UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 

 

Large Accelerated Filer (X)	FirstEnergy Corp.
Accelerated Filer (   )	N/A
Non-accelerated Filer (X)	Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company

	OUTSTANDING
CLASS	AS OF MAY 8, 2006
FirstEnergy Corp., $.10 par value	329,836,276
Ohio Edison Company, no par value	100
The Cleveland Electric Illuminating Company, no par value	79,590,689
The Toledo Edison Company, $5 par value	39,133,887
Pennsylvania Power Company, $30 par value	6,290,000
Jersey Central Power & Light Company, $10 par value	15,371,270
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	5,290,596

TABLE OF CONTENTS (Cont'd)

		Pages
Jersey Central Power & Light Company
	Consolidated Statements of Income and Comprehensive Income	116
	Consolidated Balance Sheets	117
	Consolidated Statements of Cash Flows	118
	Report of Independent Registered Public Accounting Firm	119
	Management's Discussion and Analysis of Results of Operations and	120-128
	Financial Condition
Metropolitan Edison Company
	Consolidated Statements of Income and Comprehensive Income	129
	Consolidated Balance Sheets	130
	Consolidated Statements of Cash Flows	131
	Report of Independent Registered Public Accounting Firm	132
	Management's Discussion and Analysis of Results of Operations and	133-141
	Financial Condition
Pennsylvania Electric Company
	Consolidated Statements of Income and Comprehensive Income	142
	Consolidated Balance Sheets	143
	Consolidated Statements of Cash Flows	144
	Report of Independent Registered Public Accounting Firm	145
	Management's Discussion and Analysis of Results of Operations and	146-154
	Financial Condition
Item 3.   Quantitative and Qualitative Disclosures About Market Risk		155
Item 4.   Controls and Procedures		155
Part II.   Other Information
Item 1.   Legal Proceedings		156
Item 1A.   Risk Factors		156
Item 2.   Unregistered Sales of Equity Securities and Use of Proceeds		156
Item 6.   Exhibits		156

 

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GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
Centerior	Centerior Energy Corporation, former parent of CEI and TE, which merged with OE to form FirstEnergy on November 8, 1997.
CFC	Centerior Funding Corporation, a wholly owned finance subsidiary of CEI
Companies	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstCom	First Communications, LLC, provides local and long-distance telephone service
FirstEnergy	FirstEnergy Corp., a public utility holding company
FSG	FirstEnergy Facilities Services Group, LLC, the parent company of several heating, ventilation, air conditioning and energy management companies
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MYR	MYR Group, Inc., a utility infrastructure construction service company
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
OE Companies	OE and Penn
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	Termobarranquilla S.A., Empresa de Servicios Publicos
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ALJ	Administrative Law Judge
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 25	APB Opinion 25, "Accounting for Stock Issued to Employees"
APB 29	APB Opinion No. 29, "Accounting for Nonmonetary Transactions"
ARB	Accounting Research Bulletin
ARB 43	ARB No. 43, "Restatement and Revision of Accounting Research Bulletins"
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CAIDI	Customer Average Interruption Duration Index
CAIR	Clean Air Interstate Rule
CAL	Confirmatory Action Letter
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO 2	Carbon Dioxide
CTC	Competitive Transition Charge
DOJ	United States Department of Justice
DRA	Division of the Ratepayer Advocate
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 04-13	EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty"
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005

 

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GLOSSARY OF TERMS Cont'd.

ERO	Electric Reliability Organization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FMB	First Mortgage Bonds
GAAP	Accounting Principles Generally Accepted in the United States
GCAF	Generation Charge Adjustment Factor
GHG	Greenhouse Gases
KWH	Kilowatt-hours
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MOU	Memorandum of Understanding
MTC	Market Transition Charge
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NJBPU	New Jersey Board of Public Utilities
NOAC	Northwest Ohio Aggregation Coalition
NOV	Notices of Violation
NO x	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
OCA	Office of Consumer Advocate
OCC	Office of the Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OSBA	Office of Small Business Advocate
OTS	Office of Trial Staff
PCAOB	Public Company Accounting Oversight Board
PICA	Penelec Industrial Customer Association
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RFP	Request for Proposal
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SAIFI	System Average Interruption Frequency Index
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 123	SFAS No. 123, "Accounting for Stock-Based Compensation"
SFAS 123(R)	SFAS No. 123(R), "Share-Based Payment"
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities”
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 155	SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments - an amendment of FASB   Statements No. 133 and 140"
SO 2	Sulfur Dioxide
TBC	Transition Bond Charge

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GLOSSARY OF TERMS Cont'd.

 

TMI-1	Three Mile Island Unit 1
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity

 

 

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PART I. FINANCIAL INFORMATION

FIRSTENERGY CORP. AND SUBSIDIARIES

OHIO EDISON COMPANY AND SUBSIDIARIES

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES

THE TOLEDO EDISON COMPANY AND SUBSIDIARY

PENNSYLVANIA POWER COMPANY AND SUBSIDIARY

JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES

METROPOLITAN EDISON COMPANY AND SUBSIDIARIES

PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.   - ORGANIZATION AND BASIS OF PRESENTATION

    FirstEnergy’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. FirstEnergy's consolidated financial statements also include its other principal subsidiaries: FENOC, FES and its subsidiary FGCO, NGC, FESC and FSG.

    FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, PUCO, PPUC and NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

    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, 2005 for FirstEnergy and the Companies. The consolidated unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain businesses divested in the first and second quarters of 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 4). As discussed in Note 13, interim period segment reporting in 2005 was reclassified to conform with the current year business segment organizations and operations.

    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 9) when it is determined to be the VIE's primary beneficiary. Investments in nonconsolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control, (20-50 percent owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheet and the percentage share of the entity’s earnings is reported in the Consolidated Statement of Income. Certain prior year amounts have been reclassified to conform to the current presentation.

    FirstEnergy's and the Companies' independent registered public accounting firm has performed reviews of, and issued reports on, these consolidated interim financial statements in accordance with standards established by the PCAOB. Pursuant to Rule 436(c) under the Securities Act of 1933, their reports of those reviews should not be considered a report within the meaning of Section 7 and 11 of that Act, and the independent registered public accounting firm’s liability under Section 11 does not extend to them.

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2. - EARNINGS PER SHARE

    Basic earnings per share are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share 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. Stock-based awards to purchase 0.5 million shares of common stock in the three months ended March 31, 2005 were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. No stock-based awards were excluded from the calculation in the three months ended March 31, 2006. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations:

		Three Months Ended
Reconciliation of Basic and Diluted		March 31,
Earnings per Share		2006			2005
		(In millions)
Income Before Discontinued Operations		$	221		$	141
Average Shares of Common Stock Outstanding:
Denominator for basic earnings per share
(weighted average shares outstanding)			329			328
Assumed exercise of dilutive stock options and awards			1			1
Denominator for diluted earnings per share			330			329
Income Before Discontinued Operations per common share:
Basic		$	0.67		$	0.43
Diluted		$	0.67		$	0.42

3. - GOODWILL

    FirstEnergy's goodwill primarily relates to its regulated services segment. In the three months ended March 31, 2006, FirstEnergy adjusted goodwill related to the divestiture of a non-core asset (60% interest in MYR), a successful tax claim relating to the former Centerior companies, and an adjustment to the former GPU companies due to the realization of a tax benefit that had been reserved in purchase accounting.

     A summary of the changes in goodwill for the three months ended March 31, 2006 is shown below:

		FirstEnergy			CEI			TE			JCP&L			Met-Ed			Penelec
		(In millions)
Balance as of January 1, 2006		$	6,010		$	1,689		$	501		$	1,986		$	864		$	882
Non-core assets sale			(53	)
Adjustments related to Centerior acquisition			(1	)		(1	)
Adjustments related to GPU acquisition			(16	)								(8	)		(4	)		(4	)
Balance as of March 31, 2006		$	5,940		$	1,688		$	501		$	1,978		$	860		$	878

4. - DIVESTITURES AND DISCONTINUED OPERATIONS

     In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. As a result, FirstEnergy deconsolidated MYR and began accounting for its remaining 40% interest under the equity method.

 

                  In March 2005, FES sold its retail natural gas business for an after-tax gain of $5 million and FirstEnergy sold 51% of its interest in FirstCom for an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest in FirstCom under the equity method.

                 FirstEnergy sold two FSG subsidiaries (Elliott-Lewis and Spectrum) and an MYR subsidiary (Power Piping Company) in the first quarter of 2005, resulting in aggregate after-tax gains of $12 million. The remaining FSG subsidiaries continue to be actively marketed and qualify as assets held for sale in accordance with SFAS 144. Management anticipates that the transfer of FSG assets, with a net carrying value of $49 million as of March 31, 2006, will qualify for recognition as completed sales within one year. As of March 31, 2006, the FSG subsidiaries classified as held for sale did not meet the criteria for discontinued operations. The carrying amounts of FSG's assets and liabilities held for sale are not material and have not been classified as assets held for sale on FirstEnergy's Consolidated Balance Sheets. See Note 13 for FSG's segment financial information.

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    Net income (including the gain on sales discussed above) for Elliott-Lewis, Power Piping, FES' natural gas business and Cranston (sold in the second quarter of 2005) of $19 million for the first quarter of 2005 is reported as discontinued operations on FirstEnergy's Consolidated Statements of Income. Pre-tax operating results for these entities were $4 million for the first quarter of 2005. Revenues associated with discontinued operations for the first quarter of 2005 were $195 million. The following table summarizes the sources of income from discontinued operation for the three months ended March 31, 2005:

		(In millions)
Discontinued Operations (Net of tax)
Gain on sale:
Natural gas business		$	5
FSG subsidiaries and Power Piping			12
Reclassification of operating income			2
Total		$	19

5. - DERIVATIVE INSTRUMENTS

                 FirstEnergy is exposed to financial risks resulting from the fluctuation of 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 non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company. 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 that criterion are accounted for on the accrual basis. The changes in the fair value of derivative instruments that do not meet the normal purchase and sales criteria are recorded in current earnings, in AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.

                 FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.

                 The net deferred losses of $53 million included in AOCL as of March 31, 2006, for derivative hedging activity, as compared to the December 31, 2005 balance of $78 million of net deferred losses, resulted from a $19 million decrease related to current hedging activity and a $6 million decrease due to net hedge losses included in earnings during the three months ended March 31, 2006. Approximately $11 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, 2006 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors.

                  FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During the first quarter of 2006, FirstEnergy unwound swaps with a total notional amount of $350 million for which it paid $1 million in cash. The losses will be recognized in earnings over the remaining maturity of each respective hedged security as increased interest expense. As of March 31, 2006, the aggregate notional value of interest rate swap agreements outstanding was $750 million.

                 During 2005 and the first quarter of 2006, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuances of fixed-rate, long-term debt securities for one or more of its consolidated entities during 2006 - 2008 as outstanding debt matures. 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 2006, FirstEnergy revised its financing plan related to forward swaps with an aggregate notional amount of $500 million, impacting the term and timing of the respective issuances. As required by SFAS 133, FirstEnergy de-designated the forward swaps and assessed the amount of ineffectiveness. FirstEnergy terminated the forward swaps and received cash of $16 million, of which approximately $5 million ($3 million net of tax) was deemed ineffective and recognized in earnings in the first quarter of 2006. The remaining gain deemed effective in the amount of approximately $11 million ($7 million net of tax) was recorded in other comprehensive income and will subsequently be recognized in earnings over the terms of the respective forward swaps. As of March 31, 2006, FirstEnergy had forward swaps with an aggregate notional amount of $1 billion and a fair value of $25 million.

 

 

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6. - STOCK BASED COMPENSATION

 

                  FirstEnergy has the following stock-based compensation programs: Long-term Incentive Program (LTIP); Executive Deferred Compensation Plan (EDCP); Employee Stock Ownership Plan (ESOP) and Deferred Compensation Plan for Outside Directors (DCPD), which were previously accounted for under the recognition and measurement principles of APB 25 and related interpretations. The LTIP includes four stock-based compensation programs - restricted stock, restricted stock units, stock options, and performance shares.

                 Effective January 1, 2006, FirstEnergy adopted SFAS 123(R), which requires the expensing of stock-based compensation. Under SFAS 123(R), all share-based compensation cost is measured at the grant date, based on the fair value of the award and is recognized as an expense over the employee’s requisite service period. FirstEnergy adopted the modified prospective method, under which compensation expense recognized in the first quarter of 2006 includes the expense for all share-based payments granted prior to but not yet vested as of January 1, 2006. Results for prior periods have not been restated.

                  Under APB 25, no compensation expense was reflected in net income for stock options as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value. The pro-forma effects on net income for stock options were instead disclosed in a footnote to the financial statements. Under APB 25 and SFAS 123(R) expense was recorded in the income statement for restricted stock, restricted stock units, performance shares and the EDCP and DCPD programs. No stock options have been issued subsequent to the third quarter of 2004. Consequently, the impact of adopting SFAS 123(R) was not material to FirstEnergy's net income and earnings per share in the first quarter 2006. In the year of adoption all disclosures prescribed by SFAS 123(R) are required to be included in both the quarterly Form 10-Q filings as well as the annual Form 10-K filing. However, due to the immaterial impact of the adoption of SFAS 123(R) on FirstEnergy's financial results, only condensed disclosure has been provided. For annual disclosures see FirstEnergy's 2005 Form 10-K.

                 The following table illustrates the effect on net income and earnings per share for the first quarter of 2005, as if FirstEnergy had adopted SFAS 123(R) as of January 1, 2005 (in millions):

		March 31,
		2005
Net Income, as reported		$	160
Add back compensation expense
reported in net income, net of tax (based on			8
APB 25)*
Deduct compensation expense based
upon estimated fair value, net of tax*			(11	)
Pro forma net income		$	157
Earnings Per Share of Common Stock -
Basic
As Reported		$	0.49
Pro Forma		$	0.48
Diluted
As Reported		$	0.48
Pro Forma		$	0.48

*   Includes restricted stock, restricted stock units, stock options, performance

shares, ESOP, EDCP and DCPD.

7. - ASSET RETIREMENT OBLIGATIONS

 

    FirstEnergy has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47, which was implemented on December 31, 2005. Had FIN 47 been applied in the first quarter of 2005, the impact on earnings would have been immaterial.

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    The ARO liability of $1.1 billion as of March 31, 2006 primarily related to the nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

                 FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of March 31, 2006, the fair value of the decommissioning trust assets was $1.8 billion.

     The following tables analyze changes to the ARO balance during the first quarters of 2006 and 2005, respectively.

ARO Reconciliation		FirstEnergy			OE			CEI			TE			Penn			JCP&L			Met-Ed			Penelec
		(In millions)
Balance, January 1, 2006		$	1,126		$	83		$	8		$	25		$	-		$	80		$	142		$	72
Liabilities incurred			-			-			-			-			-			-			-			-
Liabilities settled			-			-			-			-			-			-			-			-
Accretion			18			1			-			-			-			1			2			1
Revisions in estimated cash flows			4			-			-			-			-			-			-			-
Balance, March 31, 2006		$	1,148		$	84		$	8		$	25		$	-		$	81		$	144		$	73
Balance, January 1, 2005		$	1,078		$	201		$	272		$	194		$	138		$	73		$	133		$	66
Liabilities incurred			-			-			-			-			-			-			-			-
Liabilities settled			-			-			-			-			-			-			-			-
Accretion			17			3			4			3			2			2			2			1
Revisions in estimated cash flows			-			-			-			-			-			-			-			-
Balance, March 31, 2005		$	1,095		$	204		$	276		$	197		$	140		$	75		$	135		$	67

8. - PENSION AND OTHER POSTRETIREMENT BENEFITS:

                 FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. 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 other postretirement benefits to employees, their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits.

     The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2006 and 2005, consisted of the following:

								Other Postretirement
		Pension Benefits						Benefits
		2006			2005			2006			2005
					(In millions)
Service cost		$	21		$	19		$	9		$	10
Interest cost			66			64			26			28
Expected return on plan assets			(99	)		(86	)		(12	)		(11	)
Amortization of prior service cost			2			2			(19	)		(11	)
Recognized net actuarial loss			15			9			14			10
Net periodic cost		$	5		$	8		$	18		$	26

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                        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 periodic pension costs (credits) and net periodic postretirement benefit costs (including amounts capitalized) recognized by each of the Companies for the three months ended March 31, 2006 and 2005 were as follows:

		Pension Benefit Cost (Credit)						Other Postretirement Benefit Cost
		2006			2005			2006			2005
					(In millions)
OE		$	(1.1	)	$	0.2		$	3.4		$	5.8
Penn			(0.4	)		(0.2	)		0.8			1.2
CEI			1.0			0.3			2.8			3.8
TE			0.2			0.3			2.0			2.2
JCP&L			(1.4	)		(0.2	)		0.6			2.7
Met-Ed			(1.7	)		(1.1	)		0.7			0.4
Penelec			(1.3	)		(1.3	)		1.8			1.9
Other FirstEnergy    subsidiaries			9.9			9.5			6.1			8.1
		$	5.2		$	7.5		$	18.2		$	26.1

9. - VARIABLE INTEREST ENTITIES

                 FIN 46R addresses the consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R.

Leases

                 FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with the 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. 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.

    OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $666 million, $96 million and $535 million, respectively, that would not be payable if the casualty value payments are made.

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 approximately 30 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.

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    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 incurs for power. As of March 31, 2006, the net projected above-market loss liability recognized for these eight NUG agreements was $102 million. Purchased power costs from these entities during the first quarters of 2006 and 2005 are shown in the table below:

		Three Months Ended
		March 31,
		2006			2005
		(In millions)
JCP&L		$	15		$	21
Met-Ed			16			16
Penelec			8			7
		$	39		$	44

Securitized Transition Bonds

 

    The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition, a wholly owned limited liability company of JCP&L. In June 2002, JCP&L Transition 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.

    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. The transition bonds are obligations of JCP&L Transition only and are collateralized solely by the equity and assets of JCP&L Transition, which consist primarily of bondable transition property. The bondable transition property is solely the property of JCP&L Transition.

    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 the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to JCP&L Transition and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from TBC collections.

10. - COMMITMENTS, GUARANTEES AND CONTINGENCIES:

(A)   GUARANTEES AND OTHER ASSURANCES

 

                 As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31, 2006, outstanding guarantees and other assurances totaled approximately $3.3 billion -- contract guarantees ($1.8 billion), surety bonds ($0.2 billion) and LOCs ($1.3 billion).

    FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.9 billion (included in the $1.8 billion discussed above) as of March 31, 2006 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

    While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of March 31, 2006, FirstEnergy's maximum exposure under these collateral provisions was $456 million.

    Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $136 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

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    The Companies, with the exception of TE and JCP&L, each have a wholly owned subsidiary whose borrowings are secured by customer accounts receivable purchased from its respective parent company. The CEI subsidiary's borrowings are also secured by customer accounts receivable purchased from TE. Each subsidiary company has its own receivables financing arrangement and, as a separate legal entity with separate creditors, would have to satisfy its obligations to creditors before any of its remaining assets could be available to its parent company.

					Borrowing
Subsidiary Company		Parent Company			Capacity
					(In millions)
OES Capital, Incorporated			OE		$	170
Centerior Funding Corp.			CEI			200
Penn Power Funding LLC			Penn			25
Met-Ed Funding LLC			Met-Ed			80
Penelec Funding LLC			Penelec			75
					$	550

                  FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($36 million as of March 31, 2006), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

(B)   ENVIRONMENTAL MATTERS

                  Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $1.8 billion for 2006 through 2010.

                 The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

                 On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders regarding air emissions regulations and an assessment of its future risks and mitigation efforts.

Clean Air Act Compliance

                  FirstEnergy is required to meet federally approved SO ₂ regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO ₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

                 FirstEnergy believes it is complying with SO ₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO _X reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO _X reductions from FirstEnergy's facilities. The EPA's NO _X Transport Rule imposes uniform reductions of NO _X emissions (an approximate 85% reduction in utility plant NO _X emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO _X emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO _X budgets established under State Implementation Plans through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

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National Ambient Air Quality Standards

                  In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO _X and SO ₂ emissions in two phases (Phase I in 2009 for NO _x , 2010 for SO ₂ and Phase II in 2015 for both NO _X and SO ₂ ). FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO ₂ and NO _x emissions, whereas its New Jersey fossil-fired generation facilities will be subject to only a cap on NO _X emissions. According to the EPA, SO ₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO ₂ emissions in affected states to just 2.5 million tons annually. NO _x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO _X cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

Mercury Emissions

                  In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO ₂ and NO _X emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and the CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

                 The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced. Since this approach is based on output, new and non-emitting generating facilities, including renewables and nuclear, would be entitled to their proportionate share of the allowances. Consequently, FirstEnergy would be disadvantaged if these model rules were implemented because its substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

W. H. Sammis Plant

                  In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NO _X and SO ₂ emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties paid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

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Climate Change

                  In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18% through 2012. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

 

                 FirstEnergy cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO ₂ emissions could require significant capital and other expenditures. The CO ₂ emissions per kilowatt-hour of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO ₂ emitting gas-fired and nuclear generators.

Clean Water Act

 

                 Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.

                 On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility's cooling water system. FirstEnergy is conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by its facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.

Regulation of Hazardous Waste

 

                  As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

    The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2006, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $63 million (JCP&L - $47.3 million, CEI - $1.7 million, TE - $0.2 million, Met-Ed - $0.05 million and other - $13.7 million) have been accrued through March 31, 2006.

(C)   OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

                  In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.

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                  In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Division. In December, 2005, JCP&L argued its motion for summary judgment before the New Jersey Superior Court on its renewed motion to decertify the class and on remaining plaintiffs' negligence and breach of contract claims. These motions remain pending. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of March 31, 2006.

                  On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

                  FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for rehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of potential liability is available for any of these cases. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. Following the PUCO's March 7, 2006 order, that action was voluntarily dismissed by the claimants.

 

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                  In addition to the above proceedings, FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter has been filed. FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. It is uncertain whether the plaintiff will appeal. No estimate of potential liability has been undertaken in either of these matters.

                 FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Nuclear Plant Matters

                 On January 20, 2006, FENOC announced that it has entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, which expires on December 31, 2006, the United States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ will refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remains in compliance with the agreement, which FENOC fully intends to do. FENOC paid a monetary penalty of $28 million (which is not deductible for income tax purposes) which reduced First Energy's earnings by $0.09 per common share in the fourth quarter of 2005.

                 On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue discussed above. FirstEnergy accrued $2 million for a potential fine prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005. On January 23, 2006, FENOC supplemented its response to the NRC's NOV on the Davis-Besse head degradation to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.

                 On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant.

                  On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Nuclear Power Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.

                  On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of Perry on March 14, 2006, the NRC again stated that the Perry Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. Although FirstEnergy is unable to predict the impact of the ultimate disposition of this matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

 

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Other Legal Matters

                 There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse-related disclosures, which has been provided. FirstEnergy has cooperated fully with the informal inquiry and continues to do so with the formal investigation.

On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, the federal court granted a Union motion to dismiss JCP&L's appeal of the award as premature. JCP&L will file its appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly-formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

11. - REGULATORY MATTERS:

RELIABILITY INITIATIVES

 

 In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the EPACT that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

 

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    As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L’s service reliability. In 2004, the NJBPU adopted a MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L’s ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L’s Planning and Operations and Maintenance programs and practices (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the DRA to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

 In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. On December 30, 2005, the ALJ recommended that the PPUC adopt the Joint Petition for Settlement among the parties involved in the three Companies’ request to amend the distribution reliability benchmarks, thereby eliminating the need for full litigation. The ALJ’s recommendation, adopting the revised benchmarks and standards, was approved by the PPUC on February 9, 2006.

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume monitoring responsibility for the new reliability standards. The FERC issued an order on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the rule.

The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of delegation agreements with regional entities. The new FERC rule referred to above, further provides for reorganizing regional reliability organizations (regional entities) that would replace the current regional councils and for rearranging the relationship with the ERO. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. NERC also made a parallel filing with the FERC April 4, 2006 seeking approval of mandatory reliability standards. These reliability standards are based with some modifications, on the current NERC Version O reliability standards with some additional standards. On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards and thirteen additional reliability standards. These standards will become effective on June 1, 2006 and will be filed with the FERC and relevant Canadian authorities for approval. The two filings are subject to review and acceptance by the FERC.

The ERO filing was noticed on April 7, 2006 and comments and interventions were filed on May 4, 2006. There is no fixed time for the FERC to act on this filing. The reliability standards filing was noticed by FERC on April 18, 2006. In that notice FERC announced its intent to treat the proposed reliability standards as a Notice of Proposed Rulemaking (NOPR), and issue a NOPR in July 2006. Prior to that time, the FERC staff will release a preliminary assessment of the proposed reliability standards. FERC also intends to hold a technical conference on the proposed reliability standards. A comment period will be set after the Staff assessment is released and the technical conference is held. NERC has requested an effective date of January 1, 2007 for the reliability standards.

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and intends to file and obtain certification consistent with the final rule as a “regional entity” under the ERO during 2006. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

     FirstEnergy believes it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC standards. The financial impact of complying with the new standards cannot be determined at this time. However, the EPACT required that all prudent costs incurred to comply with the new reliability standards be recovered in rates.

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OHIO

   On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.

         Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from the CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised RSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.

 On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·

Maintaining the existing level of base distribution rates through December 31, 2008 for OE and TE, and April 30, 2009 for CEI;

·

Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

·

Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE and TE and as of December 31, 2010 for CEI;

·

Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE, $45 million for TE, and $85 million for CEI by accelerating the application of each respective company's accumulated cost of removal regulatory liability; and

·

Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. OE, TE, and CEI may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider).

The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to:

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	·	Recognize fuel and distribution deferrals commencing January 1, 2006;
	·	Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;
	·	Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and
	·	Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred.

 

The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 30, 2006 are approximately $66 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, the Ohio Companies filed a modification to the rider to determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments are currently scheduled for May 10, 2006.

On January 20, 2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and the Ohio Companies will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of the Ohio Companies' case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.

PENNSYLVANIA

A February 2002 Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision regarding approval of the FirstEnergy/GPU merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied Met-Ed and Penelec the rate relief initially approved in the PPUC decision. On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supplements to their tariffs that became effective in October 2003 and that reflected the CTC rates and shopping credits in effect prior to the June 2001 order.

Met-Ed’s and Penelec’s combined portion of total net merger savings during 2001 - 2004 is estimated to be approximately $51 million. A procedural schedule was established by the ALJ on January 17, 2006. The companies’ filed initial testimony on March 1, 2006. Hearings are currently scheduled for the end of October 2006 with the ALJ’s recommended decision to be issued in February 2007. The companies have requested that this proceeding be consolidated with the April 10, 2006 transition plan filing proceeding as discussed below. Met-Ed and Penelec are unable to predict the outcome of this proceeding.

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In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the Commonwealth Court, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an Application for Reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005. Oral arguments are scheduled for June 8, 2006.

As of March 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $328 million and $50 million, respectively. Penelec's $50 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds.

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. As of March 31, 2006, the PPUC had taken no action on the request and neither company had yet implemented deferral accounting for these costs. Met-Ed and Penelec sought to consolidate this proceeding (and modified their request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing they made on April 10, 2006 as described below. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed and Penelec will implement deferral accounting for these costs in the second quarter of 2006, which will include $24 million and $4 million, respectively, representing the amounts that were incurred in the first quarter of 2006 -- the deferrals of such amounts will be reflected in the second quarter of 2006.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. Under this agreement, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their contracts with NUGs and other unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. The wholesale power sales agreement with FES could automatically be extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right in 2006 to terminate the agreement at any time upon 60 days notice. On April 7, 2006, the parties to the wholesale power sales agreement entered into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the wholesale power sales agreement effective midnight December 31, 2006, because that agreement is not economically sustainable to FES.

In lieu of allowing such termination to become effective as of December 31, 2006, the parties agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales agreement to provide as follows:

1.   The termination provisions of the wholesale power sales agreement will be tolled for one year until December 31, 2007, provided that during such tolling period:

a.	FES will be permitted to terminate the wholesale power sales agreement at any time with sixty days written notice;

b.

Met-Ed and Penelec will procure through arrangements other than the wholesale power sales agreement beginning December 1, 2006 and ending December 31, 2007, approximately 33% of the amounts of capacity and energy necessary to satisfy their PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased power contracts and distributed generation) have not been obtained; and

c.	FES will not be obligated to supply additional quantities of capacity and energy in the event that a supplier of Committed Resources defaults on its supply agreement.

2.   During the tolling period FES will not act as agent for Met-Ed or Penelec in procuring the services under section 1.(b) above; and

3.   The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed and Penelec comply with the provisions of the Tolling Agreement and any applicable provision of the wholesale power sales agreement.

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In the event that FES elects not to terminate the wholesale power sales agreement effective midnight December 31, 2007, similar tolling agreements effective after December 31, 2007 are expected to be considered by FES for subsequent years if Met-Ed and Penelec procure through arrangements other than the wholesale power sales agreement approximately 64%, 83% and 95% of the additional amounts of capacity and energy necessary to satisfy their PLR obligations for 2008, 2009 and 2010, respectively, for which Committed Resources have not been obtained from the market.

The wholesale power sales agreement, as modified by the Tolling Agreement, requires Met-Ed and Penelec to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed below, or, to the extent granted, adequate to mitigate such adverse consequences.

Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million and $157 million, respectively. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a competitive bid process as the amount of supply provided under the existing FES agreement is phased out in accordance with the April 7, 2006 Tolling agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 petition for the deferral of transmission-related costs discussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also included in the filing. The filing contemplates a reduction in distribution rates for Met-Ed in the amount of $37 million annually and an increase in distribution rates for Penelec in the amount of $20 million annually. Although the companies have proposed an effective date of June 10, 2006, it is expected that the PPUC will suspend the effective date for seven months as permitted under Pennsylvania law. Hearings are expected to be scheduled for the second half of 2006 and a PPUC decision is expected early in the first quarter of 2007.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn recommended that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. The PPUC approved the Recommended Decision with additional modifications on April 20, 2006. The approved plan is designed to provide customers with PLR service for January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2006, the accumulated deferred cost balance totaled approximately $558 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval to securitize the July 31, 2003 deferred balance. On December 2, 2005, JCP&L filed a request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2003 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the financial advisor. Meetings with the NJBPU Staff and the DRA were held during March and April and additional discovery conducted. The DRA filed comments on April 6, 2006, arguing that the proposed securitization does not produce customer savings. JCP&L submitted reply comments on April 10, 2006. On February 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of cost incurred since July 31, 2003. The filing also includes a request for recovery of $49 million for above-market NUG costs incurred prior to August 1, 2003, to the extent those costs are not recoverable through securitization. On March 29, 2006, a pre-hearing conference was held with the presiding ALJ. A schedule for the proceeding was established, including a discovery period and evidentiary hearings scheduled for September 2006.

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An NJBPU Decision and Order approving a Phase II Stipulation of Settlement and resolving the Motion for Reconsideration of the Phase I Order was issued on May 31, 2005. The Phase II Settlement includes a performance standard pilot program with potential penalties of up to 0.25% of allowable equity return. The Order requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI information related to the performance pilot program) through December 2006 and updates to reliability related project expenditures until all projects are completed. The first quarterly report was submitted to NJBPU on August 16, 2005. The second quarterly report was submitted on November 22, 2005. The third quarterly report as of December 31, 2005 was submitted on March 28, 2006. As of December 31, 2005 there were no performance penalties issued by the NJBPU.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to an NJBPU order for the period June 1, 2005 through May 31, 2006.

The NJBPU decision approving the BGS procurement proposal for the period beginning June 1, 2006 was issued on October 12, 2005. JCP&L submitted a compliance filing on October 26, 2005, which was approved on November 10, 2005. The written order was dated December 8, 2005. The auction took place in February 2006. On February 9, 2006, the NJBPU approved the auction results and a written order was signed on February 23, 2006. The JCP&L tariff compliance filing was approved on March 29, 2006. New BGS rates become effective June 1, 2006.  

In a reaction to the higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the auction process and potential options for the future. On April 6, 2006, initial comments were submitted. A public meeting was held on April 21, 2006 and a legislative-type hearing was held on April 28, 2006. Final comments were due on May 4, 2006. An NJBPU decision is anticipated in June 2006.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address the issues was published in the NJ Register on December 19, 2005. The proposal would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. A public hearing was held February 7, 2006 and comments were submitted to the NJBPU. The NJBPU Staff issued a draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Comments and reply comments are due by May 22 and May 31, 2006, respectively. JCP&L is not able to predict the outcome of this proceeding at this time.

On December 21, 2005, the NJBPU initiated a generic proceeding and requested comments in order to formulate an appropriate regulatory treatment for investment tax credits related to generation assets divested by New Jersey’s four electric utility companies. Comments were filed by the utilities and by the DRA.

FERC MATTERS

    On November 1, 2004, ATSI filed with FERC a request to defer approximately $54 million of costs to be incurred from 2004 through 2007 in connection with ATSI’s Vegetation Management Enhancement Project (VMEP), which represents ATSI’s adoption of newly identified industry “best practices” for vegetation management. On March 4, 2005, the FERC approved ATSI’s request to defer the VMEP costs (approximately $29 million deferred as of March 31, 2006). On March 28, 2006 ATSI and MISO filed with FERC a request to modify ATSI’s Attachment O formula rate to include revenue requirements associated with recovery of deferred VMEP costs over a five-year period. The requested effective date to begin recovery is June 1, 2006. Various parties have filed comments responsive to the March 28, 2006 submission. The FERC has not taken any action on the filing. The estimated impact of the VMEP cost recovery is $13 million in revenues annually during the five-year recovery period of June 1, 2006 to May 31, 2011 .

On January 24, 2006, ATSI and MISO filed with FERC a request to correct ATSI’s Attachment O formula rate to reverse revenue credits associated with termination of revenue streams from transitional rates stemming from FERC’s elimination of through and out rates. Revenues formerly collected under these rates were included in, and served to reduce, ATSI’s zonal transmission rate under the Attachment O formula. Absent the requested correction, elimination of these revenue streams would not be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16, 2006, FERC approved without suspension the revenue credit correction, which became effective April 1, 2006. One party sought rehearing of the FERC's order. The FERC has not yet issued a further order. The estimated impact of the correction mechanism is approximately $40 million in revenues on an annualized basis beginning June 1, 2006.

 

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On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006.

 

On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio competitive bid process, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of an April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for further consideration on March 1, 2006.

12. - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

 

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF Issue will not have a material impact on FirstEnergy's financial results.

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SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

 

                 In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

13. - SEGMENT INFORMATION:

FirstEnergy has two reportable segments: regulated services and power supply management services. The aggregate “Other” segments do not individually meet the criteria to be considered a reportable segment. The regulated services segment's operations include the regulated sale of electricity and distribution and transmission services by its eight utility subsidiaries in Ohio, Pennsylvania and New Jersey. The power supply management services segment primarily consists of the subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in deregulated markets and operate and now own the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business. “Other” consists of telecommunications services, the recently sold MYR (a construction service company) and retail natural gas operations (see Note 4). The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable segments.”

The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition cost recovery. Assets of the regulated services segment as of March 31, 2005 included generating units that were leased or whose output had been sold to the power supply management services segment. The regulated services segment’s 2005 internal revenues represented the rental revenues for the generating unit leases which ceased in the fourth quarter of 2005 as a result of the intra-system generation asset transfers (see Note 14).

The power supply management services segment supplies all of the electric power needs of FirstEnergy’s end-use customers through retail and wholesale arrangements, including regulated retail sales to meet the PLR requirements of FirstEnergy's Ohio and Pennsylvania companies and competitive retail sales to commercial and industrial businesses primarily in Ohio, Pennsylvania and Michigan. This business segment owns and operates FirstEnergy's generating facilities and purchases electricity from the wholesale market when needed to meet sales obligations. The segment's net income is primarily derived from all electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission, congestion and ancillary costs charged by PJM and MISO to deliver energy to retail customers.

Segment reporting for interim periods in 2005 was reclassified to conform to the current year business segment organization and operations and the reclassification of discontinued operations (see Note 4). Changes in the current year operations reporting reflected in reclassifications of 2005 segment reporting primarily includes the transfer of the net results of retail transmission revenues and PJM/MISO transmission revenues and expenses associated with serving electricity load previously included in the regulated services segment to the power supply management services segment. In addition, as a result of the 2005 Ohio tax legislation reducing the effective state income tax rate, the calculated composite income tax rate used in the two reportable segments results for 2005 and 2006 has been changed to 40% from the 41% previously reported in their 2005 segment results. The net amount of the changes in the 2005 reportable segments' income taxes reclassifications has been correspondingly offset in the 2005 "Reconciling Adjustments." FSG is being disclosed as a reporting segment due to its subsidiaries qualifying as held for sale. Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Adjustments."

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Segment Financial Information					Power
					Supply
		Regulated			Management			Facilities						Reconciling
Three Months Ended		Services			Services			Services			Other			Adjustments			Consolidated
		(In millions)
March 31, 2006
External revenues		$	1,083		$	1,619		$	46		$	120		$	(23	)	$	2,845
Internal revenues			-			-			-			-			-			-
Total revenues			1,083			1,619			46			120			(23	)		2,845
Depreciation and amortization			259			46			-			1			5			311
Investment Income			62			15			-			-			(34	)		43
Net interest charges			93			49			-			1			17			160
Income taxes			144			27			-			(7	)		(30	)		134
Net income			211			40			(1	)		15			(44	)		221
Total assets			23,848			6,759			63			304			823			31,797
Total goodwill			5,916			24			-			-			-			5,940
Property additions			195			244			-			1			7			447
March 31, 2005
External revenues		$	1,216		$	1,377		$	43		$	112		$	2		$	2,750
Internal revenues			78			-			-			-			(78	)		-
Total revenues			1,294			1,377			43			112			(76	)		2,750
Depreciation and amortization			374			13			-			1			6			394
Investment income			41			-			-			-			-			41
Net interest charges			98			10			-			1			62			171
Income taxes			157			(30	)		(3	)		10			(13	)		121
Income before discontinued operations			236			(46	)		(2	)		5			(52	)		141
Discontinued operations			-			-			13			6			-			19
Net income			236			(46	)		11			11			(52	)		160
Total assets			28,540			1,582			83			495			561			31,261
Total goodwill			5,947			24			-			63			-			6,034
Property additions			141			81			1			2			4			229

 

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, fuel marketing revenues (which are reflected as reductions to expenses for internal management reporting purposes) and elimination of intersegment transactions.

14. - FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, the Ohio Companies and Penn completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.  

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15. - JCP&L RESTATEMENT

                 JCP&L's earnings for the three months ended March 31, 2005 have been restated to reflect the results of a tax audit by the State of New Jersey, in which JCP&L became aware that the New Jersey Transitional Energy Facilities Assessment (TEFA) is not an allowable deduction for state income tax purposes. JCP&L had incorrectly claimed a state income tax deduction for TEFA payments and as a result, income taxes and interest expense were understated by $0.5 million and $0.6 million, respectively, in the first quarter of 2005. The effects of these adjustments on JCP&L's Consolidated Statements of Income for the three months ended March 31, 2005 are as follows:

		As Previously			As
		Reported			Restated
		(In millions)
Operating Revenues		$	529.1		$	529.1
Operating Expenses and
Taxes			494.7			495.2
Operating Income			34.4			33.9
Net Interest Charges			19.9			20.5
Net Income		$	14.5		$	13.4
Earnings Applicable
to Common Stock		$	14.4		$	13.3

These adjustments were not material to FirstEnergy's consolidated financial statements, nor JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash Flows.

 

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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
		(In millions, except per share amounts)
REVENUES:
Electric utilities		$	2,340		$	2,267
Unregulated businesses			505			483
Total revenues			2,845			2,750
EXPENSES:
Fuel and purchased power			976			895
Other operating expenses			893			884
Provision for depreciation			148			143
Amortization of regulatory assets			222			311
Deferral of new regulatory assets			(59	)		(60	)
General taxes			193			185
Total expenses			2,373			2,358
OPERATING INCOME			472			392
OTHER INCOME (EXPENSE)
Investment income			43			41
Interest expense			(165	)		(164	)
Capitalized interest			7			-
Subsidiaries’ preferred stock dividends			(2	)		(7	)
Total other income (expense)			(117	)		(130	)
INCOME TAXES			134			121
INCOME BEFORE DISCONTINUED OPERATIONS			221			141
Discontinued operations (net of income tax benefit of $8 million)
(Note 4)			-			19
NET INCOME		$	221		$	160
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations		$	0.67		$	0.43
Discontinued operations (Note 4)			-			0.06
Net income		$	0.67		$	0.49
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING			329			328
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Income before discontinued operations		$	0.67		$	0.42
Discontinued operations (Note 4)			-			0.06
Net income		$	0.67		$	0.48
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING			330			329
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK		$	0.45		$	0.4125
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part
of these statements.

 

 

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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006						2005
		(In millions)
NET INCOME		$	221					$	160
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain on derivative hedges			43						7
Unrealized gain (loss) on available for sale securities			36						(8	)
Other comprehensive income (loss)			79						(1	)
Income tax expense related to other comprehensive income			32						-
Other comprehensive income (loss), net of tax			47						(1	)
COMPREHENSIVE INCOME		$	268					$	159
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.

 

 

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FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,			December 31,
		2006			2005
		(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	28		$	64
Receivables -
Customers (less accumulated provisions of $37 million and
$38 million, respectively, for uncollectible accounts)			1,072			1,293
Other (less accumulated provisions of $27 million
for uncollectible accounts in both periods)			154			205
Materials and supplies, at average cost			610			518
Prepayments and other			235			237
			2,099			2,317
PROPERTY, PLANT AND EQUIPMENT:
In service			23,071			22,893
Less - Accumulated provision for depreciation			9,859			9,792
			13,212			13,101
Construction work in progress			1,073			897
			14,285			13,998
INVESTMENTS:
Nuclear plant decommissioning trusts			1,818			1,752
Investments in lease obligation bonds			845			890
Other			805			765
			3,468			3,407
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			5,940			6,010
Regulatory assets			4,396			4,486
Prepaid pension costs			1,018			1,023
Other			591			600
			11,945			12,119
		$	31,797		$	31,841
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	2,115		$	2,043
Short-term borrowings			931			731
Accounts payable			612			727
Accrued taxes			803			800
Other			989			1,152
			5,450			5,453
CAPITALIZATION:
Common stockholders’ equity -
Common stock, $.10 par value, authorized 375,000,000 shares -
329,836,276 shares outstanding			33			33
Other paid-in capital			7,050			7,043
Accumulated other comprehensive income (loss)			27			(20	)
Retained earnings			2,232			2,159
Unallocated employee stock ownership plan common stock -
1,167,865 and 1,444,796 shares, respectively			(22	)		(27	)
Total common stockholders' equity			9,320			9,188
Preferred stock of consolidated subsidiaries			154			184
Long-term debt and other long-term obligations			8,004			8,155
			17,478			17,527
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			2,759			2,726
Asset retirement obligations			1,148			1,126
Power purchase contract loss liability			1,184			1,226
Retirement benefits			1,334			1,316
Lease market valuation liability			830			851
Other			1,614			1,616
			8,869			8,861
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
		$	31,797		$	31,841
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these balance sheets.

 

 

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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
		(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	221		$	160
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation			148			143
Amortization of regulatory assets			222			311
Deferral of new regulatory assets			(59	)		(60	)
Nuclear fuel and lease amortization			20			19
Deferred purchased power and other costs			(125	)		(118	)
Deferred income taxes and investment tax credits, net			6			(14	)
Deferred rents and lease market valuation liability			(38	)		(36	)
Accrued compensation and retirement benefits			(19	)		(26	)
Commodity derivative transactions, net			26			4
Income from discontinued operations			-			(19	)
Cash collateral			(106	)		2
Decrease (Increase) in operating assets -
Receivables			226			91
Materials and supplies			(52	)		7
Prepayments and other current assets			(15	)		(106	)
Increase (Decrease) in operating liabilities -
Accounts payable			(114	)		61
Accrued taxes			8			41
Accrued interest			100			108
Electric service prepayment programs			(14	)		(5	)
Other			(33	)		35
Net cash provided from operating activities			402			598
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Short-term borrowings, net			200			140
Redemptions and Repayments -
Preferred stock			(30	)		(98	)
Long-term debt			(64	)		(236	)
Net controlled disbursement activity			(8	)		(30	)
Common stock dividend payments			(148	)		(135	)
Net cash used for financing activities			(50	)		(359	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(447	)		(229	)
Proceeds from asset sales			57			54
Proceeds from nuclear decommissioning trust fund sales			481			366
Investments in nuclear decommissioning trust funds			(484	)		(391	)
Cash investments			25			27
Other			(20	)		(38	)
Net cash used for investing activities			(388	)		(211	)
Net increase (decrease) in cash and cash equivalents			(36	)		28
Cash and cash equivalents at beginning of period			64			53
Cash and cash equivalents at end of period		$	28		$	81
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

 

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of March 31, 2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(K) and Note 12 to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated February 27, 2006, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2006

 

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FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

EXECUTIVE SUMMARY

Net income in the first quarter of 2006 was $221 million, or basic and diluted earnings of $0.67 per share of common stock, compared with net income of $160 million, or basic earnings of $0.49 per share of common stock ($0.48 diluted) for the first quarter of 2005. Total revenues for the first quarter of 2006 were $2.84 billion, up from $2.75 billion as adjusted to reflect certain businesses divested in the first quarter of 2005. Certain businesses divested in the first quarter of 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 4). FirstEnergy’s earnings increase was driven primarily by increased electric sales revenues, reduced financing costs and reduced transition cost amortization for FirstEnergy's Ohio Companies.

    Total electric generation KWH sales were up by 2.1 percent over the prior-year quarter, mostly due to the return of customers to the Ohio Companies from third-party suppliers leaving the Ohio marketplace. Electric distribution deliveries were down 2.6 percent during the same time period, reflecting milder weather conditions in 2006.

    FirstEnergy's generating fleet produced a record 20.1 billion KWH during the first quarter of 2006 compared to 18.8 billion KWH in the first quarter of 2005. FirstEnergy's non-nuclear fleet produced a record 13.4 billion KWH, while its nuclear facilities produced 6.7 billion KWH.

 

    Ohio CBP - On February 23, 2006, the CBP auction manager, National Economic Research Associates, notified the PUCO that the CBP to potentially provide firm generation service for the Ohio Companies’ 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 16, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO’s rules for the CBP.

    On May 3, 2006, the Supreme Court of Ohio, in a ruling on certain appeals filed by the OCC and NOAC, issued an opinion affirming PUCO's June 2004 order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts and approval of FirstEnergy's financial separation plan. It remanded the approval of the rate stabilization plan pricing back to the PUCO for further consideration of the issue as to whether the rate stabilization plan, as adopted by the PUCO, provided for sufficient customer participation.

    Wind Power Generation - In March 2006, FirstEnergy entered into multi-year agreements to purchase a combined 330 MW of wind power output from three wind power generation projects. Two of the projects are being developed in West Virginia, and the third is being developed in central Pennsylvania. The projects are anticipated to be complete and operational in 2007. When combined with prior contracts, these new contracts will bring the total wind power generation output available to FirstEnergy to 360 MW.

    Pennsylvania Rate Matters - On April 10, 2006, FirstEnergy's subsidiaries, Met-Ed and Penelec, filed with the PPUC a comprehensive transition rate plan. The filing addresses transmission, distribution and power supply issues while ensuring that customers continue to pay below-market prices for generation through 2010.

    Met-Ed requested an overall revenue increase of $216 million, or 19 percent, for 2007 if its preferred approach of implementing accounting deferrals in its filing is approved. Under an alternative proposed approach, the 2007 increase could be up to $269 million, or 24 percent. Met-Ed also has proposed changes in its generation rates for the years 2008, 2009 and 2010 that could increase revenues by up to $165 million per year.

    Penelec requested an overall revenue increase of $157 million, or 15 percent, for 2007 if its preferred approach of implementing accounting deferrals in its filing is approved. Under an alternative proposed approach that assumes accounting deferrals are not approved and instead adjusts rates to provide for appropriate cost recovery, the 2007 increase could be up to $206 million, or 19 percent. Penelec also has proposed changes in its generation rates for 2008, 2009 and 2010 that could increase revenues by up to $135 million per year.

    Statutory generation rate caps imposed by Pennsylvania’s 1996 Electricity Generation Choice and Competition Act expired as of year-end 2005. While Met-Ed's and Penelec's 1998 restructuring plans implemented under that act contain additional price caps for generation through 2010, Met-Ed and Penelec also incorrectly anticipated that by mid-2003 they would only serve 20 percent of their PLR customers’ generation needs. However, Met-Ed and Penelec continue to serve virtually all of their PLR customers at these capped rates that have been and continue to be, well below market prices.

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    The transmission portion of each transition rate plan filed with the PPUC represents nearly one-half of the overall requested increase and reflects the pass-through of federally mandated charges for transmission services from PJM. Without regulatory relief, the charges Met-Ed and Penelec expect to pay in 2006 will exceed what they expect to collect from customers by an estimated $186 million (Met-Ed - $131 million; Penelec - $55 million).

    With respect to the generation portion of customers' bills, the plan includes a four-year transition toward market-based generation rates. During this time, customers would continue paying below-market prices for power. Under the transition plan, the market-priced portion of the generation supply that Met-Ed and Penelec procure for customers would gradually increase through 2010.

    The transition plan also proposes to defer, for future recovery, costs that Met-Ed and Penelec are required to incur under federal law for power purchased from NUGs for which there is currently inadequate recovery. The amount of these costs - above what Met-Ed and Penelec currently collect from customers - is expected to total approximately $92 million in 2006. However, the deferral would begin with costs incurred after new rates become effective.

    Met-Ed and Penelec had filed on January 12, 2005 with the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. As of March 31, 2006, the PPUC had taken no action on the request and neither company had yet implemented deferral accounting for these costs. Met-Ed and Penelec sought to consolidate this proceeding (and modified their request to provide deferral of 2006 transmission-related costs only) with the April 10, 2006 comprehensive rate filing. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed and Penelec will implement deferral accounting for these costs in the second quarter of 2006, which will include $24 million and $4 million, respectively, representing the amounts were incurred in the first quarter of 2006 -- the deferrals of such amounts will be reflected in the second quarter of 2006.

Nuclear Outages - Beaver Valley Unit 1 returned to service on April 19, 2006, restarting 11 days ahead of schedule from a refueling and maintenance outage. The unit was the first plant in the world to have a temporary opening cut in its containment building and have its steam generators and reactor head replaced within a 65-day time frame. The Beaver Valley Project also included replacing the turbine rotor, rewinding the main generator, and replacing approximately one-third of the fuel assemblies.

Davis-Besse returned to service on April 27, 2006 from an outage to refuel the plant and to modify it to generate more electricity. Work performed during the outage, which began on March 6, 2006, included refurbishing the plant's turbine and rebuilding two of the four reactor coolant pumps. Generating capacity is expected to increase by approximately 11 MW to a gross output of about 946 MW.

Penn RFP - On April 20, 2006 the PPUC approved Penn's PLR supply plan with modifications. The approved plan encourages wholesale electric suppliers to participate in an RFP process to provide customers with generation service from January 1, 2007, through May 13, 2008. Penn's PLR rates are currently capped at prices determined through restructuring agreements that are set to expire at the end of 2006. The PPUC is obligated to approve a PLR plan with rates that reflect prevailing market prices and that allow Penn to recover all reasonable costs for service.

FIRSTENERGY’S BUSINESS

 

FirstEnergy is a public utility holding company headquartered in Akron, Ohio that operates primarily through two core business segments (see Results of Operations).

·   Regulated Services transmits and distributes electricity through FirstEnergy's eight utility operating companies that collectively comprise the nation’s fifth largest investor-owned electric system, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. This business segment derives its revenue principally from the delivery of electricity generated or purchased by the Power Supply Management Services segment in the states in which the utility subsidiaries operate.

·   Power Supply Management   Services supplies all of the electric power needs of end-use customers through retail and wholesale arrangements, including regulated retail sales to meet the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to commercial and industrial businesses primarily in Ohio, Pennsylvania and Michigan. This business segment owns and operates FirstEnergy's generating facilities and purchases electricity from the wholesale market to meet sales obligations. The segment's net income is primarily derived from electric generation sales revenues less the related costs of electricity generation, including purchased power, and net transmission, congestion and ancillary costs charged by PJM and MISO to deliver energy to retail customers.

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Other operating segments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, electrical and facility control systems, high-efficiency electrotechnologies and telecommunication services. FirstEnergy is in the process of divesting its remaining non-core businesses (see Note 4). The assets and revenues for the other business operations are below the quantifiable threshold for separate disclosure as “reportable operating segments”.

FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

 

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred do not include leasehold interests of CEI, TE and OE in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, the Ohio Companies and Penn completed the intra-system transfer of their respective ownership in the nuclear generation assets to NGC through, in the case of OE and Penn, an asset spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants. The transfers were intercompany transactions and, therefore, had no impact on our consolidated results.

RESULTS OF OPERATIONS

    The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 13 to the consolidated financial statements. The FSG business segment is included in “Other and Reconciling Adjustments” in this discussion due to its immaterial impact on current period financial results, but is presented separately in segment information provided in Note 13 to the consolidated financial statements. Net income (loss) by major business segment was as follows:

		Three Months Ended
		March 31,						Increase
		2006			2005			(Decrease)
Net Income (Loss)		(In millions, except per share data)
By Business Segment
Regulated services		$	211		$	236		$	(25	)
Power supply management services			40			(46	)		86
Other and reconciling adjustments*			(30	)		(30	)		-
Total		$	221		$	160		$	61
Basic Earnings Per Share:
Income before discontinued operations		$	0.67		$	0.43		$	0.24
Discontinued operations			-			0.06			(0.06	)
Net Income		$	0.67		$	0.49		$	0.18
Diluted Earnings Per Share:
Income before discontinued operations		$	0.67		$	0.42		$	0.25
Discontinued operations			-			0.06			(0.06	)
Net Income		$	0.67		$	0.48		$	0.19

*

Represents other operating segments and reconciling items including interest expense on holding company debt and corporate support services revenues and expenses.

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     Net income in the first quarter of 2005 included after-tax earnings from discontinued operations of $19 million ($0.06 per basic and diluted share) resulting from FirstEnergy’s disposition of non-core assets and operations. In the first quarter of 2005, discontinued operations included $17 million from net gains on sales and $2 million from operations.

     In the first quarter of 2005, earnings were increased by $0.02 per share from the combined impact of $0.07 per share of gains from the sale of non-core assets, offset by $0.04 per share of expense associated with the W. H. Sammis Plant New Source Review settlement and $0.01 per share of expense related to the fine by the Nuclear Regulatory Commission regarding the Davis-Besse Nuclear Power Station.

     Financial results for FirstEnergy's major business segments in the first quarter of 2006 and 2005 were as follows:

					Power
					Supply			Other and
		Regulated			Management			Reconciling			FirstEnergy
First Quarter 2006 Financial Results		Services			Services			Adjustments			Consolidated
		(In millions)
Revenues:
External
Electric		$	935		$	1,576		$	-		$	2,511
Other			148			43			143			334
Internal			-			-			-			-
Total Revenues			1,083			1,619			143			2,845
Expenses:
Fuel and purchased power			-			976			-			976
Other operating expenses			298			451			144			893
Provision for depreciation			96			46			6			148
Amortization of regulatory assets			222			-			-			222
Deferral of new regulatory assets			(59	)		-			-			(59	)
General taxes			140			45			8			193
Total Expenses			697			1,518			158			2,373
Operating Income (Loss)			386			101			(15	)		472
Other Income (Expense):
Investment income			62			15			(34	)		43
Interest expense			(94	)		(53	)		(18	)		(165	)
Capitalized interest			3			4			-			7
Subsidiaries' preferred stock dividends			(2	)		-			-			(2	)
Total Other Income (Expense)			(31	)		(34	)		(52	)		(117	)
Income taxes (benefit)			144			27			(37	)		134
Income before discontinued operations			211			40			(30	)		221
Discontinued operations			-			-			-			-
Net Income (Loss)		$	211		$	40		$	(30	)	$	221

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					Power
					Supply			Other and
		Regulated			Management			Reconciling			FirstEnergy
First Quarter 2005 Financial Results		Services			Services			Adjustments			Consolidated
		(In millions)
Revenues:
External
Electric		$	1,082		$	1,355		$	-		$	2,437
Other			134			22			157			313
Internal			78			-			(78	)		-
Total Revenues			1,294			1,377			79			2,750
Expenses:
Fuel and purchased power			-			895			-			895
Other operating expenses			324			503			57			884
Provision for depreciation			123			13			7			143
Amortization of regulatory assets			311			-			-			311
Deferral of new regulatory assets			(60	)		-			-			(60	)
General taxes			146			32			7			185
Total Expenses			844			1,443			71			2,358
Operating Income (Loss)			450			(66	)		8			392
Other Income (Expense):
Investment income			41			-			-			41
Interest expense			(94	)		(7	)		(63	)		(164	)
Capitalized interest			3			(3	)		-			-
Subsidiaries' preferred stock dividends			(7	)		-			-			(7	)
Total Other Income (Expense)			(57	)		(10	)		(63	)		(130	)
Income taxes (benefit)			157			(30	)		(6	)		121
Income before discontinued operations			236			(46	)		(49	)		141
Discontinued operations			-			-			19			19
Net Income (Loss)		$	236		$	(46	)	$	(30	)	$	160

					Power
Change Between First Quarter 2006 and					Supply			Other and
First Quarter 2005 Financial Results		Regulated			Management			Reconciling			FirstEnergy
Increase (Decrease)		Services			Services			Adjustments			Consolidated
		(In millions)
Revenues:
External
Electric		$	(147	)	$	221		$	-		$	74
Other			14			21			(14	)		21
Internal			(78	)		-			78			-
Total Revenues			(211	)		242			64			95
Expenses:
Fuel and purchased power			-			81			-			81
Other operating expenses			(26	)		(52	)		87			9
Provision for depreciation			(27	)		33			(1	)		5
Amortization of regulatory assets			(89	)		-			-			(89	)
Deferral of new regulatory assets			1			-			-			1
General taxes			(6	)		13			1			8
Total Expenses			(147	)		75			87			15
Operating Income			(64	)		167			(23	)		80
Other Income (Expense):
Investment income			21			15			(34	)		2
Interest expense			-			(46	)		45			(1	)
Capitalized interest			-			7			-			7
Subsidiaries' preferred stock dividends			5			-			-			5
Total Other Income (Expense)			26			(24	)		11			13
Income taxes			(13	)		57			(31	)		13
Income before discontinued operations			(25	)		86			19			80
Discontinued operations			-			-			(19	)		(19	)
Net Income		$	(25	)	$	86		$	-		$	61

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Regulated Services - First Quarter 2006 Compared to First Quarter 2005

 

     Net income decreased $25 million (or 10.6%) to $211 million in the first quarter of 2006 compared to $236 million in the first quarter of 2005, primarily due to decreased operating revenues partially offset by lower operating expenses and taxes.

Revenues -

     The decrease in total revenues resulted from the following sources:

		Three Months Ended
		March 31,						Increase
Revenues By Type of Service		2006			2005			(Decrease)
		(In millions)
Distribution services		$	935		$	1,082		$	(147	)
Transmission services			94			92			2
Internal revenues			-			78			(78	)
Other			54			42			12
Total Revenues		$	1,083		$	1,294		$	(211	)

     Decreases in distribution deliveries by customer class are summarized in the following table:

Electric Distribution Deliveries
Residential			(2.6	)%
Commercial			(2.1	)%
Industrial			(2.9	)%
Total Distribution Deliveries			(2.6	)%

 

    The completion of the Ohio Companies' generation transition cost recovery under their respective transition plans and Penn's transition plan in 2005 was the primary reason for lower distribution unit prices, which, in conjunction with lower KWH deliveries, resulted in lower distribution delivery revenues. The decreased deliveries to customers were primarily due to unseasonably mild weather during the first quarter of 2006. The following table summarizes major factors contributing to the $147 million decrease in distribution service revenues in the first quarter of 2006:

Sources of Change in Distribution Revenues		Decrease
		(In millions)
Changes in customer usage		$	(5	)
Changes in prices:
Rate changes			(124	)
Rate mix & other			(18	)
Net Decrease in Distribution Revenues		$	(147	)

 

    The decrease in internal revenues reflected the effect of the generation asset transfers discussed above. The 2005 generation assets lease revenue from affiliates ceased as a result of the transfers. Other revenues increased $14 million due in part to higher payments received under a contract provision associated with the prior sale of TMI. Under the contract, additional payments are received if subsequent energy prices rise above specified levels. These payments are passed along to JCP&L, Met-Ed and Penelec customers, resulting in no net earnings effect. Other revenues were also impacted by an increase in customer late payment charges.

Expenses-

     The decrease in revenues discussed above was partially offset by the following decreases in total expenses:

·

Other operating expenses were $26 million lower in 2006 due in part to the following factors:

 

                                        1)    The absence in 2006 of expenses for ancillary service refunds to third party suppliers of $7 million in 2005 due to the RCP, which provides that alternate

                     suppliers of ancillary services now bill customers directly for those services;

2)

The absence in 2006 of receivables factoring discount expenses of approximately $5 million incurred in 2005; and

3)     A $4 million decrease in employee and contractor costs.

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·

Lower depreciation expense of $27 million that resulted from the impact of the generation asset transfers.

·

Reduced amortization of regulatory assets of $89 million principally due to the completion of Ohio generation transition cost recovery and Penn's transition plan in 2005; and

·

General taxes decreased by $6 million primarily due to lower property taxes as a result of the generation asset transfers.

Other Income -

·

Higher investment income reflects the impact of the generation asset transfers. Interest income on the affiliated company notes receivable from the power supply management services segment in the first quarter of 2006 is partially offset by the absence in 2006 of the majority of nuclear decommissioning trust income which is now included in the power supply management services segment; and

·

Subsidiaries' preferred stock dividends decreased by $5 million in 2006 due to redemption activity in 2005.

Power Supply Management Services - First Quarter 2006 Compared to First Quarter 2005

 

     Net income for this segment was $40 million in the first quarter of 2006 compared to a net loss of $46 million in the same period last year. An improvement in the gross generation margin was partially offset by higher depreciation, general taxes and interest expense resulting from the generation asset transfers.

Revenues -

 

Electric generation sales revenues increased $199 million in the first quarter of 2006 compared to the same period in 2005. This increase primarily resulted from a 6.6% increase in retail KWH sales and higher unit prices resulting from the 2006 rate stabilization and fuel recovery charges. Additional retail sales reduced energy available for sales to the wholesale market. The transmission revenues increase reflected new revenues under the MISO transmission rider of approximately $27 million that began in the first quarter of 2006.

     An increase in reported segment revenues resulted from the following sources:

		Three Months Ended
		March 31,						Increase
Revenues By Type of Service		2006			2005			(Decrease)
		(In millions)
Electric Generation Sales:
Retail		$	1,239		$	980		$	259
Wholesale			235			295			(60	)
Total Electric Generation Sales			1,474			1,275			199
Retail Transmission Rider			116			80			36
Other Transmission			12			10			2
Other			17			12			5
Total Revenues		$	1,619		$	1,377		$	242

     The following table summarizes the price and volume factors contributing to changes in sales revenues from retail and wholesale customers:

		Increase
Source of Change in Electric Generation Sales		(Decrease)
		(In millions)
Retail:
Effect of 6.6% increase in customer usage		$	65
Change in prices			194
			259
Wholesale:
Effect of 15.7% decrease in KWH sales			(46	)
Change in prices			(14	)
			(60	)
Net Increase in Electric Generation Sales		$	199

 

 

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Expenses -

     Total operating expenses increased by $75 million. The increase was due to the following factors:

·

Higher fuel and purchased power costs of $81 million, including increased fuel costs of $49 million, of which, coal costs, contributed $41 million as a result of increased generation output and higher coal prices reflecting higher transportation costs. The increase in coal transportation costs is primarily due to a change in the fuel mix resulting from a greater use of western coal. Purchased power costs, net of the Ohio RCP fuel deferral of $21 million, increased $32 million due to higher prices partially offset by lower volume. Factors contributing to the higher costs are summarized in the following table:

		Increase
Source of Change in Fuel and Purchased Power		(Decrease)
		(In millions)
Fuel:
Change due to increased unit costs		$	32
Change due to volume consumed			17
			49
Purchased Power:
Change due to increased unit costs			77
Change due to volume purchased			(33	)
Decrease in NUG costs deferred			9
			53
Ohio RCP fuel deferrals			(21	)
Net Increase in Fuel and Purchased Power Costs		$	81

·

Higher transmission expenses of $30 million related to the transmission revenues discussed above;

·

Increased depreciation expenses of $33 million, which resulted principally from the generation asset transfers; and

·

Higher general taxes of $13 million due to additional property taxes resulting from the generation asset transfers.

Offsetting these higher costs were lower non-fuel operating expenses of $52 million, which reflect the absence in 2006 of generating asset lease rents of $78 million charged in 2005 due to the generation asset transfers. Also absent in 2006 were: (1) the 2005 accrual of an $8.5 million civil penalty payable to the DOJ and $10 million for obligations to fund environmentally beneficial projects in connection with the Sammis Plant settlement; and (2) a $3.5 million penalty related to the Davis-Besse outage.

Other Income -

 

	·	Investment income in the first quarter of 2006 was higher by $15 million over the prior year period primarily due to nuclear decommissioning trust investments   acquired through the generation asset transfers; and
	·	Interest expense increased by $46 million, primarily due to the interest expense in 2006 on associated company notes payable used in connection with the generation asset transfers. This increase was partially offset by an additional $7 million of capitalized interest.

 

Income Taxes - Income taxes increased as a result of higher taxable income.

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Other - First Quarter 2006 Compared to First Quarter 2005

    FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in no change to FirstEnergy’s net income in the first quarter of 2006 compared to the same quarter of 2005. The effect of lower income taxes due to allocations among the business segments offset the effect of the absence of the results of the 2005 discontinued operations. The 2005 results reflected the effect of discontinued operations, which included an after-tax net gain of $17 million from discontinued operations (see Note 4). The following table summarizes the sources of income from discontinued operations for the three months ended March 31, 2005:

		(In millions)
Discontinued Operations (Net of tax)
Gain on sale:
Natural gas business		$	5
Elliot-Lewis, Spectrum and Power Piping			12
Reclassification of operating income			2
Total		$	19

CAPITAL RESOURCES AND LIQUIDITY

During 2006 and thereafter, FirstEnergy expects to meet its contractual obligations primarily with a combination of cash from operations and funds from the capital markets. Borrowing capacity under credit facilities is available to manage working capital requirements.

Changes in Cash Position

FirstEnergy's primary source of cash required for continuing operations as a holding company is cash from the operations of its subsidiaries. FirstEnergy also has access to $2.0 billion of short-term financing under a revolving credit facility which expires in 2010, subject to short-term debt limitations under current regulatory approvals of $1.5 billion and to outstanding borrowings by subsidiaries of FirstEnergy that are also parties to such facility. In the first quarter of 2006, FirstEnergy received $148 million of cash dividends from its subsidiaries and paid $148 million in cash dividends to common shareholders. There are no material restrictions on the payment of cash dividends by FirstEnergy's subsidiaries.

As of March 31, 2006, FirstEnergy had $28 million of cash and cash equivalents compared with $64 million as of December 31, 2005. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

 

    FirstEnergy's consolidated net cash from operating activities is provided primarily by its regulated services and power supply management services businesses (see Results of Operations above). Net cash provided from operating activities was $402 million in the first quarter of 2006 and $598 million in the first quarter of 2005, summarized as follows:

		Three Months Ended
		March 31,
Operating Cash Flows		2006			2005
		(In millions)
Cash earnings (1)		$	388		$	359
Working capital and other			14			239
Net cash provided from operating activities		$	402		$	598

 

⁽¹⁾    Cash earnings is a Non-GAAP measure (see reconciliation below).

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    Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. FirstEnergy believes that cash earnings are a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income.

		Three Months Ended
		March 31,
Reconciliation of Cash Earnings		2006			2005
		(In millions)
Net Income (GAAP)		$	221		$	160
Non-Cash Charges (Credits):
Provision for depreciation			148			143
Amortization of regulatory assets			222			311
Deferral of new regulatory assets			(59	)		(60	)
Nuclear fuel and lease amortization			20			19
Deferred purchased power and other costs			(125	)		(118	)
Deferred income taxes and investment tax credits			6			(14	)
Deferred rents and lease market valuation liability			(38	)		(36	)
Accrued compensation and retirement benefits			(19	)		(26	)
Income from discontinued operations			-			(19	)
Other non-cash expenses			12			(1	)
Cash Earnings (Non-GAAP)		$	388		$	359

 

    Net cash provided from operating activities decreased by $196 million in the first quarter of 2006 compared to the first quarter of 2005 primarily due to a $225 million decrease in working capital, partially offset by a $29 million increase in cash earnings described under "Results of Operations." The working capital decrease primarily resulted from increased outflows of $175 million for payables and $59 million for materials and supplies which reflected increased generation costs as discussed above and fuel inventory replacement activity due to increased fossil fuel consumption and higher unit prices; and $108 million of cash collateral returned to suppliers. These decreases were partially offset by an increase in cash provided from the settlement of receivables balances of $135 million which reflects increased electric sales revenues.

Cash Flows From Financing Activities

 

    In the first quarters of 2006 and 2005, net cash used for financing activities was $50 million and $359 million, respectively, primarily resulting from the redemptions of debt and preferred stock as shown below.

		Three Months Ended
		March 31,
Securities Issued or Redeemed		2006			2005
		(In millions)
Redemptions
FMB		$	-		$	1
Pollution control notes			54			-
Senior secured notes			10			20
Long-term revolving credit			-			215
Preferred stock			30			98
		$	94		$	334
Short-term Borrowings, Net		$	200		$	140

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    FirstEnergy had approximately $931 million of short-term indebtedness as of March 31, 2006 compared to approximately $731 million as of December 31, 2005. This increase was due primarily to increased capital spending including the costs associated with the Davis-Besse and Beaver Valley Unit 1 refueling outages during the first quarter of 2006 and lower customer cash receipts. Available bank borrowing capability as of March 31, 2006 included the following:

Borrowing Capability
		(In millions)
Short-term credit facilities (1)		$	2,120
Accounts receivable financing facilities			550
Utilized			(919	)
LOCs			(116	)
Net		$	1,635
(1)     A $2 billion revolving credit facility that expires in 2010 is available in various amounts to FirstEnergy and certain of its subsidiaries. A $100 million revolving credit facility that expires in December 2006 and a $20 million uncommitted line of credit facility that expires in September 2006 are both available to FirstEnergy only.

As of March 31, 2006, the Ohio Companies and Penn had the aggregate capability to issue approximately $1.3 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $644 million and $576 million, respectively, as of March 31, 2006. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of March 31, 2006, JCP&L had the capability to issue $625 million of additional senior notes upon the basis of FMB collateral.

Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $6 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2006. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred stock shares authorized under their respective charters.

As of March 31, 2006, approximately $1 billion of capacity remained unused under an existing shelf registration statement, filed by FirstEnergy with the SEC in 2003, to support future securities issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of April 26, 2006, a shelf registration statement filed by OE became effective and provides, together with previously effective OE registration statements, $1 billion of capacity to support future issuances of debt securities by OE.

FirstEnergy's working capital and short-term borrowing needs are met principally with a $2 billion five-year revolving credit facility (included in the table above). Borrowings under the facility are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment expiration date, June 16, 2010.

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The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:

		Revolving			Regulatory and
		Credit Facility			Other Short-Term
Borrower		Sub-Limit			Debt Limitations 1
		(In millions)
FirstEnergy		$	2,000		$	1,500
OE			500			500
Penn			50			43
CEI			250			500
TE			250			500
JCP&L			425			412
Met-Ed			250			300
Penelec			250			300
FES			- 2			n/a
ATSI			- 2			26

(1)

As of March 31, 2006.

(2)

Borrowing sub-limits for FES and ATSI may be increased to up to $250 million and $100 million, respectively, by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility.

 

    The revolving credit facility, combined with an aggregate $550 million ($292 million unused as of March 31, 2006) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet short-term working capital requirements for FirstEnergy and its subsidiaries.

Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities was $1.6 billion as of March 31, 2006.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter.

As of March 31, 2006, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy			54	%
OE			33	%
Penn			35	%
CEI			52	%
TE			31	%
JCP&L			27	%
Met-Ed			39	%
Penelec			36	%

The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.

    FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2006 was approximately 4.58% for both the regulated companies’ money pool and the unregulated companies' money pool.

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FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy’s and the Companies' securities ratings as of March 31, 2006. The ratings outlook from S&P on all securities is stable. The ratings outlook from Moody's and Fitch on all securities is positive.

Issuer		Securities		S&P		Moody’s		Fitch
FirstEnergy		Senior unsecured		BBB-		Baa3		BBB-
OE		Senior unsecured		BBB-		Baa2		BBB
		Preferred stock		BB+		Ba1		BBB-
CEI		Senior secured		BBB		Baa2		BBB-
		Senior unsecured		BBB-		Baa3		BB+
TE		Senior secured		BBB		Baa2		BBB-
		Preferred stock		BB+		Ba2		BB
Penn		Senior secured		BBB+		Baa1		BBB+
		Senior unsecured (1)		BBB-		Baa2		BBB
		Preferred stock		BB+		Ba1		BBB-
JCP&L		Senior secured		BBB+		Baa1		BBB+
		Preferred stock		BB+		Ba1		BBB-
Met-Ed		Senior secured		BBB+		Baa1		BBB+
		Senior unsecured		BBB		Baa2		BBB
Penelec		Senior unsecured		BBB		Baa2		BBB

⁽¹⁾   Penn's only senior unsecured debt obligations are notes underlying pollution control revenue refunding bonds issued by the Ohio Air Quality Development Authority to which bonds this rating applies.

    On January 20, 2006, TE redeemed all 1.2 million of its outstanding shares of Adjustable Rate Series B preferred stock at $25.00 per share, plus accrued dividends to the date of redemption.

On April 3, 2006, NGC issued pollution control revenue refunding bonds ($60 million at 3.07% and $46.5 million at 3.25%). These bonds were used to redeem the following Companies' pollution control notes (OE - $60 million at 7.05%, CEI - $27.7 million at 3.32%, TE - $18.8 million at 3.32%) on April 3, 2006. Also on April 3, 2006, FGCO issued pollution control revenue refunding bonds ($90.1 million at 3.03% and $56.6 million at 3.10%) which were used to redeem the following Companies' pollution control notes (OE - $14.8 million at 5.45%, Penn - $6.95 million at 5.45%, TE - $34.85 million at 3.18%, CEI - $47.5 million at 3.22%, $39.8 million at 3.20% and $2.8 million at 3.15%) in April and May 2006. These refinancings were undertaken in furtherance of FirstEnergy's intra-system generation asset transfers (see Note 14). The proceeds from NGC's and FGCO's refinancing issuances were used to repay a portion of their associated company notes payable to OE, Penn, CEI, and TE, who then redeemed their respective debt.

FirstEnergy will consider a common stock repurchase program later in 2006 after satisfactorily finalizing its environmental compliance plans for its fossil plants.

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Cash Flows From Investing Activities

 

    Net cash flows used in investing activities resulted principally from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the power supply management services segment are principally generation-related. The following table summarizes investments for the first quarter of 2006 and 2005 by segment:

Summary of Cash Flows		Property
Used for Investing Activities		Additions			Investments			Other			Total
Sources (Uses)		(In millions)
Three Months Ended March 31, 2006
Regulated services		$	(195	)	$	58		$	(7	)	$	(144	)
Power supply management services			(244	)		(34	)		-			(278	)
Other			(1	)		16			(5	)		10
Inter-Segment reconciling items			(7	)		30			1			24
Total		$	(447	)	$	70		$	(11	)	$	(388	)
Three Months Ended March 31, 2005
Regulated services		$	(141	)	$	21		$	3		$	(117	)
Power supply management services			(81	)		14			-			(67	)
Other			(3	)		1			(13	)		(15	)
Inter-Segment reconciling items			(4	)		(8	)		-			(12	)
Total		$	(229	)	$	28		$	(10	)	$	(211	)

 

Net cash used for investing activities in the first quarter of 2006 increased by $177 million compared to the first quarter of 2005. The increase was principally due to a $218 million increase in property additions which reflects the replacement of the steam generators and reactor head at Beaver Valley Unit 1 and the distribution system Accelerated Reliability Improvement Program. The increase in property additions was partially offset by a $22 million decrease in net nuclear decommissioning trust activities due to completion of the Ohio Companies' and Penn's transition cost recovery for decommissioning at the end of 2005.

During the remaining three quarters of 2006, capital requirements for property additions and capital leases are expected to be approximately $860 million. FirstEnergy and the Companies have additional requirements of approximately $1.3 billion for maturing long-term debt during the remainder of 2006. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term debt capital markets and short-term credit arrangements.

FirstEnergy's capital spending for the period 2006-2010 is expected to be about $6.7 billion (excluding nuclear fuel), of which $1.1 billion applies to 2006. Investments for additional nuclear fuel during the 2006-2010 periods are estimated to be approximately $769 million, of which about $164 million applies to 2006. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $574 million and $92 million, respectively, as the nuclear fuel is consumed.

GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds, and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy's credit ratings.

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As of March 31, 2006, FirstEnergy's maximum exposure to potential future payments under outstanding guarantees and other assurances totaled approximately $3.3 billion, as summarized below:

		Maximum
Guarantees and Other Assurances		Exposure
		(In millions)
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts (1)		$	906
Other (2)			884
			1,790
Surety Bonds			136
LOC (3)(4)			1,340
Total Guarantees and Other Assurances		$	3,266

(1)

Issued for open-ended terms, with a 10-day termination right by FirstEnergy.

(2)

Issued for various terms.

(3)

Includes $116 million issued for various terms under LOC capacity available under FirstEnergy’s revolving credit agreement and $604 million outstanding in support of pollution control revenue bonds issued with various maturities.

(4)

Includes approximately $194 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of its subsidiaries directly involved in these energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy's other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related contracts is remote.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of March 31, 2006, FirstEnergy's maximum exposure under these collateral provisions was $456 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($36 million as of March 31, 2006), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.

OFF-BALANCE SHEET ARRANGEMENTS

FirstEnergy has obligations that are not included on its Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.3 billion as of March 31, 2006.

FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under Guarantees and Other Assurances above.

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MARKET RISK INFORMATION

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities throughout the Company.

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices primarily due to fluctuations in electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy's derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the table below. Contracts that are not exempt from such treatment include power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2006 is summarized in the following table:

Increase (Decrease) in the Fair Value of Commodity Derivative Contracts		Non-Hedge			Hedge			Total
		(In millions)
Change in the Fair Value of Commodity Derivative Contracts:
Outstanding net liability as of January 1, 2006		$	(1,170	)	$	(3	)	$	(1,173	)
New contract value when entered			-			-			-
Additions/change in value of existing contracts			122			(7	)		115
Change in techniques/assumptions			-			-			-
Settled contracts			(81	)		5			(76	)
Outstanding net liability as of March 31, 2006 (1)		$	(1,129	)	$	(5	)	$	(1,134	)
Non-commodity Net Assets as of March 31, 2006 :
Interest Rate Swaps (2)			-			(16	)		(16	)
Net Liabilities - Derivatives Contracts as of March 31, 2006		$	(1,129	)	$	(21	)	$	(1,150	)
Impact of Changes in Commodity Derivative Contracts: (3)
Income Statement Effects (Pre-Tax)		$	(2	)	$	-		$	(2	)
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)		$	-		$	(2	)	$	(2	)
Regulatory Asset (net)		$	(43	)	$	-		$	(43	)

⁽¹⁾   Includes $1,140 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

⁽²⁾   Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below).

⁽³⁾   Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

        Derivatives are included on the Consolidated Balance Sheet as of March 31, 2006 as follows:

Balance Sheet Classification		Non-Hedge			Hedge			Total
		(In millions)
Current-
Other assets		$	5		$	12		$	17
Other liabilities			(9	)		(15	)		(24	)
Non-Current-
Other deferred charges			46			30			76
Other noncurrent liabilities			(1,171	)		(48	)		(1,219	)
Net assets (liabilities)		$	(1,129	)	$	(21	)	$	(1,150	)

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    The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts by year are summarized in the following table:

Source of Information
- Fair Value by Contract Year		2006 (1)			2007			2008			2009			2010			Thereafter			Total
		(In millions)
Prices actively quoted (2)		$	(2	)	$	(2	)	$	-		$	-		$	-		$	-		$	(4	)
Other external sources (3)			(281	)		(284	)		-			-			-			-			(565	)
Prices based on models			-			-			(246	)		(166	)		(137	)		(16	)		(565	)
Total (4)		$	(283	)	$	(286	)	$	(246	)	$	(166	)	$	(137	)	$	(16	)	$	(1,134	)

⁽¹⁾   For the last three quarters of 2006.

⁽²⁾   Exchange traded.

⁽³⁾   Broker quote sheets.

(4)

Includes $1,140 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.

 

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2006. Based on derivative contracts held as of March 31, 2006, an adverse 10% change in commodity prices would decrease net income by approximately $5 million during the next 12 months.

Interest Rate Swap Agreements- Fair Value Hedges

FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the first quarter of 2006, FirstEnergy unwound swaps with a total notional amount of $350 million for which FirstEnergy paid $1 million in cash. The loss will be recognized over the remaining maturity of each respective hedged security as increased interest expense. As of March 31, 2006, the debt underlying the $750 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.74%, which the swaps have converted to a current weighted average variable rate of 6.24%.

		March 31, 2006									December 31, 2005
		Notional			Maturity			Fair			Notional			Maturity			Fair
Interest Rate Swaps		Amount			Date			Value			Amount			Date			Value
		(In millions)
(Fair value hedges)		$	100			2008		$	(4	)	$	100			2008		$	(3	)
			50			2010			(1	)		50			2010			-
			-			2011			-			50			2011			-
			300			2013			(12	)		450			2013			(4	)
			150			2015			(13	)		150			2015			(9	)
			-			2016			-			150			2016			-
			50			2025			(2	)		50			2025			(1	)
			100			2031			(8	)		100			2031			(5	)
		$	750					$	(40	)	$	1,100					$	(22	)

Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2006 through 2008. 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 2006, FirstEnergy entered into forward swaps with a total notional amount of $525 million and terminated forward swaps with a total notional amount of $500 million from which FirstEnergy received $16 million in cash. The gain associated with the ineffective portion of the terminated hedges ($5 million) was recognized in earnings in the first quarter of 2006, with the remainder to be recognized over the terms of the respective forward swaps. As of March 31, 2006, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $1 billion and an aggregate fair value of $25 million.

 

 

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		March 31, 2006									December 31, 2005
		Notional			Maturity			Fair			Notional			Maturity			Fair
Forward Starting Swaps		Amount			Date			Value			Amount			Date			Value
		(In millions)
(Cash flow hedges)		$	25			2015		$	1		$	25			2015		$	-
			250			2016			8			600			2016			2
			50			2017			1			25			2017			-
			125			2018			4			275			2018			1
			50			2020			2			50			2020			-
			500			2036			9			-			2036			-
		$	1,000					$	25		$	975					$	3

Equity Price Risk

    Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.1 billion as of March 31, 2006 and December 31, 2005. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $113 million reduction in fair value as of March 31, 2006.

CREDIT RISK

 

Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of March 31, 2006, the largest credit concentration with one party (currently rated investment grade) represented 7.1% of FirstEnergy's total credit risk. Within FirstEnergy's unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of March 31, 2006.

Outlook

State Regulatory Matters

                 In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:

 

·	restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies;
·	establishing or defining the PLR obligations to customers in the Companies' service areas;
·	providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive    generation market;
·	itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges;
·	continuing regulation of the Companies' transmission and distribution systems; and
·	requiring corporate separation of regulated and unregulated business activities.

 

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    The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $237 million as of March 31, 2006. The following table discloses the regulatory assets by company and by source:

		March 31,			December 31,			Increase
Regulatory Assets*		2006			2005			(Decrease)
		(In millions)
OE		$	757		$	775		$	(18	)
CEI			858			862			(4	)
TE			276			287			(11	)
JCP&L			2,168			2,227			(59	)
Met-Ed			308			310			(2	)
ATSI			29			25			4
Total		$	4,396		$	4,486		$	(90	)

*

Penn had net regulatory liabilities of approximately $64 million and $59 million as of March 31, 2006 and December 31, 2005. Penelec had net regulatory liabilities of approximately $156 million and $163 million as of March 31, 2006 and December 31, 2005. These net regulatory liabilities are included in Other Noncurrent Liabilities on the Consolidated Balance Sheets.

Regulatory assets by source are as follows:

		March 31,			December 31,			Increase
Regulatory Assets By Source		2006			2005			(Decrease)
		(In millions)
Regulatory transition costs		$	3,470		$	3,576		$	(106	)
Customer shopping incentives			662			884			(222	)
Customer receivables for future income taxes			215			217			(2	)
Societal benefits charge			15			29			(14	)
Loss on reacquired debt			40			41			(1	)
Employee postretirement benefits costs			53			55			(2	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs			(129	)		(126	)		(3	)
Asset removal costs			(164	)		(365	)		201
Property losses and unrecovered plant costs			27			29			(2	)
MISO transmission costs			90			91			(1	)
RCP fuel recovery			22			-			22
RCP distribution costs			40			-			40
JCP&L reliability costs			21			23			(2	)
Other			34			32			2
Total		$	4,396		$	4,486		$	(90	)

Reliability Initiatives

 

FirstEnergy is proceeding with the implementation of the recommendations that were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) in late 2003 and early 2004, regarding enhancements to regional reliability that were to be completed subsequent to 2004. FirstEnergy will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing, equipment. The FERC or other applicable government agencies and reliability coordinators, however, may take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to EPACT that could require additional, material expenditures. Finally, the PUCO is continuing to review our filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. In 2004, the NJBPU adopted an MOU that set out specific tasks and a timetable for completion of actions related to service reliability to be performed by JCP&L and also approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

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In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. On December 30, 2005, the ALJ recommended that the PPUC adopt the Joint Petition for Settlement among the parties involved in the three Companies’ request to amend the distribution reliability benchmarks, thereby eliminating the need for full litigation. The ALJ’s recommendation, adopting the revised benchmarks and standards, was approved by the PPUC on February 9, 2006.

EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume monitoring responsibility for the new reliability standards. The FERC issued an order on rehearing on March 30, 2006, providing certain clarifications and essentially affirming the rule.

The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC made a filing with the FERC on April 4, 2006 to obtain certification as the ERO and to obtain FERC approval of delegation agreements with regional entities. The new FERC rule referred to above, further provides for reorganizing regional reliability organizations (regional entities) that would replace the current regional councils and for rearranging the relationship with the ERO. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. NERC also made a parallel filing with the FERC April 4, 2006 seeking approval of mandatory reliability standards. These reliability standards are based with some modifications, on the current NERC Version O reliability standards with some additional standards. On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards and thirteen additional reliability standards. These standards will become effective on June 1, 2006 and will be filed with the FERC and relevant Canadian authorities for approval. The two filings are subject to review and acceptance by the FERC.

The ERO filing was noticed on April 7, 2006 and comments and interventions were filed on May 4, 2006. There is no fixed time for the FERC to act on this filing. The reliability standards filing was noticed by FERC on April 18, 2006. In that notice FERC announced its intent to treat the proposed reliability standards as a NOPR and issue a NOPR in July 2006. Prior to that time, the FERC staff will release a preliminary assessment of the proposed reliability standards. FERC also intends to hold a technical conference on the proposed reliability standards. A comment period will be set after the Staff assessment is released and the technical conference is held. NERC has requested an effective date of January 1, 2007 for the reliability standards.

The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have completed the consolidation of these regions into a single new regional reliability organization known as ReliabilityFirst Corporation. ReliabilityFirst began operations as a regional reliability council under NERC on January 1, 2006 and intends to file and obtain certification consistent with the final rule as a “regional entity” under the ERO during 2006. All of FirstEnergy’s facilities are located within the ReliabilityFirst region.

    FirstEnergy believes that it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC standards. The financial impact of complying with the new standards cannot be determined at this time. However, EPACT requires that all prudent costs incurred to comply with the new reliability standards be recovered in rates. If FirstEnergy is unable to meet the reliability standards for the bulk power system in the future, it could have a material adverse effect on the Company’s and its subsidiaries’ financial condition, results of operations and cash flows.

See Note 11 to the consolidated financial statements for a more detailed discussion of reliability initiatives.

Ohio

        On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.

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        Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from the CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised RSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.

On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies' RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·

Maintaining the existing level of base distribution rates through December 31, 2008 for OE and TE, and April 30, 2009 for CEI;

·

Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

·

Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE and TE and as of December 31, 2010 for CEI;

·

Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE, $45 million for TE, and $85 million for CEI by accelerating the application of each respective company's accumulated cost of removal regulatory liability; and

·

Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. OE, TE, and CEI may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider).

The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2010:

Amortization											Total
Period		OE			CEI			TE			Ohio
		(In millions)
2006		$	172		$	97		$	83		$	352
2007			180			113			90			383
2008			206			130			108			444
2009			-			211			-			211
2010			-			263			-			263
Total Amortization		$	558		$	814		$	281		$	1,653

The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to:

	·	Recognize fuel and distribution deferrals commencing January 1, 2006;
	·	Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;

 

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	·	Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and
	·	Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred.

 

The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 30, 2006 are approximately $66 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, the Ohio Companies filed a modification to the rider to determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of the Ohio Companies' case with a similar case involving Dayton Power & Light Company. Oral arguments are currently scheduled for May 10, 2006.

On January 20, 2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and the Ohio Companies will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of the Ohio Companies' case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.

See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Pennsylvania

 

As of March 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $328 million and $50 million, respectively. Penelec's $50 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds.

    On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. As of March 31, 2006, the PPUC had taken no action on the request and neither company had yet implemented deferral accounting for these costs. Met-Ed and Penelec sought to consolidate this proceeding (and modified their request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing they made on April 10, 2006 as described below. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed and Penelec will implement deferral accounting for these costs in the second quarter of 2006, which will include $24 million and $4 million, respectively, representing the amounts that were incurred in the first quarter of 2006 -- the deferrals of such amounts will be reflected in the second quarter of 2006.

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Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. Under this agreement, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their contracts with NUGs and other unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. The wholesale power sales agreement with FES could automatically be extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right in 2006 to terminate the agreement at any time upon 60 days notice. On April 7, 2006, the parties to the wholesale power sales agreement entered into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the wholesale power sales agreement effective midnight December 31, 2006, because that agreement is not economically sustainable to FES.

In lieu of allowing such termination to become effective as of December 31, 2006, the parties agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales agreement to provide as follows:

1.   The termination provisions of the wholesale power sales agreement will be tolled for one year until December 31, 2007, provided that during such tolling period:

a.	FES will be permitted to terminate the wholesale power sales agreement at any time with sixty days written notice;

b.

Met-Ed and Penelec will procure through arrangements other than the wholesale power sales agreement beginning December 1, 2006 and ending December 31, 2007, approximately 33% of the amounts of capacity and energy necessary to satisfy their PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased power contracts and distributed generation) have not been obtained; and

c.	FES will not be obligated to supply additional quantities of capacity and energy in the event that a supplier of Committed Resources defaults on its supply agreement.

2.   During the tolling period FES will not act as agent for Met-Ed or Penelec in procuring the services under section 1.(b) above; and

3.   The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed and Penelec comply with the provisions of the Tolling Agreement and any applicable provision of the wholesale power sales agreement.

In the event that FES elects not to terminate the wholesale power sales agreement effective midnight December 31, 2007, similar tolling agreements effective after December 31, 2007 are expected to be considered by FES for subsequent years if Met-Ed and Penelec procure through arrangements other than the wholesale power sales agreement approximately 64%, 83% and 95% of the additional amounts of capacity and energy necessary to satisfy their PLR obligations for 2008, 2009 and 2010, respectively, for which Committed Resources have not been obtained from the market.

The wholesale power sales agreement, as modified by the Tolling Agreement, requires Met-Ed and Penelec to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed below, or, to the extent granted, adequate to mitigate such adverse consequences.

Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million and $157 million, respectively. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a competitive bid process as the amount of supply provided under the existing FES agreement is phased out in accordance with the April 7, 2006 Tolling agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 petition for the deferral of transmission-related costs discussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also included in the filing. The filing contemplates a reduction in distribution rates for Met-Ed in the amount of $37 million annually and an increase in distribution rates for Penelec in the amount of $20 million annually. Although the companies have proposed an effective date of June 10, 2006, it is expected that the PPUC will suspend the effective date for seven months as permitted under Pennsylvania law. Hearings are expected to be scheduled for the second half of 2006 and a PPUC decision is expected early in the first quarter of 2007.

 

 

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On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn recommended that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. The PPUC approved the Recommended Decision with additional modifications on April 20, 2006. The approved plan is designed to provide customers with PLR service for January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2006, the accumulated deferred cost balance totaled approximately $558 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval to securitize the July 31, 2003 deferred balance. On December 2, 2005, JCP&L filed a request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2003 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the financial advisor. Meetings with the NJBPU Staff and the DRA were held during March and April and additional discovery conducted. The DRA filed comments on April 6, 2006, arguing that the proposed securitization does not produce customer savings. JCP&L submitted reply comments on April 10, 2006. On February 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of cost incurred since July 31, 2003. The filing also includes a request for recovery of $49 million for above-market NUG costs incurred prior to August 1, 2003, to the extent those costs are not recoverable through securitization. On March 29, 2006, a pre-hearing conference was held with the presiding ALJ. A schedule for the proceeding was established including a discovery period and evidentiary hearings scheduled for September 2006.

An NJBPU Decision and Order approving a Phase II Stipulation of Settlement and resolving the Motion for Reconsideration of the Phase I Order was issued on May 31, 2005. The Phase II Settlement includes a performance standard pilot program with potential penalties of up to 0.25% of equity return. The Order requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI information related to the performance pilot program) through December 2006 and updates to reliability related project expenditures until all projects are completed. The first quarterly report was submitted to NJBPU on August 16, 2005. The second quarterly report was submitted on November 22, 2005. The third quarterly report as of December 31, 2005 was submitted on March 28, 2006. As of December 31, 2005 there were no performance penalties issued by the NJBPU.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address the issues was published in the NJ Register on December 19, 2005. The proposal would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. A public hearing was held February 7, 2006 and comments were submitted to the NJBPU. The NJBPU Staff issued a draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Comments and reply comments are due by May 22 and May 31, 2006, respectively. JCP&L is not able to predict the outcome of this proceeding at this time.

See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

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FERC Matters

 

On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006.

On November 1, 2004, ATSI filed with FERC a request to defer approximately $54 million of costs to be incurred from 2004 through 2007 in connection with ATSI’s Vegetation Management Enhancement Project (VMEP), which represents ATSI’s adoption of newly identified industry “best practices” for vegetation management. On March 4, 2005, the FERC approved ATSI’s request to defer the VMEP costs (approximately $29 million deferred as of March 31, 2006). On March 28, 2006 ATSI and MISO filed with FERC a request to modify ATSI’s Attachment O formula rate to include revenue requirements associated with recovery of deferred VMEP costs over a five-year period. The requested effective date to begin recovery is June 1, 2006. Various parties have filed comments responsive to the March 28, 2006 submission. The FERC has not taken any action on the filing. The estimated impact of the VMEP cost recovery is $13 million in revenues annually during the five-year recovery period of June 1, 2006 to May 31, 2011.

On January 24, 2006, ATSI and MISO filed with FERC a request to correct ATSI’s Attachment O formula rate to reverse revenue credits associated with termination of revenue streams from transitional rates stemming from FERC’s elimination of through and out rates. Revenues formerly collected under these rates were included in, and served to reduce, ATSI’s zonal transmission rate under the Attachment O formula. Absent the requested correction, elimination of these revenue streams would not be fully reflected in ATSI’s formula rate until June 1, 2008. On March 16, 2006, FERC approved without suspension the revenue credit correction, which became effective April 1, 2006. One party sought rehearing of the FERC order. The FERC has not yet issued a further order. The estimated impact of the correction mechanism is approximately $40 million in revenues on an annualized basis beginning June 1, 2006.

On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio competitive bid process, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of an April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for further consideration on March 1, 2006.

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Environmental Matters

The Companies accrue environmental liabilities only when it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in the Companies' determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

On December 1, 2005, FirstEnergy issued a comprehensive report to shareholders regarding air emissions regulations and an assessment of future risks and mitigation efforts. The report is available on FirstEnergy's web site at www.firstenergycorp.com/environmental.

National Ambient Air Quality Standards

 

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO _X and SO ₂ emissions in two phases (Phase I in 2009 for NO _X , 2010 for SO ₂ and Phase II in 2015 for both NO _X and SO ₂ ). FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO ₂ and NO _X emissions, whereas its New Jersey fossil-fired generation facilities will be subject to a cap on NO _X emissions only. According to the EPA, SO ₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO ₂ emissions in affected states to just 2.5 million tons annually. NO _X emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO _X cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which the Companies operate affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized CAMR, which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO ₂ and NO _X emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at 15 tons per year by 2018. However, the final rules give states substantial discretion in developing rules to implement these programs. In addition, both CAIR and CAMR have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

    The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced. Since this approach is based on output, new and non-emitting generating facilities, including renewables and nuclear, would be entitled to their proportionate share of the allowances. Consequently, FirstEnergy would be disadvantaged if these model rules were implemented because FirstEnergy's substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NO _X and SO ₂ emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties paid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

 

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Climate Change

 

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18% through 2012. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO ₂ emissions could require significant capital and other expenditures. However, the CO ₂ emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which include low or non-CO ₂ emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2006, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey. Those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $63 million have been accrued through March 31, 2006.

    See Note 1 0(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

Power Outages and Related Litigation

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

 

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FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for rehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of potential liability is available for any of these cases. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. Following the PUCO's March 7, 2006 order, that action was voluntarily dismissed by the claimants.

In addition to the above proceedings, FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter has been filed. FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. It is uncertain whether the plaintiff will appeal. No estimate of potential liability has been undertaken in either of these matters.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Nuclear Plant Matters

On January 20, 2006, FENOC announced that it has entered into a deferred prosecution agreement with the U.S. Attorney’s Office for the Northern District of Ohio and the Environmental Crimes Section of the Environment and Natural Resources Division of the DOJ related to FENOC’s communications with the NRC during the fall of 2001 in connection with the reactor head issue at the Davis-Besse Nuclear Power Station. Under the agreement, which expires on December 31, 2006, the United States acknowledged FENOC’s extensive corrective actions at Davis-Besse, FENOC’s cooperation during investigations by the DOJ and the NRC, FENOC’s pledge of continued cooperation in any related criminal and administrative investigations and proceedings, FENOC’s acknowledgement of responsibility for the behavior of its employees, and its agreement to pay a monetary penalty. The DOJ will refrain from seeking an indictment or otherwise initiating criminal prosecution of FENOC for all conduct related to the statement of facts attached to the deferred prosecution agreement, as long as FENOC remains in compliance with the agreement, which FENOC fully intends to do. FENOC paid a monetary penalty of $28 million (which is not deductible for income tax purposes) which reduced First Energy's earnings by $0.09 per common share in the fourth quarter of 2005.

 

 

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On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue discussed above. FirstEnergy accrued $2 million for a potential fine prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005. On January 23, 2006, FENOC supplemented its response to the NRC's NOV on the Davis-Besse head degradation to reflect the deferred prosecution agreement that FENOC had reached with the DOJ.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant.

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of Perry on March 14, 2006, the NRC again stated that the Perry Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. Although FirstEnergy is unable to predict the impact of the ultimate disposition of this matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

As of December 16, 2005, NGC acquired ownership of the nuclear generation assets transferred from OE, CEI, TE and Penn with the exception of leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other material items not otherwise discussed above are described below.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

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On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, the federal court granted a Union motion to dismiss JCP&L's appeal of the award as premature. JCP&L will file its appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.

See Note 10(C) to the consolidated financial statements for further details and a complete discussion of these and other legal proceedings.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

 

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on FirstEnergy's financial results.

SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

 

        In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

 

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
STATEMENTS OF INCOME		(In thousands)
OPERATING REVENUES		$	586,203		$	726,358
OPERATING EXPENSES AND TAXES:
Fuel			2,951			11,916
Purchased power			272,386			246,590
Nuclear operating costs			41,084			95,653
Other operating costs			90,810			83,179
Provision for depreciation			18,016			26,052
Amortization of regulatory assets			53,861			111,771
Deferral of new regulatory assets			(25,606	)		(24,795	)
General taxes			45,895			48,078
Income taxes			30,550			54,972
Total operating expenses and taxes			529,947			653,416
OPERATING INCOME			56,256			72,942
OTHER INCOME (net of income taxes)			25,470			423
NET INTEREST CHARGES:
Interest on long-term debt			13,082			15,609
Allowance for borrowed funds used during construction and capitalized interest			(491	)		(2,235	)
Other interest expense			5,149			2,594
Subsidiary's preferred stock dividend requirements			156			640
Net interest charges			17,896			16,608
NET INCOME			63,830			56,757
PREFERRED STOCK DIVIDEND REQUIREMENTS			659			659
EARNINGS ON COMMON STOCK		$	63,171		$	56,098
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME		$	63,830		$	56,757
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on available for sale securities			5,735			(2,717	)
Income tax expense (benefit) related to other comprehensive income			2,069			(1,124	)
Other comprehensive income (loss), net of tax			3,666			(1,593	)
TOTAL COMPREHENSIVE INCOME		$	67,496		$	55,164
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these statements.

 

 

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OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,						December 31,
		2006						2005
		(In thousands)
ASSETS
UTILITY PLANT:
In service		$	2,552,488					$	2,526,851
Less - Accumulated provision for depreciation			996,292						984,463
			1,556,196						1,542,388
Construction work in progress			56,728						58,785
			1,612,924						1,601,173
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds			325,519						325,729
Nuclear plant decommissioning trusts			109,497						103,854
Long-term notes receivable from associated companies			1,758,377						1,758,776
Other			43,491						44,210
			2,236,884						2,232,569
CURRENT ASSETS:
Cash and cash equivalents			1,048						929
Receivables-
Customers (less accumulated provisions of $8,136,000 and $7,619,000, respectively,
for uncollectible accounts)			251,937						290,887
Associated companies			104,839						187,072
Other (less accumulated provisions of $23,000 and $4,000, respectively,
for uncollectible accounts)			20,239						15,327
Notes receivable from associated companies			582,252						536,629
Prepayments and other			27,017						93,129
			987,332						1,123,973
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets			757,164						774,983
Prepaid pension costs			226,314						224,813
Property taxes			52,897						52,875
Unamortized sale and leaseback costs			53,888						55,139
Other			29,013						31,752
			1,119,276						1,139,562
		$	5,956,416					$	6,097,277
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding		$	2,297,289					$	2,297,253
Accumulated other comprehensive income			7,760						4,094
Retained earnings			229,015						200,844
Total common stockholder's equity			2,534,064						2,502,191
Preferred stock not subject to mandatory redemption			60,965						60,965
Preferred stock of consolidated subsidiary not subject to mandatory redemption			14,105						14,105
Long-term debt and other long-term obligations			931,507						1,019,642
			3,540,641						3,596,903
CURRENT LIABILITIES:
Currently payable long-term debt			309,445						280,255
Short-term borrowings-
Associated companies			-						57,715
Other			22,584						143,585
Accounts payable-
Associated companies			181,663						172,511
Other			10,123						9,607
Accrued taxes			191,375						163,870
Accrued interest			12,054						8,333
Other			95,273						61,726
			822,517						897,602
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			764,337						769,031
Accumulated deferred investment tax credits			23,194						24,081
Asset retirement obligation			84,282						82,527
Retirement benefits			292,965						291,051
Deferred revenues - electric service programs			113,930						121,693
Other			314,550						314,389
			1,593,258						1,602,772
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	5,956,416					$	6,097,277
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.

 

 

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		March 31,
		2006						2005
		(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	63,830					$	56,757
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			18,016						26,052
Amortization of regulatory assets			53,861						111,771
Deferral of new regulatory assets			(25,606	)					(24,795	)
Nuclear fuel and lease amortization			532						9,170
Deferred purchased power costs			(10,634	)					-
Amortization of lease costs			32,934						33,030
Deferred income taxes and investment tax credits, net			(3,945	)					(24,627	)
Accrued compensation and retirement benefits			(1,494	)					(1,973	)
Decrease (increase) in operating assets-
Receivables			116,271						86,123
Materials and supplies			-						(15,834	)
Prepayments and other current assets			66,112						(12,877	)
Increase (decrease) in operating liabilities-
Accounts payable			9,668						(39,854	)
Accrued taxes			27,505						44,448
Accrued interest			3,721						6,993
Electric service prepayment programs			(7,763	)					-
Other			3,922						13,297
Net cash provided from operating activities			346,930						267,681
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net			-						31,182
Redemptions and Repayments-
Long-term debt			(59,506	)					(15,787	)
Short-term borrowings, net			(178,716	)					-
Dividend Payments-
Common stock			(35,000	)					(47,000	)
Preferred stock			(659	)					(659	)
Net cash used for financing activities			(273,881	)					(32,264	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(28,793	)					(79,783	)
Proceeds from nuclear decommissioning trust fund sales			19,054						68,400
Investments in nuclear decommissioning trust funds			(19,054	)					(76,285	)
Loans to associated companies, net			(45,224	)					(154,038	)
Other			1,087						6,263
Net cash used for investing activities			(72,930	)					(235,443	)
Net increase (decrease) in cash and cash equivalents			119						(26	)
Cash and cash equivalents at beginning of period			929						1,230
Cash and cash equivalents at end of period		$	1,048					$	1,204
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part
of these statements.

 

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Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of March 31, 2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those consolidated financial statements) dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2006

 

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OHIO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

   OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. The OE Companies also provide generation services to those customers electing to retain the OE Companies as their power supplier. Power supply requirements of the OE Companies are provided by FES - an affiliated company.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred did not include OE's leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, the OE Companies completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, the OE Companies completed the intra-system transfer of their ownership interests in the nuclear generation assets to NGC through an asset spin-off in the form of a dividend. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

The transfers will affect the OE Companies' near-term results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which the OE Companies previously sold their nuclear-generated KWH to FES and leased their non-nuclear generation assets to FGCO, a subsidiary of FES. Their expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. With respect to OE's retained leasehold interests in the Perry Nuclear Power Plant and Beaver Valley Power Station Unit 2. OE has continued the nuclear-generated KWH sales arrangement with FES for the associated output and continues to be obligated on the applicable portion of expenses related to those interests. In addition, the OE Companies receive interest income on associated company notes receivable from the transfer of their generation net assets. FES will continue to provide the OE Companies’ PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 (see Regulatory Matters).

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The effects on the OE Companies' results of operations in the first quarter of 2006 compared to the first quarter of 2005 from the generation asset transfers (also reflecting OE's retained leasehold interests discussed above) are summarized in the following table:

Intra-System Generation Asset Transfers -
First Quarter 2006 vs First Quarter 2005 Income Statement Effects
Increase (Decrease)		(In millions)
Operating Revenues:
Non-nuclear generating units rent		$	(45	) (a)
Nuclear generated KWH sales			(64	) (b)
Total - Operating Revenues Effect			(109	)
Operating Expenses and Taxes:
Fuel costs - nuclear			(9	) (c)
Nuclear operating costs			(46	) (c)
Provision for depreciation			(17	) (d)
General taxes			(3	) (e)
Income taxes			(15	) (i)
Total - Operating Expenses and Taxes Effect			(90	)
Operating Income Effect			(19	)
Other Income:
Interest income from notes receivable			15	(f)
Nuclear decommissioning trust earnings			(2	) (g)
Income taxes			(5	) (i)
Total - Other Income Effect			8
Net Interest Charges:
Allowance for funds used during construction			(2	) (h)
Total - Net Interest Charges Effect			2
Net Income Effect		$	(13	)
(a) Elimination of non-nuclear generation assets lease to FGCO.
(b) Reduction of nuclear generated wholesale KWH sales to FES.
(c) Reduction of nuclear fuel and operating costs.
(d) Reduction of depreciation expense and asset retirement obligation accretion related to generation assets.
(e) Reduction of property tax expense on generation assets.
(f) Interest income on associated company notes receivable from the
transfer of generation net assets.
(g) Reduction of earnings on nuclear decommissioning trusts.
(h) Reduction of allowance for borrowed funds used during construction on nuclear capital expenditures.
(i) Income tax effect of the above adjustments.

Results of Operations

 

    Earnings on common stock in the first quarter of 2006 increased to $63 million from $56 million in the first quarter of 2005. The increase in earnings in 2006 primarily resulted from reduced operating expenses and taxes and increased other income, partially offset by lower operating revenues and increased net interest charges principally from the asset transfer effects shown in the table above.

Operating Revenues

    Operating revenues decreased by $140 million or 19.3% in the first quarter of 2006 compared with the same period in 2005, primarily due to the generation asset transfer impact summarized in the table above. Excluding the effects of the asset transfer, operating revenues decreased $31 million, primarily due to decreases of $59 million and $98 million in wholesale sales and distribution revenues, respectively, partially offset by increases in retail generation revenues of $108 million and reduced customer shopping incentives of $18 million.

    The lower wholesale revenues reflected the termination of a non-affiliated wholesale sales agreement and the cessation of the MSG sales arrangements under OE’s transition plan in December 2005. OE had been required to provide the MSG to non-affiliated alternative suppliers.

    Increased retail generation revenues in all customer sectors (residential - $43 million; commercial - $32 million; and industrial - $33 million) reflected the impact of higher KWH sales and higher unit prices. The increase in generation KWH sales primarily resulted from decreased customer shopping, as the percentage of generation services provided by alternative suppliers to total sales delivered in OE's service area decreased by the following percentages: residential - 8.8%; commercial - 11.0%; and industrial - 9.3%. The decreased shopping resulted from alternative energy suppliers terminating their supply arrangements with OE’s shopping customers in the fourth quarter of 2005. Higher unit prices reflected the Rate Stabilization Charge and fuel recovery rider that became effective in January 2006 under the RCP.

 

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    Revenues from distribution throughput decreased $98 million in the first quarter of 2006 compared with the same period in 2006. The decrease in all customer sectors (residential - $40 million; commercial - $32 million; and industrial - $26 million) primarily reflected the impact of lower composite prices and reduced KWH deliveries. The lower unit prices reflected the completion of the generation-related transition cost recovery under OE’s and Penn’s respective rate restructuring plans in 2005, partially offset by the recovery of MISO costs beginning in 2006 (see Outlook -- Regulatory Matters). Lower distribution KWH deliveries to residential and commercial customers reflected the impact of milder weather conditions in the first quarter of 2006, compared to the same period of 2005.

    Under the Ohio transition plan, OE had provided incentives to customers to encourage switching to alternative energy providers, which reduced OE’s revenues by $18 million in the first quarter of 2005. These revenue reductions, which were deferred for future recovery and did not affect current period earnings, ceased in 2006. The deferred shopping incentives (Extended RTC) are now being recovered under the RCP (see Regulatory Matters below.)

    Changes in electric generation sales and distribution deliveries in the first quarter of 2006 from the same quarter of 2005 are summarized in the following table:

Changes in KWH Sales
Increase (Decrease)
Electric Generation:
Retail			11.3	%
Wholesale - Non-Associated			(95.6	)%
Wholesale - Associated (FES)*			(75.7	)%
Total Electric Generation Sales			(28.0	)%
Distribution Deliveries:
Residential			(1.8	)%
Commercial			(1.0	)%
Industrial			(1.7	)%
Total Distribution Deliveries			(1.5	)%
* Change reflects impact of generation asset transfers.

Operating Expenses and Taxes

    Total operating expenses and taxes decreased by $123 million in the first quarter of 2006 from the first quarter of 2005 principally due to the effects of the generation asset transfer shown in the table above. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes
Increase (Decrease)		(In millions)
Purchased power costs		$	26
Nuclear operating costs			(8	)
Other operating costs			7
Provision for depreciation			9
Amortization of regulatory assets			(58	)
Deferral of new regulatory assets			(1	)
General taxes			1
Income taxes			(10	)
Total operating expenses and taxes		$	(34	)

    I ncreased purchased power costs in the first quarter of 2006 reflected higher unit prices associated with the new power supply agreement with FES, partially offset by a decrease in KWH purchased to meet the lower net generation sales requirements, and RCP fuel deferrals of $11 million. Under the RCP that was effective January 1, 2006, OE can defer increased fuel costs (i.e., in excess of 2002 baseline amounts) above the amount collected through the fuel recovery mechanism. Excluding the effects of the generation asset transfers, the lower nuclear operating costs for OE’s nuclear leasehold interests were primarily due to the absence in 2006 of the Perry Nuclear Power Plant scheduled refueling outage (including an unplanned extension) in the first quarter of 2005. The increase in other operating costs was primarily from increased transmission expenses related to MISO Day 2 operations that began on April 1, 2005.

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    Excluding the effects of the generation asset transfers, higher depreciation expense in the first quarter of 2006 compared with the same quarter of 2005 reflects capital additions subsequent to the first quarter of 2005. Lower amortization of regulatory assets was due to the completion of the generation-related transition cost amortization under OE's and Penn's respective transition plans, partially offset by the amortization of deferred MISO costs being recovered in 2006. The higher deferrals of new regulatory assets primarily resulted from the deferral of distribution costs and related interest ($19 million) under the RCP, partially offset by the decrease in shopping incentive deferrals ($18 million) which ceased in 2006 under the Ohio transition plan. The deferral of interest on the unamortized shopping incentive balances will continue under the RCP.

Other Income

    Other income increased $25 million in the first quarter of 2006 compared with the same quarter of 2005, partially due to the effects of the asset transfer. Excluding the asset transfer effects, the $17 million increase is primarily due to the absence in 2006 of the 2005 accruals of an $8.5 million civil penalty payable to the DOJ and $10 million for environmental projects in connection with the Sammis New Source Review settlement (see Outlook - Environmental Matters).

Net Interest Charges

    Net interest charges increased $1 million in the first quarter of 2006 compared to the same period of 2005 primarily due to the effects of the generation asset transfer. Excluding the asset transfer, interest charges continued to trend lower, decreasing by $1 million in the first quarter of 2006 compared with the same quarter of 2005.

Capital Resources and Liquidity

    OE’s cash requirements in 2006 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met with cash from operations and short-term credit arrangements. Available borrowing capacity under credit facilities will be used to manage working capital requirements.

    In connection with a plan to realign its capital structure, OE may also issue up to $600 million of long-term debt in 2006 with proceeds expected to fund a return of equity capital to FirstEnergy.

Changes in Cash Position

    OE's cash and cash equivalents were approximately $1 million as of March 31, 2006 and December 31, 2005.

Cash Flows From Operating Activities

    Cash provided from operating activities during the first quarter of 2006, compared with the first quarter of 2005, were as follows:

		Three Months Ended March 31,
Operating Cash Flows		2006			2005
		(In millions)
Cash earnings (1)		$	120		$	185
Working capital and other			227			83
Net cash provided from operating activities		$	347		$	268

⁽¹⁾  Cash earnings are a non-GAAP measure (see reconciliation below).

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     Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. OE believes that cash earnings are a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income:

		Three Months Ended March 31,
Reconciliation of Cash Earnings		2006			2005
		(In millions)
Net Income (GAAP)		$	64		$	57
Non-Cash Charges (Credits):
Provision for depreciation			18			26
Amortization of regulatory assets			54			112
Deferral of new regulatory assets			(26	)		(25	)
Nuclear fuel and lease amortization			1			9
Amortization of electric service obligation			(8	)		-
Amortization of lease costs			33			33
Deferred income taxes and investment tax credits, net			(4	)		(25	)
Deferred purchased power costs			(11	)		-
Accrued compensation and retirement benefits			(1	)		(2	)
Cash earnings (Non-GAAP)		$	120		$	185

    Net cash provided from operating activities increased $79 million in the first quarter of 2006, compared with the first quarter of 2005, due to a $144 million increase from changes in working capital, partially offset by a $65 million decrease in cash earnings as described above under “Results from Operations.” The increase in working capital primarily reflects changes in accounts payable and receivables of $80 million and prepayments and other current assets of $79 million, partially offset by changes in accrued taxes of $17 million.

Cash Flows From Financing Activities

 

     Net cash used for financing activities increased to $274 million in the first quarter of 2006 from $32 million in the first quarter of 2005. The increase primarily reflected repayments of short-term borrowings to associated companies, partially offset by a $12 million decrease in common stock dividend payments to FirstEnergy.

    OE had approximately $583 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $23 million of short-term indebtedness as of March 31, 2006. OE has authorization from the PUCO to incur short-term debt of up to $500 million, which is expected to come from the bank facility and the utility money pool described below. Penn has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit of $43 million as of March 31, 2006, and will have access to the bank facility and the utility money pool.

    OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing arrangement. As a separate legal entity with separate creditors, OES Capital would have to satisfy its obligations to creditors before any of its remaining assets could be made available to OE. As of March 31, 2006, the facility was not drawn.

    Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to the full amount of $25 million available as of March 31, 2006 under a receivables financing arrangement which expires June 29, 2006 . As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of March 31, 2006, the facility was drawn for $19 million.

    As of March 31, 2006, OE and Penn had the aggregate capability to issue approximately $502 million of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE is also subject to provisions of its senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, OE is permitted under the indenture to incur additional secured debt not otherwise permitted by a specified exception of up to $644 million as of March 31, 2006. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of $3.1 billion of preferred stock (assuming no additional debt was issued) as of March 31, 2006.

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    As of April 26, 2006, a shelf registration statement filed by OE became effective and provides, together with previously effective OE registration statements, $1 billion of capacity to support future issuances of debt securities by OE.

    FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility with a syndicate of banks that expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. OE's borrowing limit under the facility is $500 million and Penn’s is $50 million, subject in each case to applicable regulatory approvals.

    Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities totaled $726 million as of March 31, 2006.

    The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, debt to total capitalization as defined under the revolving credit facility was 33% for OE and 35% for Penn.

    The facility does not contain any provisions that either restrict the ability of OE and Penn to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to OE’s and Penn’s credit ratings.

                 OE and Penn have the ability to borrow from their regulated affiliates and FirstEnergy to meet their short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2006 was 4.58%.

OE’s access to the capital markets and the costs of financing are influenced by the ratings of its securities. The ratings outlook from S&P on all securities is stable. The ratings outlook from Moody's and Fitch on all securities is positive.

 

In April 2006, pollution control notes that were formerly obligations of OE and Penn were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of their associated company notes payable to Penn and OE. With those repayments, OE redeemed $74.8 million and Penn redeemed $6.95 million of pollution control notes having variable interest rates.

Cash Flows From Investing Activities

 

    Net cash used for investing activities decreased to $73 million in the first quarter of 2006 from $235 million in the first quarter of 2005. The decrease resulted primarily from a $109 million decrease in loans to associated companies and a $51 million decrease in property additions, which reflects the impact of the generation asset transfers.

    During the remaining three quarters of 2006, capital requirements for property additions and capital leases are expected to be approximately $93 million. OE has additional requirements of approximately $4 million to meet requirements for maturing long-term debt during the remainder of 2006. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term debt capital markets and short-term credit arrangements. OE’s capital spending for the period 2006-2010 is expected to be about $638 million, of which approximately $122 million applies to 2006.

Off-Balance Sheet Arrangements

    Obligations not included on OE’s Consolidated Balance Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. The present value of these operating lease commitments, net of trust investments, was $666 million as of March 31, 2006.

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Equity Price Risk

 

    Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $71 million and $67 million as of March 31, 2006 and December 31, 2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of March 31, 2006. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of a sale or recognized as regulatory assets or liabilities.

Outlook

 

    The electric industry continues to transition to a more competitive environment and all of the OE Companies’ customers can select alternative energy suppliers. The OE Companies continue to deliver power to residential homes and businesses through their existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.

Regulatory Matters

Regulatory assets are costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered under the provisions of the OE Companies’ transition plans and rate restructuring plans. OE‘s regulatory assets were $757 million and $775 million as of March 31, 2006 and December 31, 2005, respectively. Penn had net regulatory liabilities of $64 million and $59 million as of March 31, 2006 and December 31, 2005, respectively, which are included in Other Noncurrent Liabilities on the Consolidated Balance Sheets as of March 31, 2006 and December 31, 2005.

        On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.

        Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from the CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised RSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.

On January 4, 2006, the PUCO approved, with modifications, OE's RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·

Maintaining the existing level of base distribution rates through December 31, 2008 for OE;

·

Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred by all of the Ohio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

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·

Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for OE;

·

Reducing the deferred shopping incentive balance as of January 1, 2006 by up to $75 million for OE by accelerating the application of its accumulated cost of removal regulatory liability; and

·

Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. The Ohio Companies may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider).

The following table provides OE’s estimated amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2008:

Amortization
Period			Amortization
			(In millions)
2006		$	172
2007			180
2008			206
Total Amortization		$	558

The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to:

 

	·	Recognize fuel and distribution deferrals commencing January 1, 2006;
	·	Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;
	·	Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and
	·	Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred.

 

The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.

On December 30, 2004, OE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. OE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 30, 2006 are approximately $34 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, OE filed a modification to the rider to determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for OE to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized OE to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of OE's case with a similar case involving Dayton Power & Light Company. Oral argument is currently scheduled for May 10, 2006.

 

 

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On January 20, 2006, the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and OE will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of OE's case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn recommended that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. The PPUC approved the Recommended Decision with additional modifications on April 20, 2006. The approved plan is designed to provide customers with PLR service for January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio competitive bid process, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of the April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for future consideration on March 1, 2006.

See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a detailed discussion of reliability initiatives, including initiatives by the PPUC, that impact Penn.

Environmental Matters

OE accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in OE’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NO _X and SO ₂ emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if OE and Penn fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, OE and Penn could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties paid by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities in the first quarter of 2005 of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects.

 

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See Note 10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

    There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to OE’s normal business operations pending against OE and its subsidiaries. The other potentially material items not otherwise discussed above are described below.

Power Outages and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for rehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of potential liability is available for any of these cases. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. Following the PUCO's March 7, 2006 order, that action was voluntarily dismissed by the claimants.

 

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    FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

Nuclear Plant Matters-

As of December 16, 2005, NGC acquired ownership of the nuclear generation assets transferred from OE, Penn, CEI and TE with the exception of leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates. Excluding OE's retained leasehold interests in Beaver Valley Unit 2 (21.66%) and Perry (12.58%), the transfer included the OE Companies’ prior owned interests in Beaver Valley Unit 1 (100%), Beaver Valley Unit 2 (33.96%) and Perry (22.66%).

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant.

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Plant and stated that the CAL would remain open until substantial improvement was demonstrated. The CAL was anticipated as part of the NRC's Reactor Oversight Process. In the NRC's 2005 annual assessment letter dated March 2, 2006 and associated meetings to discuss the performance of Perry on March 14, 2006, the NRC again stated that the Perry Plant continued to operate in a manner that "preserved public health and safety." However, the NRC also stated that increased levels of regulatory oversight would continue until sustained improvement in the performance of the facility was realized. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. Although FirstEnergy is unable to predict the impact of the ultimate disposition of this matter, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Other Legal Matters-

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully with the informal inquiry and continues to do so with the formal investigation.

 

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On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly-formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO of a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.

    If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

    See Note 10(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

 

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, OE will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on OE's financial results.

SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

 

        In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. OE is currently evaluating the impact of this Statement on its financial statements.

 

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
STATEMENTS OF INCOME		(In thousands)
OPERATING REVENUES		$	407,810		$	433,173
OPERATING EXPENSES AND TAXES:
Fuel			13,563			18,327
Purchased power			135,990			142,884
Nuclear operating costs			-			58,727
Other operating costs			72,895			63,573
Provision for depreciation			17,201			31,115
Amortization of regulatory assets			31,530			54,026
Deferral of new regulatory assets			(22,746	)		(25,288	)
General taxes			35,070			38,887
Income taxes			36,125			4,877
Total operating expenses and taxes			319,628			387,128
OPERATING INCOME			88,182			46,045
OTHER INCOME (net of income taxes)			18,290			4,304
NET INTEREST CHARGES:
Interest on long-term debt			27,185			27,952
Allowance for borrowed funds used during construction			(673	)		411
Other interest expense			7,547			6,514
Net interest charges			34,059			34,877
NET INCOME			72,413			15,472
PREFERRED STOCK DIVIDEND REQUIREMENTS			-			2,918
EARNINGS ON COMMON STOCK		$	72,413		$	12,554
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME		$	72,413		$	15,472
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized loss on available for sale securities			-			(1,221	)
Income tax benefit related to other comprehensive income			-			504
Other comprehensive loss, net of tax			-			(717	)
TOTAL COMPREHENSIVE INCOME		$	72,413		$	14,755
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric
Illuminating Company are an integral part of these statements.

 

 

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,			December 31,
		2006			2005
		(In thousands)
ASSETS
UTILITY PLANT:
In service		$	2,055,348		$	2,030,935
Less - Accumulated provision for depreciation			799,281			788,967
			1,256,067			1,241,968
Construction work in progress			59,756			51,129
			1,315,823			1,293,097
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			519,618			564,166
Long-term notes receivable from associated companies			1,058,626			1,057,337
Other			12,779			12,840
			1,591,023			1,634,343
CURRENT ASSETS:
Cash and cash equivalents			217			207
Receivables-
Customers (less accumulated provisions of $5,431,000 and $5,180,000,
respectively, for uncollectible accounts)			250,546			268,427
Associated companies			42,435			86,564
Other			3,958			16,466
Notes receivable from associated companies			28,535			19,378
Prepayments and other			1,388			1,903
			327,079			392,945
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			1,688,521			1,688,966
Regulatory assets			857,683			862,193
Prepaid pension costs			138,047			139,012
Property taxes			63,500			63,500
Other			39,874			27,614
			2,787,625			2,781,285
		$	6,021,550		$	6,101,670
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding		$	1,355,897		$	1,354,924
Retained earnings			596,563			587,150
Total common stockholder's equity			1,952,460			1,942,074
Long-term debt and other long-term obligations			1,887,074			1,939,300
			3,839,534			3,881,374
CURRENT LIABILITIES:
Currently payable long-term debt			118,370			75,718
Short-term borrowings-
Associated companies			209,647			212,256
Other			94,000			140,000
Accounts payable-
Associated companies			64,853			74,993
Other			5,380			4,664
Accrued taxes			137,178			121,487
Accrued interest			31,688			18,886
Lease market valuation liability			60,200			60,200
Other			30,750			61,308
			752,066			769,512
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			555,320			554,828
Accumulated deferred investment tax credits			23,001			23,908
Lease market valuation liability			593,000			608,000
Asset retirement obligation			8,117			8,024
Retirement benefits			83,641			83,414
Deferred revenues - electric service programs			67,205			71,261
Other			99,666			101,349
			1,429,950			1,450,784
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	6,021,550		$	6,101,670
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral
part of these balance sheets.

 

 

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
					Three Months Ended
					March 31,
					2006			2005
					(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income					$	72,413		$	15,472
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation						17,201			31,115
Amortization of regulatory assets						31,530			54,026
Deferral of new regulatory assets						(22,746	)		(25,288	)
Nuclear fuel and capital lease amortization						60			4,610
Deferred rents and lease market valuation liability						(54,821	)		(53,469	)
Deferred income taxes and investment tax credits, net						(402	)		(4,506	)
Deferred purchased power costs						(7,780	)		-
Accrued compensation and retirement benefits						(172	)		(3,203	)
Decrease (increase) in operating assets-
Receivables						74,518			84,890
Materials and supplies						-			(22,336	)
Prepayments and other current assets						515			627
Increase (decrease) in operating liabilities-
Accounts payable						(9,424	)		39,238
Accrued taxes						15,691			(21,198	)
Accrued interest						12,802			12,031
Electric service prepayment programs						(4,056	)		(5,451	)
Other						81			(3,358	)
Net cash provided from operating activities						125,410			103,200
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Preferred stock						-			(97,900	)
Long-term debt						(172	)		(330	)
Short-term borrowings, net						(57,760	)		(29,683	)
Dividend Payments-
Common stock						(63,000	)		(55,000	)
Preferred stock						-			(2,260	)
Net cash used for financing activities						(120,932	)		(185,173	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions						(34,410	)		(33,683	)
Loan repayments from (loans to) associated companies, net						(9,158	)		90,788
Investments in lessor notes						44,548			32,470
Proceeds from nuclear decommissioning trust fund sales						-			132,805
Investments in nuclear decommissioning trust funds						-			(140,061	)
Other						(5,448	)		(336	)
Net cash provided from (used for) investing activities						(4,468	)		81,983
Net increase in cash and cash equivalents						10			10
Cash and cash equivalents at beginning of period						207			197
Cash and cash equivalents at end of period					$	217		$	207
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company
are an integral part of these statements.

 

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Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of March 31, 2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(G) and Note 11 to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements.

In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2006

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

    CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES - an affiliated company.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively.

On October 24, 2005, CEI completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, CEI completed the intra-system transfer of their ownership interests in the nuclear generation assets to NGC through a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

The transfers will affect CEI’s near-term results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which CEI previously sold its nuclear-generated KWH to FES and leased its non-nuclear generation assets to FGCO, a subsidiary of FES. CEI’s expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets.With respect to CEI's retained leashold interests in the Bruce Mansfield Plant, CEI has continued the fossil generation KWH sales arrangement with FES and continues to be obligated on the applicable portion of expenses related to those interests. In addition, CEI receives interest income on associated company notes receivable from the transfer of its generation net assets. FES will continue to provide CEI’s PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 (see Regulatory Matters).

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The effects on CEI’s results of operations in the first quarter of 2006 compared to the first quarter of 2005 from the generation asset transfers (also reflecting CEI's retained leasehold interests discussed above) are summarized in the following table:

Intra-System Generation Asset Transfers -
First Quarter 2006 vs First Quarter 2005 Income Statement Effects
Increase (Decrease)		(In millions)
Operating Revenues:
Non-nuclear generating units rent		$	(15	) (a)
Nuclear generated KWH sales			(53	) (b)
Total - Operating Revenues Effect			(68	)
Operating Expenses and Taxes:
Fuel costs - nuclear			(6	) (c)
Nuclear operating costs			(58	) (c)
Provision for depreciation			(19	) (d)
General taxes			(4	) (e)
Income taxes			8	(i)
Total- Operating Expenses and Taxes Effect			(79	)
Operating Income Effect			11
Other Income:
Interest income from notes receivable			16	(f)
Nuclear decommissioning trust earnings			(2	) (g)
Income taxes			(6	)  (i)
Total-Other Income Effect			8
Net Interest Charges:
Allowance for funds used during construction			1	(h)
Total-Net Interest Charges Effect			(1	)
Net Income Effect		$	20
(a) Elimination of non-nuclear generation assets lease to FGCO.
(b) Reduction of nuclear generated wholesale KWH sales to FES.
(c) Reduction of nuclear fuel and operating costs.
(d) Reduction of depreciation expense and asset retirement obligation accretion related to generation assets.
(e) Reduction of property tax expense on generation assets.
(f) Interest income on associated company notes receivable from the transfer of generation net assets.
(g) Reduction of earnings on nuclear decommissioning trusts.
(h) Absence in 2006 of adjustment to 2005 allowance for borrowed funds used during construction on generation assets transferred.
(i) Income tax effect of the above adjustments.

Results of Operations

    Earnings on common stock in the first quarter of 2006 increased to $72 million from $13 million in the first quarter of 2006. This increase resulted primarily from lower operating expenses and taxes and increased other income, partially offset by lower operating revenues. These changes were principally a result of the effects of the generation asset transfer shown in the table above.

Operating Revenues

    Operating revenues decreased by $25 million or 5.9% in the first quarter of 2006 from the same period in 2005. Excluding the generation asset transfer effects discussed above, operating revenues increased $43 million due to an $88 million increase in retail generation sales revenues and a $19 million reduction in customer shopping incentives, partially offset by a $44 million decrease in distribution revenues and an $18 million decrease in MSG wholesale sales.

    Retail generation revenues increased $88 million (residential - $38 million, commercial - $32 million and industrial - $18 million) due to increased KWH sales and higher unit prices. The higher unit prices reflected the rate stabilization charge that became effective in January 2006 under the RCP. The increase in generation KWH sales resulted from decreased customer shopping. Generation services provided by alternative suppliers as a percent of total sales deliveries in CEI's service area decreased in all customer classes by the following percentage points: residential - 59.2%, commercial - 38.9% and industrial - 6.3%. The decreased shopping resulted from alternative energy suppliers terminating their supply arrangements with CEI's shopping customers in the fourth quarter of 2005.

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    Non-affiliated wholesale sales revenues decreased by $18 million due to the cessation of the MSG sales arrangements under CEI’s transition plan in December 2005. CEI had been required to provide the MSG to non-affiliated alternative suppliers.

    Revenues from distribution throughput decreased $44 million in the first quarter of 2006 compared with the corresponding quarter in 2005. The decrease in all customer classes (residential - $5 million, commercial - $22 million and industrial - $17 million) primarily reflected lower unit prices and decreased KWH deliveries. The lower unit prices reflected the completion of the generation-related transition cost recovery under CEI’s transition plan in 2005, partially offset by the recovery of MISO costs beginning in 2006 (see Outlook -- Regulatory Matters). The lower KWH distribution deliveries to residential and commercial customers reflected the impact of milder weather conditions in the first quarter of 2006 compared to the same period of 2005.

    Under the Ohio transition plan, CEI had provided incentives to customers to encourage switching to alternative energy providers, reducing CEI's revenues. These revenue reductions, which were deferred for future recovery and did not affect current period earnings, ceased in 2006, resulting in a $19 million revenue increase as discussed above.

    Changes in electric generation sales and distribution deliveries in the first quarter of 2006 from the first quarter of 2005 are summarized in the following table:

Changes in KWH Sales
Increase (Decrease)
Electric Generation:
Retail			46.5	%
Wholesale:
Non-Associated Companies			(94.5	)%
Associated Companies (1)			(64.6	)%
Total Electric Generation Sales			(13.9	)%
Distribution Deliveries:
Residential			(2.3	)%
Commercial			(5.7	)%
Industrial			(3.7	)%
Total Distribution Deliveries			(3.8	)%

⁽¹⁾   Change reflects impact of generation asset transfers.

Operating Expenses and Taxes

    Total operating expenses and taxes decreased by $68 million in the first quarter of 2006 from the same quarter of 2005 principally due to the asset transfer effects as shown in the table above. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category:

Operating Expenses and Taxes - Changes
Increase (Decrease)		(In millions)
Fuel costs		$	1
Purchased power costs			(7	)
Other operating costs			9
Provision for depreciation			5
Amortization of regulatory assets			(22	)
Deferral of new regulatory assets			3
Income taxes			23
Total operating expenses and taxes		$	12

    Lower purchased power costs in the first quarter of 2006 compared to the first quarter of 2005 primarily reflected lower unit prices associated with the new power supply agreement with FES, RCP fuel deferral of $8 million and a purchased power lease credit amortization of $8 million. Under the RCP that was effective January 1, 2006, CEI can defer increased fuel costs (i.e., in excess of 2002 baseline amounts). The amortization is for the above-market lease liability related to an existing Beaver Valley Unit 2 purchased power arrangement with TE. The lease credit amortization had been previously included in CEI's nuclear operating costs and the related nuclear generation KWH purchased from TE had then been sold to FES. Subsequent to the generation asset transfer, CEI now retains this purchased power from TE to meet a portion of its PLR obligation and, consequently, the lease amortization is now included as part of CEI's purchased power costs. These decreases were partially offset by the impact of an increase in KWH purchased to meet the higher retail generation sales requirements. Higher other operating costs reflect increased transmission expenses, primarily related to MISO Day 2 operations that began on April 1, 2005.

 

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    Excluding the effects of the generation asset transfers, the increase in depreciation in the first quarter of 2006 compared with the first quarter of 2005 was attributable to a higher level of depreciable distribution property in 2006. Lower amortization of regulatory assets reflected the completion of generation-related transition cost amortization under CEI’s transition plan, partially offset by the amortization of deferred MISO costs that are being recovered in 2006. The decreased deferral of new regulatory assets was primarily due to the termination of the shopping incentive deferrals ($19 million), partially offset by the RCP deferral of distribution costs and related interest ($15 million) and increased deferred MISO costs ($1 million).

Increased income taxes in the first quarter of 2006 compared to the same period last year were primarily due to an increase in taxable income, partially offset by a reduction in the tax rates due to the continuing phase-out of the income-based Ohio franchise tax.

Other Income

The increase in other income of $14 million was primarily due to interest income on associated company notes receivable from the generation asset transfers discussed above. Excluding the effects of the asset transfer, other income increased $6 million due to the absence in 2006 of $5 million in expenses related to the sales of customer receivables and a $2 million NRC fine related to the Davis-Besse Plant in the first quarter of 2005. The customer receivables sales expenses ceased in 2005 as result of the renewal of the CFC financing arrangement.

Net Interest Charges

    Net interest charges continued to trend lower, decreasing by $1 million in the first quarter of 2006 from the same quarter last year.

Preferred Stock Dividend Requirements

    Preferred stock dividend requirements decreased by $3 million in the first quarter of 2006, compared to the same period last year as a result of the optional redemption of CEI's remaining outstanding preferred stock in 2005.

Capital Resources and Liquidity

During 2006, CEI expects to meet its contractual obligations with cash from operations and short-term credit arrangements. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of March 31, 2006, CEI had $217,000 of cash and cash equivalents, compared with $207,000 as of December 31, 2005. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

    Cash provided from operating activities during the first quarter of 2006, compared with the first quarter of 2005, were as follows:

		Three Months Ended March 31,
Operating Cash Flows		2006			2005
		(in millions)
Cash earnings (1)		$	31		$	13
Working capital and other			94			90
Net cash provided from operating activities		$	125		$	103

(1)

Cash earnings is a non-GAAP measure (see reconciliation below).

 

 

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    Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. CEI believes that cash earnings are a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income:

		Three Months Ended
		March 31,
Reconciliation of Cash Earnings		2006			2005
		(In millions)
Net Income (GAAP)		$	72		$	15
Non-Cash Charges (Credits):
Provision for depreciation			17			31
Amortization of regulatory assets			32			54
Deferral of new regulatory assets			(22	)		(25	)
Nuclear fuel and capital lease amortization			-			4
Amortization of electric service obligation			(4	)		(5	)
Deferred rents and lease market valuation liability			(55	)		(53	)
Deferred income taxes and investment tax credits, net			(1	)		(4	)
Deferred purchased power costs			(8	)		-
Accrued compensation and retirement benefits			-			(4	)
Cash earnings (Non-GAAP)		$	31		$	13

    Net cash provided from operating activities increased by $22 million in the first quarter of 2006 from the first quarter of 2005 as a result of an $18 million increase in cash earnings described above under "Results of Operations" and a $4 million increase from working capital and other cash flows.

Cash Flows from Financing Activities

    Net cash used for financing activities decreased $64 million in the first quarter of 2006 from the first quarter of 2005. The decrease in funds used for financing activities primarily resulted from a $70 million reduction in net preferred stock and debt redemptions, partially offset by an $8 million increase in common stock dividend payments to FirstEnergy.

                 CEI had $29 million of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $304 million of short-term indebtedness as of March 31, 2006. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including through the available bank facility and the utility money pool described below). As of March 31, 2006, CEI had the capability to issue $129 million of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture. The issuance of FMB by CEI is subject to a provision of its senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, CEI is permitted under the indenture to incur additional secured debt not otherwise permitted by a specified exception of up to $576 million as of March 31, 2006. CEI has no restrictions on the issuance of preferred stock.

    CFC is a wholly owned subsidiary of CEI whose borrowings are secured by customer accounts receivable purchased from CEI and TE. CFC can borrow up to $200 million under a receivables financing arrangement. As a separate legal entity with separate creditors, CFC would have to satisfy its obligations to creditors before any of its remaining assets could be made available to CEI. As of March 31, 2006, the facility was drawn for $94 million.

    CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2006 was 4.58%.

CEI, FirstEnergy, OE, Penn, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility through a syndicate of banks that expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing and the commitment expiration date, as the same may be extended. CEI’s borrowing limit under the facility is $250 million subject to applicable regulatory approvals.

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Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding LOC will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, CEI's debt to total capitalization as defined under the revolving credit facility was 52%.

The facility does not contain any provisions that either restrict CEI's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to CEI's credit ratings.

    CEI’s access to the capital markets and the costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from S&P on all such securities is stable. The ratings outlook from Moody's and Fitch on all securities is positive.

In April and May of 2006, pollution control notes that were formerly obligations of CEI were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of their associated company notes payable to CEI. CEI redeemed $117.8 million of pollution control notes having variable interest rates.

Cash Flows from Investing Activities

    Net cash used for investing activities was $4 million in the first quarter of 2006 compared to net cash provided from investing activities of $82 million in the first quarter of 2005. The change was primarily due to increased loans to associated companies, partially offset by a reduction in investments in lessor notes.

    CEI’s capital spending for the last three quarters of 2006 is expected to be about $85 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. CEI’s capital spending for the period 2006-2010 is expected to be about $615 million of which approximately $122 million applies to 2006.

Off-Balance Sheet Arrangements

 

    Obligations not included on CEI’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of March 31, 2006, the present value of these operating lease commitments, net of trust investments, total $96 million.

Outlook

The electric industry continues to transition to a more competitive environment and all of CEI’s customers can select alternative energy suppliers. CEI continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.

Regulatory Matters

Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered under the provisions of CEI’s transition plan. CEI’s regulatory assets as of March 31, 2006 and December 31, 2005, were $858 million and $862 million, respectively.

        On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.

 

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        Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from the CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised RSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.

On January 4, 2006, the PUCO approved, with modifications, CEI’s RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

 

	·	Maintaining the existing level of base distribution rates through April 30, 2009 for CEI;
	·	Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred by all of the Ohio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;
	·	Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2010 for CEI;
	·	Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $85 million for CEI by accelerating the application of its accumulated cost of removal regulatory liability; and
	·	Deferring and capitalizing (for recovery over a 25-year period) increased fuel costs above the amount collected through the Ohio Companies’ fuel recovery mechanism (in lieu of implementation of the GCAF rider).

 

The following table provides CEI’s estimated amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2010:

Amortization
Period		Amortization
		(In millions)
2006		$	97
2007			113
2008			130
2009			211
2010			263
Total Amortization		$	814

The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to:

 

	·	Recognize fuel and distribution deferrals commencing January 1, 2006;
	·	Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;

 

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	·	Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and
	·	Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred.

 

The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.

On December 30, 2004, CEI filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. CEI requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 30, 2006 are approximately $24 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, CEI filed a modification to the rider to determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for CEI to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized CEI to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of CEI's case with a similar case involving Dayton Power & Light Company. Oral argument is currently scheduled for May 10, 2006.

On January 20, 2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and CEI will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of CEI's case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio competitive bid process, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of the April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for future consideration on March 1, 2006.

See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

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Environmental Matters

CEI accrues environmental liabilities when it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in CEI’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Regulation of Hazardous Waste

        CEI has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2006, based on estimates of the total costs of cleanup, CEI’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $1.7 million as of March 31, 2006.

        See Note 10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

Power Outages and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO’s underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for rehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of potential liability is available for any of these cases. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. Following the PUCO's March 7, 2006 order, that action was voluntarily dismissed by the claimants.

 

 

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FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.

Other Legal Matters-

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to CEI’s normal business operations pending against CEI and its subsidiaries. The other potentially material items not otherwise discussed above are described below.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 10 (C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

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New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, CEI will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on CEI's financial results.

SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

    In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. CEI is currently evaluating the impact of this Statement on its financial statements.

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THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
STATEMENTS OF INCOME		(In thousands)
OPERATING REVENUES		$	217,977		$	241,755
OPERATING EXPENSES AND TAXES:
Fuel			9,762			12,569
Purchased power			72,418			80,156
Nuclear operating costs			17,332			59,163
Other operating costs			40,425			34,348
Provision for depreciation			8,097			14,680
Amortization of regulatory assets			24,456			34,865
Deferral of new regulatory assets			(10,654	)		(9,424	)
General taxes			12,931			14,181
Income taxes (benefit)			14,418			(3,968	)
Total operating expenses and taxes			189,185			236,570
OPERATING INCOME			28,792			5,185
OTHER INCOME (net of income taxes)			4,310			2,659
NET INTEREST CHARGES:
Interest on long-term debt			2,790			4,220
Allowance for borrowed funds used during construction			(214	)		443
Other interest expense			1,520			2,816
Net interest charges			4,096			7,479
NET INCOME			29,006			365
PREFERRED STOCK DIVIDEND REQUIREMENTS			1,275			2,211
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK		$	27,731		$	(1,846	)
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME		$	29,006		$	365
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized loss on available for sale securities			(1,138	)		(1,683	)
Income tax benefit related to other comprehensive income			411			695
Other comprehensive loss, net of tax			(727	)		(988	)
TOTAL COMPREHENSIVE INCOME (LOSS)		$	28,279		$	(623	)
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.

 

 

 

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THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,			December 31,
		2006			2005
		(In thousands)
ASSETS
UTILITY PLANT:
In service		$	834,124		$	824,677
Less - Accumulated provision for depreciation			377,586			372,845
			456,538			451,832
Construction work in progress			36,277			33,920
			492,815			485,752
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes			169,463			178,798
Nuclear plant decommissioning trusts			58,458			59,209
Long-term notes receivable from associated companies			436,446			436,178
Other			1,770			1,781
			666,137			675,966
CURRENT ASSETS:
Cash and cash equivalents			15			15
Receivables-
Customers			751			2,209
Associated companies			28,275			16,311
Other			4,697			6,410
Notes receivable from associated companies			59,681			48,349
Prepayments and other			693			1,059
			94,112			74,353
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			500,576			501,022
Regulatory assets			275,671			287,095
Prepaid pension costs			35,345			35,566
Property taxes			18,047			18,047
Other			40,988			24,164
			870,627			865,894
		$	2,123,691		$	2,101,965
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, $5 par value, authorized 60,000,000 shares -
39,133,887 shares outstanding		$	195,670		$	195,670
Other paid-in capital			473,894			473,638
Accumulated other comprehensive income			3,963			4,690
Retained earnings			192,159			189,428
Total common stockholder's equity			865,686			863,426
Preferred stock			66,000			96,000
Long-term debt			237,722			237,753
			1,169,408			1,197,179
CURRENT LIABILITIES:
Currently payable long-term debt			53,650			53,650
Accounts payable-
Associated companies			30,004			46,386
Other			3,085			2,672
Notes payable to associated companies			120,228			64,689
Accrued taxes			69,745			49,344
Lease market valuation liability			24,600			24,600
Other			43,281			40,049
			344,593			281,390
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			213,298			221,149
Accumulated deferred investment tax credits			11,622			11,824
Lease market valuation liability			237,250			243,400
Retirement benefits			41,242			40,353
Asset retirement obligation			25,252			24,836
Deferred revenues - electric service programs			30,374			32,606
Other			50,652			49,228
			609,690			623,396
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	2,123,691		$	2,101,965
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of
these balance sheets.

 

 

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THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
		(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	29,006		$	365
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			8,097			14,680
Amortization of regulatory assets			24,456			34,865
Deferral of new regulatory assets			(10,654	)		(9,424	)
Nuclear fuel and capital lease amortization			-			4,868
Deferred rents and lease market valuation liability			(16,084	)		(15,224	)
Deferred income taxes and investment tax credits, net			(8,453	)		(1,387	)
Deferred purchased power costs			(3,002	)		-
Accrued compensation and retirement benefits			1,110			(654	)
Decrease (increase) in operating assets-
Receivables			(8,793	)		41,475
Materials and supplies			-			(6,489	)
Prepayments and other current assets			366			(56	)
Increase (decrease) in operating liabilities-
Accounts payable			(15,969	)		6,935
Accrued taxes			20,401			(15,262	)
Accrued interest			(668	)		853
Electric service prepayment programs			(2,231	)		-
Other			(121	)		(1,989	)
Net cash provided from operating activities			17,461			53,556
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net			55,539			-
Redemptions and Repayments-
Preferred stock			(30,000	)		-
Short-term borrowings, net			-			(34,993	)
Dividend Payments-
Common stock			(25,000	)		-
Preferred stock			(1,275	)		(2,211	)
Net cash used for financing activities			(736	)		(37,204	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(15,044	)		(17,919	)
Loans to associated companies			(11,270	)		(1,610	)
Investments in lessor notes			9,335			11,928
Proceeds from nuclear decommissioning trust fund sales			13,793			106,009
Investments in nuclear decommissioning trust funds			(13,793	)		(113,144	)
Other			254			(1,616	)
Net cash used for investing activities			(16,725	)		(16,352	)
Net change in cash and cash equivalents			-			-
Cash and cash equivalents at beginning of period			15			15
Cash and cash equivalents at end of period		$	15		$	15
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral
part of these statements.

 

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Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of March 31, 2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) and Note 11 to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2006

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THE TOLEDO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

 

    TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE’s power supply requirements are provided by FES - an affiliated company.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively. The generating plant interests transferred did not include TE's leasehold interests in certain of the plants that are currently subject to sale and leaseback arrangements with non-affiliates.

On October 24, 2005, TE completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, TE completed the intra-system transfer of its ownership interests in the nuclear generation assets to NGC through a sale at net book value. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

        The transfers will affect TE’s near-term results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which TE previously sold its nuclear-generated KWH to FES and leased its non-nuclear generation assets to FGCO, a subsidiary of FES. TE’s expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. With respect to TE's retained leashold interests in the Bruce Mansfield Plant and Beaver Valley Unit 2, TE has continued the generation KWH sales arrangement with FES and continues to be obligated on the applicable portion of expenses related to those interests. In addition, TE receives interest income on associated company notes receivable from the transfer of its generation net assets. FES will continue to provide TE’s PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 (see Outlook - Regulatory Matters).

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The effects on TE’s results of operations in the first quarter of 2006 compared to the first quarter of 2005 from the generation asset transfers are summarized in the following table:

Intra-System Generation Asset Transfers -
First Quarter 2006 vs First Quarter 2005 Income Statement Effects
Increase (Decrease)		(In millions)
Operating Revenues:
Non-nuclear generating units rent		$	(4	) (a)
Nuclear generated KWH sales			(22	) (b)
Total - Operating Revenues Effect			(26	)
Operating Expenses and Taxes:
Fuel costs - nuclear			(4	) (c)
Nuclear operating costs			(39	) (c)
Provision for depreciation			(8	) (d)
General taxes			(1	) (e)
Income taxes			11	(i)
Total- Operating Expenses and Taxes Effect			(41	)
Operating Income Effect			15
Other Income:
Interest income from notes receivable			4	(f)
Nuclear decommissioning trust earnings			(1	) (g)
Income taxes			(1	) (i)
Total-Other Income Effect			2
Net interest Charges:
Allowance for funds used during construction			1
Total-Net Interest Charges Effect			(1	) (h)
Net Income Effect		$	18
(a) Elimination of non-nuclear generation assets lease to FGCO.
(b) Reduction of nuclear generated wholesale KWH sales to FES.
(c) Reduction of nuclear fuel and operating costs.
(d) Reduction of depreciation expense and asset retirement obligation accretion related to   generation assets.
(e) Reduction of property tax expense on generation assets.
(f) Interest income on associated company notes receivable from the transfer of
generation net assets.
(g) Reduction of earnings on nuclear decommissioning trusts.
(h) Absence in 2006 of adjustment to 2005 allowance for borrowed funds used during construction on generation assets transferred.
(i) Income tax effect of the above adjustments.

Results of Operations

    Earnings applicable to common stock in the first quarter of 2006 increased to $28 million from a loss of $2 million in the first quarter of 2005. This increase resulted primarily from reduced operating expenses and taxes, reduced net interest charges and increased other income, which was partially offset by lower operating revenues. These changes were principally from the effects of the generation asset transfer shown in the table above.

Operating Revenues

    Operating revenues decreased by $24 million or 9.8% in the first quarter of 2006 compared with the same period of 2005, primarily due to the generation asset transfer impact shown in the table above. Excluding the asset transfer effects, operating revenues increased $2 million due to a $27 million increase in retail generation sales revenues and a $6 million reduction in customer shopping incentives, partially offset by a $27 million decrease in distribution revenues and a $4 million decrease in wholesale sales to non-affiliates.

    Retail generation revenues increased $27 million with increases in all customer classes (residential - $16 million, commercial - $9 million and industrial - $2 million) due to higher unit prices and increased KWH sales. The higher unit prices reflected the rate stabilization charge and fuel cost recovery rider that became effective in January 2006 under the RCP. The increase in generation KWH sales (residential - 37.6%, commercial - 11.7% and industrial - 0.5%) primarily resulted from decreased customer shopping. The decreased shopping resulted from alternative energy suppliers terminating their supply arrangements with TE's shopping customers in the first quarter of 2006. Generation services provided by alternative suppliers as a percent of total sales deliveries in TE's franchise area decreased in all customer classes by the following percentage points : residential - 24.3%, commercial - 8.5% and industrial - 1.4%.

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    The lower non-affiliated wholesale revenues reflected a decrease in sales to municipal customers ($1 million) and a $3 million decrease due to the cessation of the MSG sales arrangements under TE’s transition plan in December 2005. TE had been required to provide the MSG to non-affiliated alternative suppliers.

    Revenues from distribution throughput decreased by $27 million in the first quarter of 2006 from the corresponding quarter of 2005. The decrease in all customer sectors (residential - $12 million; commercial - $13 million; and industrial - $1 million) primarily reflected lower unit prices and decreased KWH deliveries. The lower unit prices reflected the completion of the generation-related transition cost recovery under TE’s transition plan in 2005, partially offset by the recovery of MISO costs beginning in 2006 (see Outlook - Regulatory Matters). The lower KWH distribution deliveries to residential and commercial customers reflected the impact of milder weather in the first quarter of 2006 compared to the same period of 2005.

    Under the Ohio transition plan, TE had provided incentives to customers to encourage switching to alternative energy providers, reducing TE's revenues. These revenue reductions, which were deferred for future recovery and did not affect current period earnings, ceased in 2006 and resulted in a $6 million change in revenues as discussed above. The deferred shopping incentives (Extended RTC) are currently being recovered under the RCP (see Outlook - Regulatory Matters).

    Changes in electric generation sales and distribution deliveries in the first quarter of 2006 from the first quarter of 2005 are summarized in the following table:

Changes in KWH Sales
Increase (Decrease)
Electric Generation:
Retail			9.7	%
Wholesale:
Non-Associated Companies			(40.3	)%
Associated Companies (1)			(57.7	)%
Total Electric Generation Sales			(23.1	)%
Distribution Deliveries:
Residential			(1.3	)%
Commercial			(3.8	)%
Industrial			(0.9	)%
Total Distribution Deliveries			(2.0	)%

⁽¹⁾   Change reflects impact of generation asset transfers.

Operating Expenses and Taxes

    Total operating expenses and taxes decreased by $47 million in the first quarter of 2006 from the same quarter of 2005 principally due to the generation asset transfer effects as shown in the table above. Excluding the asset transfer effects, the following table presents changes from the prior year by expense category:

Operating Expenses and Taxes - Changes
Increase (Decrease)		(In millions)
Purchased power costs		$	(8	)
Nuclear operating costs			(2	)
Other operating costs			6
Provision for depreciation			2
Amortization of regulatory assets			(10	)
Deferral of new regulatory assets			(1	)
Income taxes			7
Total operating expenses and taxes		$	(6	)

    Lower purchased power costs in the first quarter of 2006 compared to the first quarter of 2005 reflected lower unit prices associated with the new power supply agreement with FES and the RCP fuel cost deferrals of $3 million that began in 2006, partially offset by an increase in KWH purchased to meet the higher retail generation sales requirements. Decreased nuclear operating costs in the 2006 period were due to lower costs associated with TE’s leasehold interest in Beaver Valley Unit 2. The first quarter of 2005 included costs related to preparations for the refueling outage which began April 4, 2005. Higher other operating costs reflect increased transmission expenses, primarily related to MISO Day 2 operations that began on April 1, 2005.

    Excluding the effects of the generation asset transfers, depreciation charges increased due to distribution plant additions.

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    Lower amortization of regulatory assets reflected the completion of generation-related transition cost recovery under TE’s transition plan, partially offset by the amortization of deferred MISO costs that are being recovered in 2006. As discussed above, the RCP transition costs amortization includes the amortization of the deferred shopping incentives, which began in 2006. The net change in deferrals of new regulatory assets primarily resulted from the deferral of distribution costs and related interest ($6.1 million) under the RCP and deferrals of the 2006 MISO transmission costs and related interest ($1.7 million), partially offset by the termination of shopping incentive deferrals and interest ($6.4 million) in 2006.

    Increased income taxes in the first quarter of 2006 were primarily due to an increase in taxable income partially offset by a reduction in the tax rates due to the continuing phase-out of the income-based Ohio franchise tax.

Other Income

    Other income increased $1.7 million in the first quarter of 2006, compared to the same period of 2005. Excluding the effects of the generation asset transfer, other income decreased $0.3 million. The decrease reflected the absence in 2006 of $2.4 million of interest income from a 2001 FGCO note (which had a balloon repayment in May 2005) partially offset by the accrual of a $1.6 million NRC fine related to the Davis-Besse Plant in the first quarter of 2005.

Net Interest Charges

    Excluding the effects of the asset transfer, net interest charges continued to trend lower, decreasing by $3 million in the first quarter of 2006 from the same period of 2005, reflecting redemptions and refinancing subsequent to the end of the first quarter of 2005.

Capital Resources and Liquidity

    During 2006, TE expects to meet its contractual obligations with a combination of cash from operations and short-term credit arrangements. In connection with a plan to realign its capital structure, TE may issue up to $100 million of new long-term debt in 2006 with proceeds expected to fund a return of equity capital to FirstEnergy.

Changes in Cash Position

    There was no change as of March 31, 2006 from December 31, 2005 in TE's cash and cash equivalents of $15,000.

Cash Flows From Operating Activities

    Cash provided from operating activities during the first quarter of 2006, compared with the first quarter of 2005 were as follows:

		Three Months Ended March 31,
Operating Cash Flows		2006			2005
		(In millions)
Cash earnings (1)		$	21		$	28
Working capital and other			(3	)		26
Net cash provided from operating activities		$	18		$	54

⁽¹⁾   Cash earnings is a non-GAAP measure (see reconciliation below).

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    Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. TE believes that cash earnings are a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income:

		Three Months Ended March 31,
Reconciliation of Cash Earnings		2006			2005
		(In millions)
Net Income (GAAP)		$	29		$	-
Non-Cash Charges (Credits):
Provision for depreciation			8			15
Amortization of regulatory assets			24			35
Deferral of new regulatory assets			(11	)		(9	)
Nuclear fuel and capital lease amortization			-			5
Amortization of electric service obligation			(2	)		-
Deferred rents and lease market valuation liability			(16	)		(15	)
Deferred income taxes and investment tax credits, net			(8	)		(2	)
Deferred purchased power costs			(3	)		-
Accrued compensation and retirement benefits			-			(1	)
Cash earnings (Non-GAAP)		$	21		$	28

    Net cash provided from operating activities decreased by $36 million in the first quarter of 2006 from the first quarter of 2005 as a result of a $7 million decrease in cash earnings described above under “Results of Operations” and a $29 million decrease from working capital. The change in working capital was primarily due to a $50 million decrease in cash provided from the settlement of receivables and $23 million of increased outflows for accounts payable, partially offset by changes in accrued taxes of $36 million.

Cash Flows From Financing Activities

 

    Net cash used for financing activities decreased by $36 million in the first quarter of 2006, as compared to the same period of 2005. The decrease resulted from a $91 million increase in net short-term borrowings, partially offset by $30 million of preferred stock redemptions and $25 million of common stock dividends to FirstEnergy in 2006.

    On January 20, 2006, TE redeemed all 1.2 million of its outstanding shares of Adjustable Preferred Rate Series B preferred stock at $25.00 per share, plus accrued dividends to the date of redemption.

    TE had $60 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $120 million of short-term indebtedness as of March 31, 2006. TE has authorization from the PUCO to incur short-term debt of up to $500 million (including through the available bank facility and the utility money pool described below). As of March 31, 2006, TE had the capability to issue $628 million of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture. Based upon applicable earnings coverage tests, TE could issue up to $1.5 billion of preferred stock (assuming no additional debt) was issued as of March 31, 2006.

    TE, FirstEnergy, OE, Penn, CEI, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility with a syndicate of banks that expires in June 2010. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment expiration date, as the same may be extended. TE’s borrowing limit under the facility is $250 million subject to applicable regulatory approval.

    Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.

    The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, TE's debt to total capitalization, as defined under the revolving credit facility, was 31%.

    The facility does not contain any provisions that either restrict TE's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to TE's credit ratings.

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    TE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2006 was 4.58%.

    TE’s access to the capital markets and the costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook from S&P on all securities is stable. The ratings outlook from Moody’s and Fitch on all securities is positive.

In April 2006, pollution control notes that were formerly obligations of TE were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of their associated company notes payable to TE.  With those repayments, TE redeemed pollution control notes in the aggregate principal amount of $54 million having variable interest rates.

Cash Flows From Investing Activities

    Net cash used for investing activities was effectively unchanged in the first quarter of 2006 compared to the same period of 2005. Decreases in property additions and net activity for the nuclear decommissioning trust funds were offset by increased loans to associated companies.

 

    TE’s capital spending for the last three quarters of 2006 is expected to be about $47 million. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term capital markets (up to $100 million) and short-term credit arrangements. TE’s capital spending for the period 2006-2010 is expected to be about $236 million of which approximately $62 million applies to 2006.

Off-Balance Sheet Arrangements

    Obligations not included on TE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of March 31, 2006, the present value of these operating lease commitments, net of trust investments, totaled $535 million.

OUTLOOK

 

The electric industry continues to transition to a more competitive environment and all of TE’s customers can select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. TE has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.

Regulatory Matters

 

Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered under the provisions of TE’s regulatory plans. TE’s regulatory assets as of March 31, 2006 and December 31, 2005 were $276 million and $287 million, respectively.

        On October 21, 2003 the Ohio Companies filed the RSP case with the PUCO. On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a CBP. The RSP was intended to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral arguments on the appeals. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming that order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the grant of interest on shopping credit incentive deferral amounts, and approval of FirstEnergy’s financial separation plan. It remanded the approval of the RSP pricing back to the PUCO for further consideration of the issue as to whether the RSP, as adopted by the PUCO, provided for sufficient customer participation in the competitive marketplace.

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        Under provisions of the RSP, the PUCO had required the Ohio Companies to undertake a CBP to secure generation and allow for customer pricing participation in the competitive marketplace. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until 12 months after the PUCO authorizes such termination. On December 9, 2004, the PUCO rejected the auction price results from the CBP for the generation supply period beginning January 1, 2006 and issued an entry stating that the pricing under the approved revised RSP would take effect on January 1, 2006. On February 23, 2006 the CBP auction manager, National Economic Research Associates, notified the PUCO that a subsequent CBP to potentially provide firm generation service for the Ohio Companies' 2007 and 2008 actual load requirements could not proceed due to lack of interest, as there were no bidder applications submitted. Additionally, on March 20, 2006, the PUCO denied applications for rehearing filed by various parties regarding the PUCO's rules for the CBP. The above May 3, 2006 Supreme Court of Ohio opinion may require the PUCO to reconsider this customer pricing process.

On January 4, 2006, the PUCO approved, with modifications, TE's RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

·

Maintaining the existing level of base distribution rates through December 31, 2008 for TE;

·

Deferring and capitalizing for future recovery (over a 25-year period) with carrying charges certain distribution costs to be incurred by all the Ohio Companies during the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three years;

·

Adjusting the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized costs will occur as of December 31, 2008 for TE;

·

Reducing the deferred shopping incentive balances as of January 1, 2006 by up to $45 million for TE by accelerating the application of its accumulated cost of removal regulatory liability; and

·

Recovering increased fuel costs (compared to a 2002 baseline) of up to $75 million, $77 million, and $79 million, in 2006, 2007, and 2008, respectively, from all OE and TE distribution and transmission customers through a fuel recovery mechanism. The Ohio Companies may defer and capitalize (for recovery over a 25-year period) increased fuel costs above the amount collected through the fuel recovery mechanism (in lieu of implementation of the GCAF rider).

The following table provides the estimated amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2006 through 2008:

Amortization
Period		Amortization
		(In millions)
2006		$	83
2007			90
2008			108
Total Amortization		$	281

The PUCO’s January 4, 2006 approval of the RCP also included approval of the Ohio Companies’ supplemental stipulation which was filed with the PUCO on November 4, 2005 and which was an additional component of the RCP filed on September 9, 2005. On January 10, 2006, the Ohio Companies filed a Motion for Clarification of the PUCO order approving the RCP. The Ohio Companies sought clarity on issues related to distribution deferrals, including requirements of the review process, timing for recognizing certain deferrals and definitions of the types of qualified expenditures. The Ohio Companies also sought confirmation that the list of deferrable distribution expenditures originally included in the revised stipulation fall within the PUCO order definition of qualified expenditures. On January 25, 2006, the PUCO issued an Entry on Rehearing granting in part, and denying in part, the Ohio Companies’ previous requests and clarifying issues referred to above. The PUCO granted the Ohio Companies’ requests to:

 

	·	Recognize fuel and distribution deferrals commencing January 1, 2006;
	·	Recognize distribution deferrals on a monthly basis prior to review by the PUCO Staff;
	·	Clarify that the types of distribution expenditures included in the Supplemental Stipulation may be deferred; and
	·	Clarify that distribution expenditures do not have to be “accelerated” in order to be deferred.

 

 

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The PUCO approved the Ohio Companies’ methodology for determining distribution deferral amounts, but denied the Motion in that the PUCO Staff must verify the level of distribution expenditures contained in current rates, as opposed to simply accepting the amounts contained in the Ohio Companies’ Motion. On February 3, 2006, several other parties filed applications for rehearing on the PUCO's January 4, 2006 Order. The Ohio Companies responded to the applications for rehearing on February 13, 2006. In an Entry on Rehearing issued by the PUCO on March 1, 2006, all motions for rehearing were denied. Certain of these parties have subsequently filed their notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP.

On December 30, 2004, TE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application sought recovery of these costs beginning January 1, 2006. TE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The parties reached a settlement agreement that was approved by the PUCO on August 31, 2005. The incremental transmission and ancillary service revenues expected to be recovered from January through June 2006 are approximately $8 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. On May 1, 2006, TE filed a modification to the rider to determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for TE to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized TE to accrue carrying charges on the deferred balances. On August 31, 2005, the OCC appealed the PUCO's decision. All briefs have been filed. On March 20, 2006, the Ohio Supreme Court, on its own motion, consolidated the OCC's appeal of TE's case with a similar case involving Dayton Power & Light Company. Oral argument is currently scheduled for May 10, 2006.

On January 20, 2006 the OCC sought rehearing of the PUCO approval of the recovery of deferred costs through the rider during the period January 1, 2006 through June 30, 2006. The PUCO denied the OCC's application on February 6, 2006. On March 23, 2006, the OCC appealed the PUCO's order to the Ohio Supreme Court. The OCC's brief is expected to be filed during the second quarter of 2006. The briefs of the PUCO and TE will be due within thirty days of the OCC's filing. On March 27, 2006, the OCC filed a motion to consolidate this appeal with the deferral appeals discussed above and to postpone oral arguments in the deferral appeal until after all briefs are filed in this most recent appeal of the rider recovery mechanism. On April 18, 2006, the Court denied both parts of the motion but on its own motion consolidated the OCC's appeal of TE's case with a similar case of Dayton Power & Light Company and stayed briefing on these appeals.

On November 1, 2005, FES filed two power sales agreements for approval with the FERC. One power sales agreement provided for FES to provide the PLR requirements of the Ohio Companies at a price equal to the retail generation rates approved by the PUCO for a period of three years beginning January 1, 2006. The Ohio Companies will be relieved of their obligation to obtain PLR power requirements from FES if the Ohio competitive bid process results in a lower price for retail customers. A similar power sales agreement between FES and Penn permits Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. The PPUC approved Penn's plan with modifications on April 20, 2006 to use an RFP process to obtain its power supply requirements after 2006.

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticized the Ohio competitive bid process, and required FES to submit additional evidence in support of the reasonableness of the prices charged in the power sales agreements. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of the April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for future consideration on March 1, 2006.

See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Environmental Matters

    TE accrues environmental liabilities when it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in TE’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

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Regulation of Hazardous Waste

TE has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2006, based on estimates of the total costs of cleanup, TE’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $0.2 million as of March 31, 2006.

See Note 10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to TE’s normal business operations pending against TE. The other potentially material items not otherwise discussed above are described below.

Power Outages and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Company, Inc. as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. On March 7, 2006, the PUCO issued a ruling applicable to all pending cases. Among its various rulings, the PUCO consolidated all of the pending outage cases for hearing; limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy Corp. as a defendant; ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence; and gave the plaintiffs additional time to amend their complaints to otherwise comply with the PUCO's underlying order. The plaintiffs in one case have since filed an amended complaint. The named FirstEnergy companies have answered and also have filed a motion to dismiss the action, which is pending. Also, most complainants, along with the FirstEnergy companies, filed applications for rehearing with the PUCO over various rulings contained in the March 7, 2006 order. On April 26, 2006, the PUCO granted rehearing to allow the insurance company claimants, as insurers, to prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities which provide their service. The PUCO denied all other motions for rehearing. No estimate of potential liability is available for any of these cases. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. Following the PUCO's March 7, 2006 order, that action was voluntarily dismissed by the claimants.

 

 

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    FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

Other Legal Matters-

 

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse related disclosures, which FirstEnergy has provided. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

The City of Huron filed a complaint against OE with the PUCO challenging the ability of electric distribution utilities to collect transition charges from a customer of a newly formed municipal electric utility. The complaint was filed on May 28, 2003, and OE timely filed its response on June 30, 2003. In a related filing, the Ohio Companies filed for approval with the PUCO a tariff that would specifically allow the collection of transition charges from customers of municipal electric utilities formed after 1998. An adverse ruling could negatively affect full recovery of transition charges by the utility. Hearings on the matter were held in August 2005. Initial briefs from all parties were filed on September 22, 2005 and reply briefs were filed on October 14, 2005. It is unknown when the PUCO will decide this case.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 10(C) to the consolidated financial statements for further details and a complete discussion of these and other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

 

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, TE will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on TE's financial results.

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SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

    In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. TE is currently evaluating the impact of this Statement on its financial statements.

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PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
STATEMENTS OF INCOME		(In thousands)
OPERATING REVENUES		$	82,719		$	134,484
OPERATING EXPENSES AND TAXES:
Fuel			-			5,620
Purchased power			54,756			46,980
Nuclear operating costs			-			19,948
Other operating costs			14,204			12,768
Provision for depreciation			2,431			3,694
Amortization of regulatory assets			3,411			9,882
General taxes			5,834			6,472
Income taxes (benefit)			(251	)		12,421
Total operating expenses and taxes			80,385			117,785
OPERATING INCOME			2,334			16,699
OTHER INCOME (EXPENSE) (net of income taxes)			2,333			(745	)
NET INTEREST CHARGES:
Interest on long term debt			1,246			2,054
Allowance for borrowed funds used during construction			(34	)		(1,367	)
Other interest expense			2,709			265
Net interest charges			3,921			952
NET INCOME			746			15,002
PREFERRED STOCK DIVIDEND REQUIREMENTS			156			640
EARNINGS ON COMMON STOCK		$	590		$	14,362
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME		$	746		$	15,002
OTHER COMPREHENSIVE INCOME			-			-
TOTAL COMPREHENSIVE INCOME		$	746		$	15,002
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are
an integral part of these statements.

 

 

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PENNSYLVANIA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,			December 31,
		2006			2005
		(In thousands)
ASSETS
UTILITY PLANT:
In service		$	364,663		$	359,069
Less - Accumulated provision for depreciation			130,346			129,118
			234,317			229,951
Construction work in progress-
Electric plant			2,301			3,775
			236,618			233,726
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies			283,125			283,248
Other			351			351
			283,476			283,599
CURRENT ASSETS:
Cash and cash equivalents			41			24
Notes receivable from associated companies			10,833			1,699
Receivables -
Customers (less accumulated provisions of $1,092,000 and $1,087,000,
respectively, for uncollectible accounts)			39,510			44,555
Associated companies			80,186			115,441
Other			1,239			2,889
Prepayments and other			22,561			86,995
			154,370			251,603
DEFERRED CHARGES AND OTHER ASSETS:
Prepaid pension costs			42,649			42,243
Other			1,955			3,829
			44,604			46,072
		$	719,068		$	815,000
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity
Common stock, $30 par value, authorized 6,500,000 shares-
6,290,000 shares outstanding		$	188,700		$	188,700
Other paid in capital			71,136			71,136
Retained earnings			37,687			37,097
Preferred stock			14,105			14,105
Long-term debt and other long-term obligations			123,807			130,677
			435,435			441,715
CURRENT LIABILITIES:
Currently payable long-term debt			22,424			69,524
Short-term borrowings -
Associated companies			-			12,703
Other			19,000			-
Accounts payable -
Associated companies			20,538			73,444
Other			1,666			1,828
Accrued taxes			32,806			28,632
Accrued interest			1,059			1,877
Other			6,620			8,086
			104,113			196,094
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			63,683			66,576
Retirement benefits			46,429			45,967
Regulatory liabilities			63,781			58,637
Other			5,627			6,011
			179,520			177,191
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	719,068		$	815,000
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets.

 

 

 

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PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
		(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	746		$	15,002
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			2,431			3,694
Amortization of regulatory assets			3,411			9,882
Nuclear fuel and other amortization			-			4,140
Deferred income taxes and investment tax credits, net			(2,348	)		(2,311	)
Decrease (increase) in operating assets-
Receivables			41,950			11,892
Materials and supplies			-			218
Prepayments and other current assets			64,433			(13,481	)
Increase (decrease) in operating liabilities-
Accounts payable			(53,068	)		(2,890	)
Accrued taxes			4,175			11,420
Accrued interest			(819	)		(258	)
Other			1,607			778
Net cash provided from operating activities			62,518			38,086
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net			6,297			-
Redemptions and Repayments-
Long-term debt			(54,462	)		-
Short-term borrowings, net			-			(1,208	)
Dividend Payments-
Common stock			-			(8,000	)
Preferred stock			(156	)		(640	)
Net cash used for financing activities			(48,321	)		(9,848	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(5,114	)		(28,522	)
Proceeds from nuclear decommissioning trust fund sales			-			13,703
Investments in nuclear decommissioning trust funds			-			(14,102	)
Loans to associated companies			(9,010	)		(19	)
Other			(56	)		702
Net cash used for investing activities			(14,180	)		(28,238	)
Net change in cash and cash equivalents			17			-
Cash and cash equivalents at beginning of period			24			38
Cash and cash equivalents at end of period		$	41		$	38
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral
part of these statements.

 

 

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Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Pennsylvania Power Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Power Company and its subsidiary as of March 31, 2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) and Note 8 to those consolidated financial statements) dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2006

 

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PENNSYLVANIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

    Penn is a wholly owned, electric utility subsidiary of OE. Penn conducts business in western Pennsylvania, providing regulated electric distribution services. Penn also provides generation services to those customers electing to retain Penn as their power supplier. Penn's rate restructuring plan and its associated transition charge revenue recovery was completed in 2005. Its power supply requirements are provided by FES - an affiliated company.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn, and on May 18, 2005, the Ohio Companies, entered into certain agreements implementing a series of intra-system generation asset transfers that were completed in the fourth quarter of 2005. The asset transfers resulted in the respective undivided ownership interests of the Ohio Companies and Penn in FirstEnergy’s nuclear and non-nuclear generation assets being owned by NGC and FGCO, respectively.

On October 24, 2005, Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to FGCO's purchase option under the Master Facility Lease.

On December 16, 2005, Penn completed the intra-system transfer of its ownership interests in the nuclear generation assets to NGC through an asset spin-off in the form of a dividend. FENOC continues to operate and maintain the nuclear generation assets.

These transactions were undertaken pursuant to the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. The transactions essentially completed the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO without impacting the operation of the plants.

    The transfers will affect Penn’s near-term results with reductions in both revenues and expenses. Revenues are reduced due to the termination of certain arrangements with FES, under which Penn previously sold its nuclear-generated KWH to FES and leased its non-nuclear generation assets to FGCO, a subsidiary of FES. Penn’s expenses are lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. In addition, Penn receives interest income on associated company notes receivable from the transfer of its generation net assets. FES will continue to provide Penn’s PLR requirements under revised purchased power arrangements for the three-year period beginning January 1, 2006 (see Outlook -- Regulatory Matters).

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The effects on Penn’s results of operations in the first quarter of 2006 compared to the first quarter of 2005 from the generation asset transfers are summarized in the following table:

 

Intra-System Generation Asset Transfers
First Quarter 2006 vs. First Quarter 2005 Income Statement Effects
Increase (Decrease)		(In millions)
Operating Revenues:
Non-nuclear generating units rent		$	(5	)	(a)
Nuclear generated KWH sales			(39	)	(b)
Total - Operating Revenues Effect			(44	)
Operating Expenses and Taxes:
Fuel costs - nuclear			(6	)	(c)
Nuclear operating costs			(20	)	(c)
Provision for depreciation			(2	)	(d)
Income taxes			(7	)	(g)
Total- Operating Expenses and Taxes Effect			(35	)
Operating Income Effect			(9	)
Other Income:
Interest income from notes receivable			2		(e)
Income taxes			1		(g)
Total-Other Income Effect			1
Net interest Charges:
Allowance for funds used during construction			(1	)	(f)
Total-Net Interest Charges Effect			1
Net Income Effect		$	(9	)
(a) Elimination of non-nuclear generation assets lease to FGCO.
(b) Reduction of nuclear generated wholesale KWH sales to FES.
(c) Reduction of nuclear fuel and operating costs.
(d) Reduction of depreciation expense and asset retirement obligation accretion related to   generation assets.
(e) Interest income on associated company notes receivable from the transfer of generation net assets.
(f) Reduction of allowance for borrowed funds used during construction on nuclear capital   expenditures.
(g) Income tax effect of the above adjustments.

 

Results of Operations

    Earnings on common stock in the first quarter of 2006 decreased to $0.6 million from $14 million in the first quarter of 2005. The lower earnings resulted principally from the generation asset transfer effects shown in the table above.

Operating Revenues

    Operating revenues decreased by $52 million, or 39%, in the first quarter of 2006 as compared with the first quarter of 2005, primarily due to the generation asset transfer impact discussed in the table above. Excluding the effects of the asset transfer, operating revenues decreased by $8 million, or 9%. That decrease resulted from lower distribution revenues of $9 million primarily reflecting the completion of Penn's transition costs recovery, and lower wholesale revenues of $6 million resulting from the termination of a wholesale sales agreement with a non-affiliate in December 2005. The decrease in distribution KWH deliveries to residential and commercial customers reflected milder weather in the first quarter of 2006. The distribution and wholesale revenue decreases were partially offset by an increase in retail generation revenues of $6 million, primarily from higher composite unit prices associated with a 5% rate increase permitted by the PPUC for all customer classes - retail generation KWH sales remained substantially unchanged.

     Changes in distribution deliveries in the first quarter of 2006 from the same period of 2005 are summarized in the following table:

Changes in Distribution Deliveries
Increase (Decrease)
Residential			(3	)%
Commercial			(1	)%
Industrial			4	%
Total Distribution Deliveries			-	%

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Operating Expenses and Taxes

    Total operating expenses and taxes decreased by $37 million in the first quarter of 2006 from the first quarter of 2005 principally due to the generation asset transfer impact as shown in the table above. Excluding the asset transfer effects, the following presents changes from the prior year by expense category:

Operating Expenses and Taxes - Changes (In millions)
Increase (Decrease)
Purchased power costs		$	8
Other operating costs			1
Amortization of regulatory assets			(6	)
Income taxes			(5	)
Total operating expenses and taxes		$	(2	)

    I ncreased purchased power costs in the first quarter of 2006, compared with the first quarter of 2005, resulted from higher unit prices associated with the new power supply agreement with FES, partially offset by a 13% decrease in KWH purchased due to lower generation sales requirements. Other operating costs increased due to transmission expenses associated with MISO Day 2 operations that began in April 2005.

    Amortization of regulatory assets was lower in the first quarter of 2006 as compared to the same period of 2005 due to the completion of Penn's rate restructuring plan and related transition cost amortization.

Other Income (Expense)

    Other income increased $3 million in the first quarter of 2006, compared with the first quarter of 2005, in part due to the impact of the generation asset transfer. Excluding the effects of the asset transfer, other income was $2 million higher. This increase was primarily due to the absence in 2006 of accruals for a $0.7 million civil penalty payable to the DOJ and $0.8 million settlement for environmental projects in connection with the Sammis New Source Review settlement in the first quarter of 2005 (see Environmental Matters).

Net Interest Charges

    Excluding the effects of the asset transfer, net interest charges increased by $2 million in the first quarter of 2006, as compared to the first quarter of 2005. This increase was primarily due to a loss incurred on reacquired pollution control notes in the first quarter of 2006.

Capital Resources and Liquidity

    Penn’s cash requirements in 2006 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with a combination of cash from operations and short-term credit arrangements. Available borrowing capacity under credit facilities will be used to manage working capital requirements.

Changes in Cash Position

    Penn had $41,000 of cash and cash equivalents as of March 31, 2006 compared with $24,000 as of December 31, 2005. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

     Net cash provided from operating activities in the first quarter of 2006, compared with the corresponding 2005 period, was as follows:

		Three Months Ended
		March 31,
Operating Cash Flows		2006			2005
		(In millions)
Cash earnings (1)		$	4		$	30
Working capital and other			58			8
Net cash provided from operating activities		$	62		$	38

(1)	Cash earnings is a non-GAAP measure (see reconciliation below).

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Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Penn believes that cash earnings are a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income:

		Three Months Ended
		March 31,
Reconciliation of Cash Earnings		2006			2005
		(In millions)
Net Income (GAAP)		$	1		$	15
Non-Cash Charges (Credits):
Provision for depreciation			2			3
Amortization of regulatory assets			3			10
Nuclear fuel and other amortization			-			4
Deferred income taxes and investment tax credits, net			(2	)		(2	)
Other non-cash expenses			-			-
Cash earnings (Non-GAAP)		$	4		$	30

 

    The $26 million decrease in cash earnings is described above under “Results of Operations.” The $50 million change in working capital was primarily due to increases in cash provided from the settlement of receivables of $30 million and a $78 million change in prepayments and other current assets, principally as a result of the asset transfer discussed above, partially offset by increased cash outflows from the settlement of accounts payable of $50 million and a $7 million change in accrued taxes.

Cash Flows From Financing Activities

    Net cash used for financing activities totaled $48 million in the first quarter of 2006, compared with $10 million in the first quarter of 2005. This increase resulted from $54 million of long-term debt redemptions in 2006 principally as a result of the generation asset transfer discussed above, partially offset by a net $8 million increase in short-term borrowings and the absence of $8 million in common stock dividend payments to OE in the first quarter of 2005.

    Penn had $11 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $19 million of short-term indebtedness as of March 31, 2006. Penn has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA,  to incur short-term debt up to its charter limit of $50 million (including the utility money pool). Penn had the capability to issue $64 million of additional FMB on the basis of property additions and retired bonds as of March 31, 2006. Based upon applicable earnings coverage tests, Penn could issue up to $415 million of preferred stock (assuming no additional debt was issued) as of March 31, 2006.

    Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to the full amount of $25 million available as of March 31, 2006 under a receivables financing arrangement which expires June 29, 2006. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of March 31, 2006, the facility was drawn for $19 million.

    Penn has the ability to borrow under a syndicated $2 billion five-year revolving credit facility, which expires in June 2010, along with FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed, Penelec, FES, and ATSI. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing or the commitment termination date. Penn's borrowing limit under the facility is $50 million.

    Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under the existing credit facility and accounts receivable financing facilities totaled $56 million as of March 31, 2006.

    The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, Penn's debt to total capitalization as defined under the revolving credit facility was 35%.

    The facility does not contain any provisions that either restrict Penn's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to Penn's credit ratings.

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    Penn has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings under these arrangements in the first quarter of 2006 was 4.58%.

    Penn's access to the capital markets and the costs of financing are influenced by the ratings of its securities and the securities of OE and FirstEnergy. The rating outlook from S&P on all securities is stable. Moody's and Fitch's ratings outlook on all securities is positive.

In April 2006, pollution control notes that were formerly obligations of Penn were refinanced and became obligations of FGCO and NGC. The proceeds from the refinancings were used to repay a portion of their associated company notes payable to Penn. With those repayments, Penn redeemed pollution control notes in the principal amount of $6.95 million at 5.45%.

Cash Flows From Investing Activities

    Net cash used for investing activities totaled $14 million in the first quarter of 2006, compared with $28 million in the same quarter of 2005. The $14 million decrease in the 2006 period reflects a $23 million reduction in property additions, principally as a result of the generation asset transfer discussed above, partially offset by a $9 million increase in loans to associated companies.

    During the remaining three quarters of 2006, capital requirements for property additions are expected to be about $14 million. Penn has sinking fund requirements of approximately $1 million for maturing long-term debt during the remainder of 2006. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

    Penn’s capital spending for the period 2006-2010 is expected to be about $91 million of which approximately $19 million applies to 2006. Penn had no other material obligations as of March 31, 2006 that have not been recognized on its Consolidated Balance Sheet.

OUTLOOK

 

The electric industry continues to transition to a more competitive environment and all of Penn’s customers can select alternative energy suppliers. Penn continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. Penn has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits.

Regulatory Matters

 

Regulatory assets and liabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Penn’s net regulatory liabilities were approximately $64 million and $59 million as of March 31, 2006 and December 31, 2005, respectively, and are included under Noncurrent Liabilities on the Consolidated Balance Sheets.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn recommended that an RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs filed on February 3, 2006. On February 16, 2006, the ALJ issued a Recommended Decision to adopt Penn's RFP process with modifications. The PPUC approved the Recommended Decision with additional modifications on April 20, 2006. The approved plan is designed to provide customers with PLR service for January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

On November 1, 2005, FES filed a power sales agreement for FERC approval that would permit Penn to obtain its PLR power requirements from FES at a fixed price equal to the retail generation price during 2006. On December 29, 2005, the FERC issued an order setting the power sales agreement for hearing. The order required FES to submit additional evidence in support of the reasonableness of the prices charged in Penn’s contract. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in late January 2007, as a result of an April 20, 2006 extension of the procedural schedule. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order and the FERC granted rehearing for further consideration on March 1, 2006.

 

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    See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.

Environmental Matters

Penn accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in Penn’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NO _x and SO ₂ emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if OE and Penn fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, OE and Penn could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million,   respectively, for probable future cash contributions toward environmentally beneficial projects.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penn’s normal business operations pending against Penn. The other material items not otherwise discussed above are described below.

Power Outages and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

 

 

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    FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

See Note 10(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

 

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, Penn adopted adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on Penn's financial results.

SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

 

        In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. Penn is currently evaluating the impact of this Statement on its financial statements.

 

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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
					Restated
STATEMENTS OF INCOME		(In thousands)
OPERATING REVENUES		$	575,792		$	529,092
OPERATING EXPENSES AND TAXES:
Purchased power			315,710			277,132
Other operating costs			83,028			101,067
Provision for depreciation			20,628			20,206
Amortization of regulatory assets			66,745			68,374
General taxes			16,232			15,440
Income taxes			22,359			12,968
Total operating expenses and taxes			524,702			495,187
OPERATING INCOME			51,090			33,905
OTHER INCOME (net of income taxes)			2,344			44
NET INTEREST CHARGES:
Interest on long-term debt			18,059			19,405
Allowance for borrowed funds used during construction			(892	)		(403	)
Deferred interest			(1,400	)		(911	)
Other interest expense			3,957			2,409
Net interest charges			19,724			20,500
NET INCOME			33,710			13,449
PREFERRED STOCK DIVIDEND REQUIREMENTS			125			125
EARNINGS ON COMMON STOCK		$	33,585		$	13,324
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME		$	33,710		$	13,449
OTHER COMPREHENSIVE INCOME:
Unrealized gain on derivative hedges			69			69
Income tax expense related to other comprehensive income			28			28
Other comprehensive income, net of tax			41			41
TOTAL COMPREHENSIVE INCOME		$	33,751		$	13,490
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.

 

 

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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,			December 31,
		2006			2005
		(In thousands)
ASSETS
UTILITY PLANT:
In service		$	3,935,904		$	3,902,684
Less - Accumulated provision for depreciation			1,453,740			1,445,718
			2,482,164			2,456,966
Construction work in progress			99,320			98,720
			2,581,484			2,555,686
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts			149,398			145,975
Nuclear fuel disposal trust			165,198			164,203
Other			13,443			16,693
			328,039			326,871
CURRENT ASSETS:
Cash and cash equivalents			103			102
Notes receivable - associated companies			21,551			18,419
Receivables-
Customers (less accumulated provisions of $3,225,000 and $3,830,000,
respectively, for uncollectible accounts)			218,926			258,077
Associated companies			2,342			203
Other (less accumulated provisions of $227,000 and $204,000,
respectively, for uncollectible accounts)			30,463			41,456
Materials and supplies, at average cost			1,849			2,104
Prepayments and other			9,002			17,065
			284,236			337,426
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets			2,167,886			2,226,591
Goodwill			1,978,350			1,985,858
Prepaid pension costs			149,407			148,054
Other			4,403			3,620
			4,300,046			4,364,123
		$	7,493,805		$	7,584,106
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
15,371,270 shares outstanding		$	153,713		$	153,713
Other paid-in capital			2,995,715			3,003,190
Accumulated other comprehensive loss			(1,989	)		(2,030	)
Retained earnings			64,475			55,890
Total common stockholder's equity			3,211,914			3,210,763
Preferred stock			12,649			12,649
Long-term debt and other long-term obligations			967,812			972,061
			4,192,375			4,195,473
CURRENT LIABILITIES:
Currently payable long-term debt			207,408			207,231
Notes payable-
Associated companies			278,158			181,346
Accounts payable-
Associated companies			5,793			37,955
Other			112,670			149,501
Accrued taxes			86,462			54,356
Accrued interest			33,685			19,916
Cash collateral from suppliers			32,568			141,225
Other			83,725			86,884
			840,469			878,414
NONCURRENT LIABILITIES:
Power purchase contract loss liability			1,183,501			1,237,249
Accumulated deferred income taxes			814,797			812,034
Nuclear fuel disposal costs			176,981			175,156
Asset retirement obligation			80,729			79,527
Retirement benefits			72,905			72,454
Other			132,048			133,799
			2,460,961			2,510,219
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	7,493,805		$	7,584,106
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part
of these balance sheets.

 

 

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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
					Restated
		(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	33,710		$	13,449
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			20,628			20,206
Amortization of regulatory assets			66,745			68,374
Deferred purchased power and other costs			(61,868	)		(73,359	)
Deferred income taxes and investment tax credits, net			3,826			7,169
Accrued retirement benefit obligation			(902	)		(4,728	)
Accrued compensation, net			(1,834	)		5,413
Cash collateral from (returned to) suppliers			(108,657	)		6,365
Decrease (increase) in operating assets:
Receivables			48,005			14,849
Materials and supplies			255			82
Prepayments and other current assets			8,063			9,250
Increase (decrease) in operating liabilities:
Accounts payable			(68,993	)		(30,390	)
Accrued taxes			32,106			39,363
Accrued interest			13,769			15,303
Other			(5,773	)		5,956
Net cash provided from (used for) operating activities			(20,920	)		97,302
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net			96,812			-
Redemptions and Repayments-
Long-term debt			(3,731	)		(3,883	)
Short-term borrowings, net			-			(43,738	)
Dividend Payments-
Common stock			(25,000	)		(20,000	)
Preferred stock			(125	)		(125	)
Net cash provided from (used for) financing activities			67,956			(67,746	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(45,361	)		(28,124	)
Loans to associated companies, net			(3,132	)		(898	)
Proceeds from nuclear decommissioning trust fund sales			45,865			28,351
Investments in nuclear decommissioning trust funds			(46,588	)		(29,075	)
Other			2,181			69
Net cash used for investing activities			(47,035	)		(29,677	)
Net increase (decrease) in cash and cash equivalents			1			(121	)
Cash and cash equivalents at beginning of period			102			162
Cash and cash equivalents at end of period		$	103		$	41
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an
integral part of these statements.

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Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Jersey Central

Power & Light Company:

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of March 31, 2006, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s restatement of its previously issued consolidated financial statements for the years ended December 31, 2004 and 2003 as discussed in Note 2(I) to those consolidated financial statements) dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2006

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JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS   AND FINANCIAL CONDITION

    JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier.

Restatements

 

As further discussed in Note 15 to the Consolidated Financial Statements, JCP&L restated its consolidated financial statements for the three months ended March 31, 2005. The revisions are the result of a tax audit from the State of New Jersey, in which JCP&L became aware that the New Jersey Transitional Energy Facilities Assessment is not an allowable deduction for state income tax purposes .

Results of Operations

    Earnings on common stock in the first quarter of 2006 increased to $33.6 million from $13.3 million in 2005, principally due to higher operating revenues and lower other operating costs, partially offset by increases in purchased power costs and income taxes.

Operating Revenues

    Operating revenues increased $46.7 million or 8.8% in the first quarter of 2006 compared with the same period of 2005 due to higher retail electric generation, distribution and wholesale revenues.

    Retail generation revenues increased by $37.8 million in the first quarter of 2006 as compared to the previous year in all customer classes (residential - $14.9 million, commercial - $21.0 million and industrial - $1.7 million). The increases were due to higher unit prices resulting from the BGS auction effective in May 2005 and increases in sales volume (commercial - 6.8% and industrial - 3.3%). The sales volume increases were primarily due to lower customer shopping. Generation provided by alternative suppliers as a percent of total sales delivered in JCP&L’s service area decreased by 6.0 and 2.7 percentage points for commercial and industrial customers, respectively. Residential KWH generation sales declined by 4.2% from the previous year, reflecting unseasonably mild weather in the first quarter of 2006 (heating degree days were 16.5% lower than in the first quarter of 2005). Wholesale sales revenues increased $1.8 million primarily due to higher market prices -- wholesale KWH sales were virtually unchanged from the first quarter of 2005.

    The increase in distribution revenues of $5.3 million in the first quarter of 2006 compared to the same period of 2005 was primarily due to higher composite unit prices resulting from a distribution rate increase pursuant to the stipulated settlements approved by the NJBPU on May 25, 2005. The effect of the increased prices was partially offset by lower distribution KWH sales.

    Changes in KWH sales by customer class in the first quarter of 2006 compared to the same period of 2005 are summarized in the following table:

Changes in KWH Sales
Increase (Decrease)
Electric Generation:
Retail			0.5	%
Wholesale			0.1	%
Total Electric Generation Sales			0.4	%
Distribution Deliveries:
Residential			(4.2	)%
Commercial			(1.1	)%
Industrial			(7.1	)%
Total Distribution Deliveries			(3.3	)%

 

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    The higher operating revenues also reflected an additional $1.0 million received in the first quarter of 2006 as compared to the first quarter of 2005 under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specified levels, which occurred. This payment is credited to JCP&L’s customers, resulting in no net earnings impact.

Operating Expenses and Taxes

 

    Total operating expenses and taxes increased by $29.5 million in the first quarter of 2006 compared to the first quarter of 2005. The following table presents changes from the prior year by expense category:

Operating Expenses and Taxes - Changes (In millions)
Increase (Decrease)
Purchased power costs		$	38.5
Other operating costs			(18.0	)
Provision for depreciation			0.4
Amortization of regulatory assets			(1.6	)
General taxes			0.8
Income taxes			9.4
Total operating expenses and taxes		$	29.5

    Purchased power costs increased $38.5 million in the first quarter of 2006 compared to the same period of 2005. The increase reflected higher prices from the 2005 BGS auction and a 0.4% increase in total electric generation sales. The decrease of $18.0 million in other operating costs in the first quarter of 2006 reflected in part the effects of a JCP&L labor strike in 2005. The JCP&L labor strike, which affected approximately 1,300 employees, began on December 8, 2004 and lasted until March 15, 2005. As a result of settling the strike later in 2005, associated company billings for work done on behalf of JCP&L of $15.4 million was absent in the first quarter of 2006. In addition, professional and contractor services declined by $2.5 million due to additional expenditures incurred in 2005 as a result of the strike. Income tax expense increased $9.4 million in the first quarter of 2006 as compared to the first quarter of 2005 due to higher pre-tax income.

Capital Resources and Liquidity

 

    JCP&L’s cash requirements in 2006 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

    As of March 31, 2006, JCP&L had $103,000 of cash and cash equivalents compared with $102,000 as of December 31, 2005. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

    Cash provided from operating activities in the first quarter of 2006 compared with the first quarter of 2005 were as follows:

		Three Months Ended March 31,
Operating Cash Flows		2006			2005
		(In millions)
Cash earnings (1)		$	60		$	37
Working capital and other			(81	)		60
Net Cash provided from (used for) Operating Activities		$	(21	)	$	97

^{(1 )} Cash earnings are a non-GAAP measure (see reconciliation below).

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    Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. JCP&L believes that cash earnings are a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance. The following table reconciles cash earnings with net income:

		Three Months Ended
		March 31
Reconciliation of Cash Earnings		2006			2005
		(In millions)
Net Income (GAAP)		$	34		$	13
Non-Cash Charges (Credits):
Provision for depreciation			21			20
Amortization of regulatory assets			67			68
Deferred costs recoverable as regulatory assets			(62	)		(73	)
Deferred income taxes			4			7
Other non-cash expenses			(4	)		2
Cash earnings (Non-GAAP)		$	60		$	37

 

    The $23 million increase in cash earnings is described above and under “Results of Operations.” The $141 million decrease from working capital primarily resulted from a $115 million change in cash collateral from suppliers and changes in accounts payable of approximately $39 million. In 2005, JCP&L received cash collateral payments from its suppliers and in the first quarter of 2006 returned $109 million back to its suppliers.

Cash Flows From Financing Activities

    Net cash provided from financing activities was $68 million in the first quarter of 2006 as compared to net cash used of $68 million in same period of 2005. The increase resulted from a $97 million increase in new short-term borrowings and a $44 million reduction in debt redemptions in the first quarter of 2006, partially offset by an additional $5 million of common stock dividend payments to FirstEnergy.

 

    JCP&L   had about $22 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and approximately $278 million of short-term indebtedness as of March 31, 2006. JCP&L has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt up to its charter limit of $412 million (including the utility money pool). JCP&L will not issue FMB other than as collateral for senior notes, since its senior note indenture prohibits (subject to certain exceptions) JCP&L from issuing any debt which is senior to the senior notes. As of March 31, 2006, JCP&L had the capability to issue $625 million of additional senior notes based upon FMB collateral. As of March 31, 2006, based upon applicable earnings coverage tests and its charter, JCP&L could issue $1.5 billion of preferred stock (assuming no additional debt was issued).

    JCP&L has the ability to borrow from FirstEnergy and its regulated affiliates to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreement must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2006 was 4.58%.

    JCP&L, FirstEnergy, OE, Penn, CEI, TE, Penelec, Met-Ed, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility which expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. JCP&L's borrowing limit under the facility is $425 million.

    Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.

    The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, JCP&L's debt to total capitalization as defined under the revolving credit facility was 27%.

    The facility does not contain any provisions that either restrict JCP&L's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to its credit ratings.

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    JCP&L's access to the capital markets and the costs of financing are dependent on the ratings of its securities and that of FirstEnergy. As of March 31, 2006, JCP&L's and FirstEnergy’s ratings outlook from S&P on all securities was stable. The ratings outlook from Moody’s and Fitch on all securities is positive.

Cash Flows From Investing Activities

    Net cash used in investing activities was $47 million in the first quarter of 2006 compared to $30 million in the previous year. The $17 million change primarily resulted from a $17 million increase in property additions for distribution system reliability initiatives.

    During the last three quarters of 2006, capital requirements for property additions and improvements are expected to be about $132.5 million. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term debt capital markets and short-term credit arrangements.

    JCP&L’s capital spending for the period 2006-2010 is expected to be about $926 million for property additions, of which approximately $176 million applies to 2006.

Market Risk Information

    JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Its Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout JCP&L. 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.

Commodity Price Risk

JCP&L is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, JCP&L uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of JCP&L’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the table below. Contracts that are not exempt from such treatment include power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policy Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2006 is summarized in the following table:

Decrease in the Fair Value of Derivative Contracts		Non-Hedge			Hedge			Total
		(In millions)
Change in the fair value of commodity derivative contracts:
Outstanding net liabilities as of January 1, 2006		$	(1,223	)	$	-		$	(1,223	)
New contract value when entered			-			-			-
Additions/Changes in value of existing contracts			123			-			123
Change in techniques/assumptions			-			-			-
Settled contracts			(73	)		-			(73	)
Net Liabilities - Derivatives Contracts as of March 31, 2006 (1)		$	(1,173	)	$	-		$	(1,173	)
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)		$	(1	)	$	-		$	(1	)
Balance Sheet Effects:
OCI (Pre-Tax)		$	-		$	-		$	-
Regulatory Asset (Net)		$	(51	)	$	-		$	(51	)

(1)

These contracts (primarily with NUGs) are offset by a regulatory asset.

(2)

Represents the change in value of existing contracts, settled contracts and changes in techniques/ assumptions.

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Derivatives are included on the Consolidated Balance Sheet as of March 31, 2006 as follows:

Balance Sheet Classification		Non-Hedge			Hedge			Total
		(In millions)
Current-
Other Assets		$	-		$	-		$	-
Other liabilities			(1	)		-			(1	)
Non-Current-
Other Deferred Charges			11			-			11
Other noncurrent liabilities			(1,183	)		-			(1,183	)
Net liabilities		$	(1,173	)	$	-		$	(1,173	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of March 31, 2006 are summarized by year in the following table:

Source of Information - Fair Value by Contract Year

		2006 (1)			2007			2008			2009			2010			Thereafter			Total
		(In millions)
Prices actively quoted (2)		$	-		$	-		$	-		$	-		$	-		$	-		$	-
Other external sources (3)			(235	)	$	(266	)		(231	)		-			-			-			(732	)
Prices based on models			-			-			-			(156	)		(128	)		(157	)		(441	)
Total (4)		$	(235	)	$	(266	)	$	(231	)	$	(156	)	$	(128	)	$	(157	)	$	(1,173	)

⁽¹⁾   For the last three quarters of 2006.

⁽²⁾   Exchange traded.

⁽³⁾   Broker quote sheets.

⁽⁴⁾   Includes $1,173 million in non-hedge commodity derivative contracts, which are offset by a regulatory asset.

JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both our trading and non-trading derivative instruments would not have had a material effect on JCP&L’s consolidated financial position or cash flows as of March 31, 2006. JCP&L estimates that if energy commodity prices experienced an adverse 10% change, net income for the next twelve months would not change, as the prices for all commodity positions are already above the contract price caps.

Equity Price Risk

 

    Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $88 million and $84 million at March 31, 2006 and December 31, 2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $9 million reduction in fair value as of March 31, 2006.

Regulatory Matters

Regulatory assets are costs which have been authorized by the NJBPU and the FERC for recovery from customers in the future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All of JCP&L’s regulatory assets are expected to continue to be recovered under the provisions of the regulatory proceedings discussed below. JCP&L’s regulatory assets totaled $2.2 billion as of March 31, 2006 and December 31, 2005.

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2006, the accumulated deferred cost balance totaled approximately $558 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval to securitize the July 31, 2003 deferred balance. On December 2, 2005, JCP&L filed a request for recovery of $165 million of actual above-market NUG costs incurred from August 1, 2003 through October 31, 2005 and forecasted above-market NUG costs for November and December 2005. On February 1, 2006, the NJBPU selected Bear Stearns as the financial advisor. Meetings with the NJBPU Staff and the DRA were held during March and April and additional discovery conducted. The DRA filed comments on April 6, 2006, arguing that the proposed securitization does not produce customer savings. JCP&L submitted reply comments on April 10, 2006. On February 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of cost incurred since July 31, 2003. The filing also includes a request for recovery of $49 million for above-market NUG costs incurred prior to August 1, 2003, to the extent those costs are not recoverable through securitization. On March 29, 2006, a pre-hearing conference was held with the presiding ALJ. A schedule for the proceeding was established including a discovery period and evidentiary hearings scheduled for September 2006.

 

 

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An NJBPU Decision and Order approving a Phase II Stipulation of Settlement and resolving the Motion for Reconsideration of the Phase I Order was issued on May 31, 2005. The Phase II Settlement includes a performance standard pilot program with potential penalties of up to 0.25% of equity return. The Order requires that JCP&L file quarterly reliability reports (CAIDI and SAIFI information related to the performance pilot program) through December 2006 and updates to reliability related project expenditures until all projects are completed. The first quarterly report was submitted to NJBPU on August 16, 2005. The second quarterly report was submitted on November 22, 2005. The third quarterly report as of December 31, 2005 was submitted on March 28, 2006. As of December 31, 2005 there were no performance penalties issued by the NJBPU.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to an NJBPU order for the period June 1, 2005 through May 31, 2006.

The NJBPU decision approving the BGS procurement proposal for the period beginning June 1, 2006 was issued on October 12, 2005. JCP&L submitted a compliance filing on October 26, 2005, which was approved on November 10, 2005. The written Order was dated December 8, 2005. The auction took place in February 2006. On February 9, 2006, the NJBPU approved the auction results and a written order was signed on February 23, 2006. The JCP&L tariff compliance filing was approved on March 29, 2006. New BGS rates become effective June 1, 2006.  

In a reaction to the higher closing prices of the 2006 BGS fixed rate auction, the NJBPU, on March 16, 2006, initiated a generic proceeding to evaluate the auction process and potential options for the future. On April 6, 2006, initial comments were submitted. A public meeting was held on April 21, 2006 and a legislative-type hearing was held on April 28, 2006. Final comments were due on May 4, 2006. An NJBPU decision is anticipated in June 2006.

In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further proceedings has not yet been set.

On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the recent repeal of PUHCA under the EPACT. An NJBPU proposed rulemaking to address the issues was published in the NJ Register on December 19, 2005. The proposal would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. A public hearing was held February 7, 2006 and comments were submitted to the NJBPU. The NJBPU Staff issued a draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Comments and reply comments are due by May 22 and May 31, 2006, respectively. JCP&L is not able to predict the outcome of this proceeding at this time.

On December 21, 2005, the NJBPU initiated a generic proceeding and requested comments in order to formulate an appropriate regulatory treatment for investment tax credits related to generation assets divested by New Jersey’s four electric utility companies. Comments were filed by the utilities and by the DRA.

On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006.

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On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.

See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Environmental Matters

JCP&L accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in JCP&L’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

JCP&L has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Responsive, Comprehension and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that PRPs for a particular site are held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2006, based on estimates of the total costs of cleanup, JCP&L’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $47.3 million have been accrued through March 31, 2006.

See Note 10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to JCP&L's normal business operations pending against JCP&L. The other material items not otherwise discussed below are described in Note 10(C) to the consolidated financial statements.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

 

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                 FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter has been filed. FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. It is uncertain whether the plaintiff will appeal. No estimate of potential liability has been undertaken in either of these matters.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, the federal court granted a Union motion to dismiss JCP&L's appeal of the award as premature. JCP&L will file its appeal again in federal district court once the damages associated with this case are identified at an individual employee level. JCP&L recognized a liability for the potential $16 million award in 2005.

The other material items not otherwise discussed above are described in Note 10(C) to the consolidated financial statements.

New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

 

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, JCP&L will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on JCP&L's financial results.

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SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

 

        In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. JCP&L is currently evaluating the impact of this Statement on its financial statements.

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METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
		(In thousands)
OPERATING REVENUES		$	311,213		$	295,781
OPERATING EXPENSES AND TAXES:
Purchased power			159,887			150,133
Other operating costs			61,079			58,430
Provision for depreciation			10,905			11,521
Amortization of regulatory assets			30,048			28,621
General taxes			20,621			19,272
Income taxes			6,336			6,732
Total operating expenses and taxes			288,876			274,709
OPERATING INCOME			22,337			21,072
OTHER INCOME (net of income taxes)			6,494			6,449
NET INTEREST CHARGES:
Interest on long-term debt			8,717			9,560
Allowance for borrowed funds used during construction			(267	)		(178	)
Other interest expense			2,467			1,663
Net interest charges			10,917			11,045
NET INCOME			17,914			16,476
OTHER COMPREHENSIVE INCOME:
Unrealized gain on derivative hedges			84			84
Income tax expense related to other comprehensive income			35			35
Other comprehensive income, net of tax			49			49
TOTAL COMPREHENSIVE INCOME		$	17,963		$	16,525
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are
an integral part of these statements.

 

 

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METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,			December 31,
		2006			2005
		(In thousands)
ASSETS
UTILITY PLANT:
In service		$	1,869,720		$	1,856,425
Less - Accumulated provision for depreciation			721,156			721,566
			1,148,564			1,134,859
Construction work in progress			21,739			20,437
			1,170,303			1,155,296
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts			242,165			234,854
Other			24,159			29,678
			266,324			264,532
CURRENT ASSETS:
Cash and cash equivalents			120			120
Notes receivable from associated companies			30,012			27,867
Receivables-
Customers (less accumulated provisions of $4,356,000 and $4,352,000,
respectively, for uncollectible accounts)			126,917			129,854
Associated companies			13,649			37,267
Other			7,506			8,780
Prepayments and other			47,725			7,912
			225,929			211,800
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			860,592			864,438
Regulatory assets			308,289			309,556
Prepaid pension costs			90,738			89,005
Other			22,831			23,060
			1,282,450			1,286,059
		$	2,945,006		$	2,917,687
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,000 shares outstanding		$	1,283,268		$	1,287,093
Accumulated other comprehensive loss			(1,520	)		(1,569	)
Retained earnings			48,489			30,575
Total common stockholder's equity			1,330,237			1,316,099
Long-term debt and other long-term obligations			591,918			591,888
			1,922,155			1,907,987
CURRENT LIABILITIES:
Currently payable long-term debt			100,000			100,000
Short-term borrowings-
Associated companies			82,312			140,240
Other			75,000			-
Accounts payable-
Associated companies			14,475			37,220
Other			51,412			27,507
Accrued taxes			11,831			17,911
Accrued interest			9,329			9,438
Other			20,362			24,274
			364,721			356,590
NONCURRENT LIABILITIES:
Accumulated deferred income taxes			348,849			344,929
Accumulated deferred investment tax credits			9,843			10,043
Nuclear fuel disposal costs			39,979			39,567
Asset retirement obligation			144,239			142,020
Retirement benefits			57,517			57,809
Other			57,703			58,742
			658,130			653,110
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	2,945,006		$	2,917,687
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these
balance sheets.

 

 

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METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
		(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	17,914		$	16,476
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			10,905			11,521
Amortization of regulatory assets			30,048			28,621
Deferred costs recoverable as regulatory assets			(22,818	)		(25,271	)
Deferred income taxes and investment tax credits, net			1,704			(11	)
Accrued compensation and retirement benefits			(3,912	)		(3,370	)
Commodity derivative transactions, net			(2,148	)		-
Decrease (increase) in operating assets:
Receivables			27,829			69,712
Prepayments and other current assets			(37,665	)		(34,135	)
Increase (decrease) in operating liabilities:
Accounts payable			1,160			(49,591	)
Accrued taxes			(6,080	)		(9,671	)
Accrued interest			(109	)		(1,173	)
Other			(4,649	)		(304	)
Net cash provided from operating activities			12,179			2,804
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net			17,065			28,587
Redemptions and Repayments-
Long-term debt			-			(435	)
Dividend Payments-
Common stock			-			(9,000	)
Net cash provided from financing activities			17,065			19,152
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(25,277	)		(16,199	)
Proceeds from nuclear decommissioning trust fund sales			42,061			22,667
Investments in nuclear decommissioning trust funds			(44,432	)		(25,038	)
Loans to associated companies, net			(2,145	)		(3,150	)
Other			549			(236	)
Net cash used for investing activities			(29,244	)		(21,956	)
Net change in cash and cash equivalents			-			-
Cash and cash equivalents at beginning of period			120			120
Cash and cash equivalents at end of period		$	120		$	120
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these statements.

 

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Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of March 31, 2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2006

 

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METROPOLITAN EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

    Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier.

Results of Operations

    Net Income in the first quarter of 2006 increased to $18 million from $16 million in the first quarter of 2005. This increase was primarily due to higher operating revenues and lower depreciation expense, and was partially offset by increases in purchased power costs, other operating costs, amortization of regulatory assets and general taxes.

    Operating revenues increased by $15 million, or 5.2% in the first quarter of 2006 compared with the same period in 2005 primarily due to higher retail generation revenues, transmission revenues and other operating revenues, partially offset by lower distribution revenues. Retail generation revenues increased in all customer sectors by $12 million principally due to higher composite unit prices and a 12.1% increase in industrial KWH sales. The industrial sales increase resulted from reduced generation service provided by alternative suppliers. Sales by alternative suppliers as a percent of total industrial sales in Med-Ed's franchise area decreased by 13.7 percentage points in the first quarter of 2006.

    Revenues from distribution throughput decreased by $2 million, primarily due to a 2.4% decrease in KWH deliveries, reflecting the effect of milder temperatures in 2006 compared with 2005, as demonstrated by a 16.4% decrease in heating degree days, partially offset by slightly higher composite unit prices. Transmission revenues increased by $3 million primarily due to higher transmission prices, which also resulted in higher transmission expenses as discussed below. Other operating revenues also increased due to a $2 million increase in the first quarter of 2006, compared with the first quarter of 2005, in the payment received under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specified levels, which occurred. This payment is credited to Met-Ed’s customers, resulting in no net earnings effect.

    Changes in KWH sales by customer class in the first quarter of 2006 compared to the same period of 2005 are summarized in the following table:

Changes in KWH Sales
Increase (Decrease)
Retail Electric Generation:
Residential			(2.5	%)
Commercial			0.1	%
Industrial			12.1	%
Total Retail Electric Generation Sales			2.0	%
Distribution Deliveries:
Residential			(2.7	%)
Commercial			(0.8	%)
Industrial			(3.6	%)
Total Distribution Deliveries			(2.4	%)

Operating Expenses and Taxes

Total operating expenses and taxes increased by $14 million, or 5.2% in the first quarter of 2006 compared to the first quarter of 2005. The following table presents changes from the prior year by expense category:

Operating Expenses and Taxes - Changes (In millions)
Increase (Decrease)
Purchased power costs		$	10
Other operating costs			3
Provision for depreciation			(1	)
Amortization of regulatory assets			1
General taxes			1
Income taxes			-
Total operating expenses and taxes		$	14

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    Purchased power costs increased by $10 million in the first quarter of 2006 as compared with the same period of 2005. The increase was mainly attributable to a 2.1% increase in KWH purchases to meet higher retail generation demand requirements. The effect of the increased power purchases was partially offset by lower composite unit prices. NUG contract purchases also increased by $2 million. Other operating costs increased in the first quarter of 2006 primarily due to higher transmission expenses, which increased as a result of the higher transmission prices discussed above. Amortization of regulatory assets increased principally due to a higher level of CTC revenue recovery, partially offset by lower amortization of non-NUG stranded costs. General taxes increased by $1 million in the first quarter of 2006 primarily due to higher gross receipt taxes.

Capital Resources and Liquidity

    Met-Ed’s cash requirements in 2006 for operating expenses, construction expenditures and scheduled debt maturities, are expected to be met with a combination of cash from operations and short-term credit arrangements.

Changes in Cash Position

    As of March 31, 2006 and December 31, 2005, Met-Ed had $120,000 of cash and cash equivalents.

Cash Flows From Operating Activities

    Cash provided from operating activities in the first quarter of 2006 and 2005 were as follows:

		Three Months Ended March 31,
Operating Cash Flows		2006			2005
		(In millions)
Cash earnings (1)		$	32		$	28
Working capital and other			(20	)		(25	)
Net cash provided from operating activities		$	12		$	3

⁽¹⁾   Cash earnings is a non-GAAP measure (see reconciliation below).

 

    Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Met-Ed believes that cash earnings are a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance.

		Three Months Ended
		March 31,
Reconciliation of Cash Earnings		2006			2005
		(In millions)
Net Income (GAAP)		$	18		$	16
Non-Cash Charges (Credits):
Provision for depreciation			11			12
Amortization of regulatory assets			30			29
Deferred costs recoverable as regulatory assets			(23	)		(25	)
Deferred income taxes and investment tax credits, net			2			-
Commodity derivative transactions, net			(2	)		-
Other non-cash expenses			(4	)		(4	)
Cash earnings (Non-GAAP)		$	32		$	28

 

    The $4 million increase in cash earnings is described above under “Results of Operations.” The $5 million working capital change primarily resulted from decreased outflows of $51 million in accounts payable and $1 million in accrued interest, partially offset by a $42 million decrease in cash provided from the settlement of receivables and a $5 million decrease in other accrued liabilities.

Cash Flows From Financing Activities

    Net cash provided from financing activities was $17 million in the first quarter of 2006 compared to $19 million in the first quarter of 2005. The decrease primarily reflects an $11 million decrease in short-term borrowings in the first quarter of 2006, partially offset by a $9 million decrease in common stock dividend payments to FirstEnergy.

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    As of March 31, 2006, Met-Ed had approximately $30 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $157 million of short-term borrowings. Met-Ed has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt up to $250 million and authorization from the PPUC to incur money pool borrowings up to $300 million. In addition, Met-Ed has $80 million of available accounts receivable financing facilities as of March 31, 2006 from Met-Ed Funding LLC, Met-Ed’s wholly owned subsidiary. As a separate legal entity with separate creditors, Met-Ed Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Met-Ed. As of March 31, 2006 the facility was drawn for $75 million.

    Under the terms of Met-Ed’s senior note indenture, FMB may no longer be issued so long as the senior bonds are outstanding. As of March 31, 2006, Met-Ed had the capability to issue $625 million of additional senior notes based upon FMB collateral. Met-Ed had no restrictions on the issuance of preferred stock.

    Met-Ed, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Penelec, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility with a syndicate of banks which expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment expiration date, as the same may be extended. Met-Ed’s borrowing limit under the facility is $250 million.

    Under the revolving credit facility, Borrowers may request the issuance of LOC expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under the existing credit facilities and accounts receivable financing facilities totaled $255 million.

    The revolving credit facility contains financial covenants requiring each Borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, Met-Ed’s debt to total capitalization as defined under the revolving credit facility was 39%.

    The facility does not contain any provisions that either restrict Met-Ed’s ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to Met-Ed's credit ratings.

    Met-Ed has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2006 was 4.58%.

    Met-Ed’s access to the capital markets and the costs of financing are dependent on the ratings of its securities and that of FirstEnergy. As of March 31, 2006, Met-Ed’s and FirstEnergy’s ratings outlook from S&P on all securities was stable. The ratings outlook from Moody’s and Fitch on all securities is positive.

Cash Flows From Investing Activities

    In the first quarter of 2006, Met-Ed's cash used for investing activities totaled $29 million, compared to $22 million in the first quarter of 2005. The increase primarily resulted from a $9 million increase in property additions, partially offset by a decrease in loans to associated companies. Expenditures for property additions primarily support Met-Ed’s energy delivery operations and reliability initiatives.

    During the remaining three quarters of 2006, capital requirements for property additions are expected to be about $56 million. Met-Ed has additional requirements of approximately $100 million for maturing long-term debt during the remainder of 2006. These cash requirements are expected to be satisfied from a combination of internal cash, funds raised in the long-term debt capital markets and short-term credit arrangements.

    Met-Ed's capital spending for the period 2006 through 2010 is expected to be about $366 million, of which approximately $82 million applies to 2006. The capital spending is primarily for property additions supporting the distribution of electricity.

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Market Risk Information

    Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities throughout the company.

Commodity Price Risk

    Met-Ed is exposed to market risk primarily due to fluctuations in electricity, energy transmission, natural gas, coal, and emission prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts, and swaps. The derivatives are used principally for hedging purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of Met-Ed’s derivative hedging contracts qualify for normal purchase and normal sale exception under SFAS 133. Contracts that are not exempt from such treatment include purchase power agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policy Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter of 2006 is summarized in the following table:

		Three Months Ended
		March 31, 2006
Increase (Decrease) in the Fair Value of Derivative Contracts		Non-Hedge			Hedge			Total
		(In millions)
Change in the fair value of commodity derivative contracts
Outstanding net asset as of January 1, 2006		$	27		$	-		$	27
New contract value when entered			-			-			-
Additions/Changes in value of existing contracts			4			-			4
Change in techniques/assumptions			-			-			-
Settled contracts			(7	)		-			(7	)
Net Assets - Derivatives Contracts as of March 31, 2006 (1)		$	24		$	-		$	24
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)		$	2		$	-		$	2
Balance Sheet Effects:
OCI (Pre-Tax)		$	-		$	-		$	-
Regulatory Liability		$	5		$	-		$	5

⁽¹⁾   Includes $21 million in non-hedge commodity derivative contracts, which are offset by a regulatory liability.

⁽²⁾   Represents the change in value of existing contracts, settled contracts and changes in techniques/ assumptions

Derivatives are included on the Consolidated Balance Sheet as of March 31, 2006 as follows :

		Non-Hedge			Hedge			Total
		(In millions)
Current-
Other assets		$	2		$	-		$	2
Other liabilities			-			-			-
Non-Current-
Other deferred charges			23			-			23
Other noncurrent liabilities			(1	)		-			(1	)
Net assets		$	24		$	-		$	24

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    The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of March 31, 2006 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year		2006 (1)			2007			2008			2009			2010			Thereafter			Total
		(In millions)
Prices based on external sources (2)		$	(20	)	$	(16	)	$	(17	)	$	-		$	-		$	-		$	(53	)
Prices based on models (3)			-			-			-			(16	)		(12	)		105			77
Total		$	(20	)	$	(16	)	$	(17	)	$	(16	)	$	(12	)	$	105		$	24

⁽¹⁾   For the last three quarters of 2006.

⁽²⁾   Broker quote sheets

⁽³⁾   Includes $21 million from an embedded option that is offset by a regulatory liability and does not affect earnings.

     Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both of Met-Ed’s trading and non-trading derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, 2006.

Equity Price Risk

     Included in Met-Ed's nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $148 million and $142 million as of March 31, 2006 and December 31, 2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $15 million reduction in fair value as of March 31, 2006.

Regulatory Matters

 

Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in the future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered under the provisions of Met-Ed’s transition plan and rate restructuring plan. Met-Ed’s regulatory assets as of March 31, 2006 and December 31, 2005 were $308 million and $310 million, respectively.

Met-Ed’s and Penelec’s combined portion of total merger savings during 2001 - 2004 is estimated to be approximately $51 million. A procedural schedule was established by the ALJ on January 17, 2006. Met-Ed and Penelec filed initial testimony on March 1, 2006. Hearings are currently scheduled for the end of October 2006 with the ALJ’s recommended decision to be issued in February 2007. Met-Ed and Penelec have requested that this proceeding be consolidated with the April 10, 2006 transition plan filing proceeding discussed below. Met-Ed is unable to predict the outcome of this proceeding.

In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the Commonwealth Court, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an Application for Reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005. Oral arguments are scheduled for June 8, 2006.

On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006.

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On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.

As of March 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $328 million and $50 million, respectively. Penelec's $50 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds.

    On January 12, 2005, Met-Ed filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. As of March 31, 2006, the PPUC had taken no action on the request and Met-Ed had not yet implemented deferral accounting for these costs. Met-Ed sought to consolidate this proceeding (and modified its request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing it made on April 10, 2006 as described below. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed will implement deferral accounting for these costs in the second quarter of 2006, which will include $24 million representing the amount that was incurred in the first quarter of 2006 -- the deferral of such amount will be reflected in the second quarter of 2006.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. Under this agreement, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their contracts with NUGs and other unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. The wholesale power sales agreement with FES could automatically be extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right in 2006 to terminate the agreement at any time upon 60 days notice. On April 7, 2006, the parties to the wholesale power sales agreement entered into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the wholesale power sales agreement effective midnight December 31, 2006, because that agreement is not economically sustainable to FES.

In lieu of allowing such termination to become effective as of December 31, 2006, the parties agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales agreement to provide as follows:

1.   The termination provisions of the wholesale power sales agreement will be tolled for one year until December 31, 2007, provided that during such tolling period:

a.	FES will be permitted to terminate the wholesale power sales agreement at any time with sixty days written notice;

b.

Met-Ed and Penelec will procure through arrangements other than the wholesale power sales agreement beginning December 1, 2006 and ending December 31, 2007, approximately 33% of the amounts of capacity and energy necessary to satisfy their PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased power contracts and distributed generation) have not been obtained; and

c.	FES will not be obligated to supply additional quantities of capacity and energy in the event that a supplier of Committed Resources defaults on its supply agreement.

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2.   During the tolling period FES will not act as agent for Met-Ed or Penelec in procuring the services under section 1.(b) above; and

3.   The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed and Penelec comply with the provisions of the Tolling Agreement and any applicable provision of the wholesale power sales agreement.

In the event that FES elects not to terminate the wholesale power sales agreement effective midnight December 31, 2007, similar tolling agreements effective after December 31, 2007 are expected to be considered by FES for subsequent years if Met-Ed and Penelec procure through arrangements other than the wholesale power sales agreement approximately 64%, 83% and 95% of the additional amounts of capacity and energy necessary to satisfy their PLR obligations for 2008, 2009 and 2010, respectively, for which Committed Resources have not been obtained from the market.

The wholesale power sales agreement, as modified by the Tolling Agreement, requires Met-Ed and Penelec to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed below, or, to the extent granted, adequate to mitigate such adverse consequences.

Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million and $157 million, respectively. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a competitive bid process as the amount of supply provided under the existing FES agreement is phased out in accordance with the April 7, 2006 Tolling agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 petition for the deferral of transmission-related costs discussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also included in the filing. The filing contemplates a reduction in distribution rates for Met-Ed in the amount of $37 million annually and an increase in distribution rates for Penelec in the amount of $20 million annually. Although the companies have proposed an effective date of June 10, 2006, it is expected that the PPUC will suspend the effective date for seven months as permitted under Pennsylvania law. Hearings are expected to be scheduled for the second half of 2006 and a PPUC decision is expected early in the first quarter of 2007.

    See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania including a more detailed discussion of reliability initiatives, including actions by the PPUC that impact Met-Ed .

Environmental Matters

Met-Ed accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in Met-Ed’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Met-Ed has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Responsive, Comprehension and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that PRPs for a particular site are held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2006, based on estimates of the total costs of cleanup, Met-Ed’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.

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See Note 10(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Met-Ed’s normal business operations pending against Met-Ed. The other material items not otherwise discussed below are described in Note 10(C) to the consolidated financial statements.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter has been filed. FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. It is uncertain whether the plaintiff will appeal. No estimate of potential liability has been undertaken in either of these matters.

FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

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New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

 

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, Met-Ed will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on Met-Ed's financial results.

SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

 

        In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. Met-Ed is currently evaluating the impact of this Statement on its financial statements.

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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
		(In thousands)
OPERATING REVENUES		$	291,752		$	293,929
OPERATING EXPENSES AND TAXES:
Purchased power			161,641			150,277
Other operating costs			38,342			53,793
Provision for depreciation			12,643			12,506
Amortization of regulatory assets			14,815			13,185
General taxes			19,389			18,206
Income taxes			12,764			15,792
Total operating expenses and taxes			259,594			263,759
OPERATING INCOME			32,158			30,170
OTHER INCOME (net of income taxes)			1,180			736
NET INTEREST CHARGES:
Interest on long-term debt			6,934			7,459
Allowance for borrowed funds used during construction			(347	)		(125	)
Other interest expense			3,602			2,188
Net interest charges			10,189			9,522
NET INCOME			23,149			21,384
OTHER COMPREHENSIVE INCOME:
Unrealized gain on derivative hedges			16			16
Unrealized loss on available for sale securities			(4	)		(3	)
Other comprehensive income			12			13
Income tax expense related to other comprehensive income			6			6
Other comprehensive income, net of tax			6			7
TOTAL COMPREHENSIVE INCOME		$	23,155		$	21,391
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are
an integral part of these statements.

 

 

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PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

		March 31,			December 31,
		2006			2005
		(In thousands)
ASSETS
UTILITY PLANT:
In service		$	2,070,562		$	2,043,885
Less - Accumulated provision for depreciation			788,535			784,494
			1,282,027			1,259,391
Construction work in progress			33,332			30,888
			1,315,359			1,290,279
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts			115,534			113,368
Non-utility generation trusts			97,390			96,761
Other			11,915			15,031
			224,839			225,160
CURRENT ASSETS:
Cash and cash equivalents			35			35
Receivables-
Customers (less accumulated provisions of $4,304,000 and $4,184,000,
respectively, for uncollectible accounts)			123,915			129,960
Associated companies			10,176			18,626
Other			10,566			12,800
Notes receivable from associated companies			18,758			17,624
Prepayments and other			48,682			7,936
			212,132			186,981
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill			877,778			882,344
Prepaid pension costs			90,972			89,637
Other			26,865			24,176
			995,615			996,157
		$	2,747,945		$	2,698,577
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
5,290,596 shares outstanding		$	105,812		$	105,812
Other paid-in capital			1,197,999			1,202,551
Accumulated other comprehensive loss			(303	)		(309	)
Retained earnings			48,973			25,823
Total common stockholder's equity			1,352,481			1,333,877
Long-term debt and other long-term obligations			476,704			476,504
			1,829,185			1,810,381
CURRENT LIABILITIES:
Short-term borrowings-
Associated companies			230,474			261,159
Other			70,000			-
Accounts payable-
Associated companies			15,915			33,770
Other			46,509			38,277
Accrued taxes			23,001			27,905
Accrued interest			14,306			8,905
Other			17,329			19,756
			417,534			389,772
NONCURRENT LIABILITIES:
Regulatory liabilities			156,002			162,937
Asset retirement obligation			73,426			72,295
Accumulated deferred income taxes			113,419			106,871
Retirement benefits			104,022			102,046
Other			54,357			54,275
			501,226			498,424
COMMITMENTS AND CONTINGENCIES (Note 10)
		$	2,747,945		$	2,698,577
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these
balance sheets.

 

 

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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended
		March 31,
		2006			2005
		(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	23,149		$	21,384
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation			12,643			12,506
Amortization of regulatory assets			14,815			13,185
Deferred costs recoverable as regulatory assets			(19,211	)		(19,433	)
Deferred income taxes and investment tax credits, net			5,361			2,446
Accrued compensation and retirement benefits			(472	)		(1,762	)
Commodity derivative transactions, net			(4,206	)		-
Decrease (Increase) in operating assets:
Receivables			16,729			39,145
Prepayments and other current assets			(36,540	)		(35,119	)
Increase (Decrease) in operating liabilities:
Accounts payable			(9,623	)		(24,234	)
Accrued taxes			(4,904	)		10,205
Accrued interest			5,401			5,581
Other			(6,745	)		(217	)
Net cash provided from (used for) operating activities			(3,603	)		23,687
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net			39,315			-
Redemptions and Repayments-
Long-term debt			-			(13	)
Short-term borrowings, net			-			(1,803	)
Dividend Payments-
Common stock			-			(5,000	)
Net cash provided from (used for) financing activities			39,315			(6,816	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(35,610	)		(15,393	)
Loans to associated companies, net			(1,134	)		(3,082	)
Proceeds from nuclear decommissioning trust fund sales			14,942			7,778
Investments in nuclear decommissioning trust funds			(14,942	)		(7,778	)
Other, net			1,032			1,603
Net cash used for investing activities			(35,712	)		(16,872	)
Net change in cash and cash equivalents			-			(1	)
Cash and cash equivalents at beginning of period			35			36
Cash and cash equivalents at end of period		$	35		$	35
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an
integral part of these statements.

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Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of March 31, 2006 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2006 and 2005. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2005, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

May 8, 2006

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PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S DISCUSSION AND   ANALYSIS OF

RESULTS OF OPERATIONS   AND FINANCIAL CONDITION

    Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier.

Results of Operations

 

    Net income in the first quarter of 2006 increased to $23 million, compared to $21 million in the first quarter of 2005. The increase resulted from lower other operating costs, partially offset by lower operating revenues and higher purchased power costs.

    Operating revenues decreased by $2 million in the first quarter of 2006 compared to the first quarter of 2005, primarily due to lower transmission and distribution revenues partially offset by higher retail generation revenues. T ransmission revenues decreased by $12 million due to lower transmission load requirements and lower prices. The decreased loads (and related lower congestion revenues) reflect milder temperatures in 2006 compared with 2005, as demonstrated by a 14.6% decrease in heating degree days, and which also resulted in lower transmission expenses discussed further below. Distribution revenues decreased by $2 million due to a 2.6% decrease in KWH deliveries reflecting the effect of the unseasonably mild weather, partially offset by slightly higher composite unit prices.

    Retail generation revenues increased by $11 million primarily due to a 15.1% increase in industrial KWH sales and higher composite unit prices that resulted in increased revenues in all customer sectors (residential - $2 million; commercial - $2 million; and industrial - $7 million). The industrial sales volume increased primarily from reduced generation service provided by alternative suppliers, which decreased by 14.3 percentage points in the first quarter of 2006. In addition, other operating revenues increased by $1 million due to a higher payment received in the first quarter of 2006 under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specified levels, which occurred. This payment is credited to Penelec’s customers, resulting in no net earnings effect.

    Changes in KWH sales by customer class in the first quarter of 2006 compared to the same period of 2005 are summarized in the following table:

Changes in KWH Sales
Increase (Decrease)
Retail Electric Generation:
Residential			(2.2	)%
Commercial			(1.4	)%
Industrial			15.1	%
Total Retail Electric Generation Sales			2.8	%
Distribution Deliveries:
Residential			(2.4	)%
Commercial			(2.5	)%
Industrial			(3.1	)%
Total Distribution Deliveries			(2.6	)%

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Operating Expenses and Taxes

    Total operating expenses and taxes decreased by $4 million in the first quarter of 2006 compared to the first quarter of 2005. The following table presents changes from the prior year by expense category:

Operating Expenses and Taxes - Changes (In millions)
Increase (Decrease)
Purchased power costs		$	11
Other operating costs			(15	)
Provision for depreciation			-
Amortization of regulatory assets			2
General taxes			1
Income taxes			(3	)
Total operating expenses and taxes		$	(4	)

 

    Purchased power costs increased by $11 million or 7.6% in the first quarter of 2006, compared to the first quarter of 2005. The increase is primarily attributable to higher unit costs from non-affiliated suppliers and increased KWH purchased to meet increased retail generation sales requirements. Other operating costs decreased due to lower transmission expenses resulting from lower congestion charges and to higher levels of construction activities in the first quarter of 2006 compared to a higher level of maintenance activities in the same period of 2005 for energy delivery operations and reliability initiatives. Amortization of regulatory assets increased due to increases in CTC revenue recovery compared to the first quarter of 2005.

    General taxes increased $1 million due to the higher Pennsylvania gross receipts taxes in the first quarter of 2006 compared to the same period in 2005. Income taxes decreased $3 million due to lower pre-tax income in the first quarter of 2006 compared to the first quarter of 2005.

Capital Resources and Liquidity

    Penelec’s cash requirements in 2006 for operating expenses, construction expenditures and scheduled debt maturities, are expected to be met by a combination of cash from operations and short-term credit arrangements.

Changes in Cash Position

    As of March 31, 2006 and December 31, 2005, Penelec had $35,000 of cash and cash equivalents.

Cash Flows From Operating Activities

    Net cash used for operating activities was $4 million in the first quarter of 2006, compared to net cash provided from operating activities of $24 million in the first quarter of 2005, summarized as follows:

			Three Months Ended
			March 31,
Operating Cash Flows			2006			2005
			(In millions)
Cash earnings (1)			$	32		$	28
Working capital and other				(36	)		(4	)
Net cash provided from (used for) Operating Activities			$	(4	)	$	24

⁽¹⁾  Cash earnings is a non-GAAP measure (see reconciliation below).

    Cash earnings (in the table above) are not a measure of performance calculated in accordance with GAAP. Penelec believes that cash earnings are a useful financial measure because it provides investors and management with an additional means of evaluating its cash-based operating performance.

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		Three Months Ended
		March 31,
Reconciliation of Cash Earnings		2006			2005
		(In millions)
Net Income (GAAP)		$	23		$	21
Non-Cash Charges (Credits):
Provision for depreciation			13			13
Amortization of regulatory assets			15			13
Deferred costs recoverable as regulatory assets			(19	)		(19	)
Deferred income taxes and investment tax credits			5			2
Commodity derivative transactions, net			(4	)		-
Other non-cash expenses			(1	)		(2	)
Cash earnings (Non-GAAP)		$	32		$	28

    The $4 million increase in cash earnings is described above under “Results of Operations.” The $32 million decrease in working capital primarily resulted from a decrease of $22 million in cash provided from the settlement of receivables and decreases of $15 million in accrued taxes and $2 million in accrued liabilities for consumer education, partially offset by a decrease of $14 million in accounts payable.

Cash Flows From Financing Activities

     Net cash provided from financing activities was $39 million in the first quarter of 2006 compared to net cash used for financing activities of $7 million in the first quarter of 2005. The change reflects a $41 million increase in short-term borrowings and a $5 million reduction in common stock dividend payments to FirstEnergy in the first quarter of 2006.

    Penelec had approximately $19 million of cash and temporary investments (which includes short-term notes receivable from associated companies) and approximately $300 million of short-term indebtedness as of March 31, 2006. Penelec has authorization from the SEC, continued by FERC rules adopted as a result of EPACT's repeal of PUHCA, to incur short-term debt of up to $250 million and authorization from the PPUC to incur money pool borrowings of up to $300 million. In addition, Penelec has $75 million of available accounts receivable financing facilities as of March 31, 2006 from Penelec Funding, Penelec's wholly owned subsidiary. As a separate legal entity with separate creditors, Penelec Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penelec. As of March 31, 2006 the facility was drawn for $70 million.

    Penelec will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) Penelec from issuing any debt which is senior to the senior notes. As of March 31, 2006, Penelec had the ability to issue $39 million of additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock.

    Penelec , FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, FES and ATSI, as Borrowers, have entered into a syndicated $2 billion five-year revolving credit facility which expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Penelec's borrowing limit under the facility is $250 million.

    Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities totaled $255 million.

    The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of March 31, 2006, Penelec’s debt to total capitalization as defined under the revolving credit facility was 36%.

    The facility does not contain any provisions that either restrict Penelec's ability to borrow or accelerate repayment of outstanding advances as a result of any change in its credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to Penelec's credit ratings.

    Penelec has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings under these arrangements in the first quarter of 2006 was 4.58%.

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    Penelec’s access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook from S&P on all securities is stable. The ratings outlook from Moody's and Fitch on all securities is positive.

Cash Flows From Investing Activities

 

    During the remaining three quarters of 2006, capital requirements for property additions are expected to be about $66 million. Penelec’s capital spending for the period 2006-2010 is expected to be about $489 million, of which approximately $103 million applies to 2006. The capital spending is primarily for property additions supporting the distribution of electricity.

Market Risk Information

    Penelec uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities throughout the Company.

Commodity Price Risk

    Penelec is exposed to market risk primarily due to fluctuations in electricity, energy transmission, natural gas, coal, and emission prices. To manage the volatility relating to these exposures, Penelec uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of Penelec’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133. Contracts that are not exempt from such treatment include purchase power agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policy Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the first quarter 2006 is summarized in the following table:

		Three Months Ended
		March 31, 2006
Increase (Decrease) in the Fair Value of Derivative Contracts		Non-Hedge			Hedge			Total
		(In millions)
Change in the fair value of commodity derivative contracts
Outstanding net asset at beginning of period		$	27		$	-		$	27
New contract value when entered			-			-			-
Additions/Changes in value of existing contracts			3			-			3
Change in techniques/assumptions			-			-			-
Settled contracts			-			-			-
Net Assets - Derivatives Contracts as of March 31, 2006 (1)		$	30		$	-		$	30
Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)		$	6		$	-		$	6
Balance Sheet Effects:
OCI (Pre-Tax)		$	-		$	-		$	-
Regulatory Asset (net)		$	3		$	-		$	3

(1)

Includes $11 million in non-hedge commodity derivative contracts, which are offset by a regulatory liability.

(2)

Represents the decrease in value of existing contracts, settled contracts and changes in techniques/ assumptions.

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Derivatives are included on the Consolidated Balance Sheet as of March 31, 2006 as follows:

		Non-Hedge			Hedge			Total
		(In millions)
Current-
Other assets		$	4		$	-		$	4
Other liabilities			-			-			-
Non-Current-
Other deferred charges			26			-			26
Other noncurrent liabilities			-			-			-
Net assets		$	30		$	-		$	30

    The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of March 31, 2006 are summarized by year in the following table:

Source of Information
Fair Value by Contract Year		2006 (1)			2007			2008			2009			2010			Thereafter			Total
		(In millions)
Other external sources (2)		$	(14	)	$	(3	)	$	2		$	-		$	-		$	-		$	(15	)
Prices based on models			-			-			-			5			3			37			45
Total (3)		$	(14	)	$	(3	)	$	2		$	5		$	3		$	37		$	30

⁽¹⁾  For the last three quarters of 2006.

⁽²⁾  Broker quote sheets.

⁽³⁾  Includes $11 million from an embedded option that is offset by a regulatory liability and does not affect earnings.

    Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on both of Penelec's trading and non-trading derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of March 31, 2006. Penelec estimates that if energy commodity prices experienced an adverse 10% change, net income for the next 12 months would not change, as the prices for all commodity positions are already above the contract price caps.

Equity Price Risk

 

    Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $65 million and $62 million as of March 31, 2006 and December 31, 2005, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of March 31, 2006.

Regulatory Matters

    Regulatory assets and liabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Penelec’s net regulatory liabilities were approximately $156 million and $163 million as of March 31, 2006 and December 31, 2005, respectively, and are included under Noncurrent Liabilities on the Consolidated Balance Sheets.

Met-Ed’s and Penelec’s combined portion of total merger savings during 2001 - 2004 is estimated to be approximately $51 million. A procedural schedule was established by the ALJ on January 17, 2006. Met-Ed and Penelec filed initial testimony on March 1, 2006. Hearings are currently scheduled for the end of October 2006 with the ALJ’s recommended decision to be issued in February 2007. Met-Ed and Penelec have requested that this proceeding be consolidated with the April 10, 2006 transition plan filing proceeding as discussed below. Penelec is unable to predict the outcome of this proceeding.

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In an October 16, 2003 order, the PPUC approved September 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC order also denied their accounting treatment request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse this PPUC finding; a Commonwealth Court judge subsequently denied their Objection on October 27, 2003 without explanation. On October 31, 2003, Met-Ed and Penelec filed an Application for Clarification of the Court order with the Commonwealth Court, a Petition for Review of the PPUC's October 2 and October 16, 2003 Orders, and an Application for Reargument, if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed on January 28, 2005. Oral arguments are scheduled for June 8, 2006.

On November 18, 2004, the FERC issued an order eliminating the regional through and out rates (RTOR) for transmission service between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within the MISO and PJM to submit compliance filings containing a mechanism - the Seams Elimination Cost Adjustment (SECA) -- to recover lost RTOR revenues during a 16-month transition period from load serving entities. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES continue to be involved in the FERC hearings concerning the calculation and imposition of the SECA charges. The hearing began on May 1, 2006. The FERC has ordered the Presiding Judge to issue an initial decision by August 11, 2006.

 

On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. American Electric Power Company, Inc. filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the settling PJM transmission owners filed a request for rehearing of the May 31, 2005 order. On March 20, 2006 a settlement was filed with FERC in the formula rate proceeding that generally accepts the companies' formula rate proposal. The FERC issued an order approving this settlement on April 19, 2006. If the FERC accepts AEP's proposal, significant additional transmission revenues would be imposed on JCP&L, Met-Ed, Penelec, and other transmission zones within PJM.

As of March 31, 2006, Met-Ed's and Penelec's regulatory deferrals pursuant to the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation are $328 million and $50 million, respectively. Penelec's $50 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds.

On January 12, 2005, Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. As of March 31, 2006, the PPUC had taken no action on the request and Penelec had not yet implemented deferral accounting for these costs. Penelec sought to consolidate this proceeding (and modified its request to provide deferral of 2006 transmission-related costs only) with the comprehensive rate filing it made on April 10, 2006 as described below. On May 4, 2006, the PPUC approved the modified request. Accordingly, Penelec will implement deferral accounting for these costs in the second quarter of 2006, which will include $4 million representing the amount that was incurred in the first quarter of 2006 -- the deferral of such amount will be reflected in the second quarter of 2006.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. Under this agreement, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their contracts with NUGs and other unaffiliated suppliers. The FES arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. The wholesale power sales agreement with FES could automatically be extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. On November 1, 2005, FES and the other parties thereto amended the agreement to provide FES the right in 2006 to terminate the agreement at any time upon 60 days notice. On April 7, 2006, the parties to the wholesale power sales agreement entered into a Tolling Agreement that arises out of FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the wholesale power sales agreement effective midnight December 31, 2006, because that agreement is not economically sustainable to FES.

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In lieu of allowing such termination to become effective as of December 31, 2006, the parties agreed, pursuant to the Tolling Agreement, to amend the wholesale power sales agreement to provide as follows:

1.   The termination provisions of the wholesale power sales agreement will be tolled for one year until December 31, 2007, provided that during such tolling period:

a.	FES will be permitted to terminate the wholesale power sales agreement at any time with sixty days written notice;

b.

Met-Ed and Penelec will procure through arrangements other than the wholesale power sales agreement beginning December 1, 2006 and ending December 31, 2007, approximately 33% of the amounts of capacity and energy necessary to satisfy their PLR obligations for which Committed Resources (i.e., non-utility generation under contract to Met-Ed and Penelec, Met-Ed- and Penelec-owned generating facilities, purchased power contracts and distributed generation) have not been obtained; and

c.	FES will not be obligated to supply additional quantities of capacity and energy in the event that a supplier of Committed Resources defaults on its supply agreement.

2.   During the tolling period FES will not act as agent for Met-Ed or Penelec in procuring the services under section 1.(b) above; and

3.   The pricing provision of the wholesale power sales agreement shall remain unchanged provided Met-Ed and Penelec comply with the provisions of the Tolling Agreement and any applicable provision of the wholesale power sales agreement.

In the event that FES elects not to terminate the wholesale power sales agreement effective midnight December 31, 2007, similar tolling agreements effective after December 31, 2007 are expected to be considered by FES for subsequent years if Met-Ed and Penelec procure through arrangements other than the wholesale power sales agreement approximately 64%, 83% and 95% of the additional amounts of capacity and energy necessary to satisfy their PLR obligations for 2008, 2009 and 2010, respectively, for which Committed Resources have not been obtained from the market.

The wholesale power sales agreement, as modified by the Tolling Agreement, requires Met-Ed and Penelec to satisfy the portion of their PLR obligations currently supplied by FES from unaffiliated suppliers at prevailing prices, which are likely to be higher than the current price charged by FES under the current agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. There can be no assurance, however, that if FES ultimately determines to terminate, or significantly modify the agreement, timely regulatory relief will be granted by the PPUC pursuant to the April 10, 2006 comprehensive rate filing discussed below, or, to the extent granted, adequate to mitigate such adverse consequences.

Met-Ed and Penelec made a comprehensive rate filing with the PPUC on April 10, 2006 that addresses a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals is approved, the filing would increase annual revenues by $216 million and $157 million, respectively. That filing includes, among other things, a request to charge customers for an increasing amount of market priced power procured through a competitive bid process as the amount of supply provided under the existing FES agreement is phased out in accordance with the April 7, 2006 Tolling agreement described above. Met-Ed and Penelec also requested approval of the January 12, 2005 petition for the deferral of transmission-related costs discussed above, but only for those costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider similar to that implemented in Ohio. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs are also included in the filing. The filing contemplates a reduction in distribution rates for Met-Ed in the amount of $37 million annually and an increase in distribution rates for Penelec in the amount of $20 million annually. Although the companies have proposed an effective date of June 10, 2006, it is expected that the PPUC will suspend the effective date for seven months as permitted under Pennsylvania law. Hearings are expected to be scheduled for the second half of 2006 and a PPUC decision is expected early in the first quarter of 2007.

See Note 11 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability initiatives, including actions by the PPUC that impact Penelec.

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Environmental Matters

    Penelec accrues environmental liabilities when it concludes that it is probable that it has an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in Penelec's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

    Penelec has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis.

Other Legal Proceedings

    There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to Penelec’s normal business operations pending against Penelec. The other material items not otherwise discussed below are described in Note 10(C) to the consolidated financial statements.

    On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of March 31, 2006 for any expenditure in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

    FirstEnergy was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter has been filed. FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy are based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. No FirstEnergy entity serves any customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. It is uncertain whether the plaintiff will appeal. No estimate of potential liability has been undertaken in either of these matters.

    FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

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New Accounting Standards and Interpretations

EITF Issue 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty"

 

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, Penelec will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. This EITF issue will not have a material impact on Penelec's financial results.

SFAS 155 - “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140”

 

        In February 2006, the FASB issued SFAS 155 which amends SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” This Statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation, clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133, establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation, clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative instrument. This Statement is effective for all financial instruments acquired or issued beginning January 1, 2007. Penelec is currently evaluating the impact of this Statement on its financial statements.

 

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

    See “Management’s Discussion and Analysis of Results of Operation and Financial Condition - Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a)   EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

 

    The applicable registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the applicable registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.

(b)   CHANGES IN INTERNAL CONTROLS

 

    During the quarter ended March 31, 2006, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.   LEGAL PROCEEDINGS

     Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 10 and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

 

ITEM 1A.   RISK FACTORS

     Not Applicable.

ITEM 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c)   FirstEnergy

    The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.

		Period
		January 1-31,			February 1-28,			March 1-31,			First
		2006			2006			2006			Quarter
Total Number of Shares Purchased (a)		150,321			143,522			769,145			1,062,988
Average Price Paid per Share		$50.77			$50.67			$50.84			$50.81
Total Number of Shares Purchased
As Part of Publicly Announced Plans
or Programs (b)			-			-			-			-
Maximum Number (or Approximate Dollar
Value) of Shares that May Yet Be
Purchased Under the Plans or Programs			-			-			-			-

 

(a)	Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan.
(b)	FirstEnergy does not currently have any publicly announced plan or program for share purchases.

 

ITEM 6.   EXHIBITS

Exhibit Number
FirstEnergy
	10.1*	Form of Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp. in favor of the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent, under the related Letter of Credit and Reimbursement Agreement.
	10.2*	Form of Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 among FirstEnergy Generation Corp., the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent.
	10.3*	Form of Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp.
	10.4*	Form of Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006.

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	10.5	Notice of Termination Tolling Agreement dated as of April 7, 2006; Restated Partial Requirements Agreement, dated January 1, 2003, by and among, Metropolitan Edison Company, Pennsylvania Electric Company, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., as amended by a First Amendment to Restated Requirements Agreement, dated August 29, 2003 and by a Second Amendment to Restated Requirements Agreement, dated June 8, 2004 (“Partial Requirements Agreement”). (Form 8-K dated April 10, 2006)
	10.6	Form of Restricted Stock Agreement between FirstEnergy and A. J. Alexander, dated February 27, 2006.
	10.7	Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and A.J. Alexander, dated March 1, 2006.
	10.8	Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy and named executive officers, dated March 1, 2006.
	10.9	Form of Restricted Stock Unit Agreement (Discretionary) between FirstEnergy and R.H. Marsh, dated March 1, 2006.
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
OE
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
Penn
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
CEI
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
TE
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
JCP&L
	12	Fixed charge ratios
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.3	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.2	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
Met-Ed
	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
Penelec
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
* Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp. (Form 8-K dated April 3, 2006)

Pursuant to reporting requirements of respective financings, FirstEnergy, OE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q. CEI, TE and Penn do not have similar financing reporting requirements and have not filed their respective fixed charge ratios.

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Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec but hereby agree to furnish to the Commission on request any such documents.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

May 8, 2006

	FIRSTENERGY CORP.
	Registrant
	OHIO EDISON COMPANY
	Registrant
	THE CLEVELAND ELECTRIC
	ILLUMINATING COMPANY
	Registrant
	THE TOLEDO EDISON COMPANY
	Registrant
	PENNSYLVANIA POWER COMPANY
	Registrant
	JERSEY CENTRAL POWER & LIGHT COMPANY
	Registrant
	METROPOLITAN EDISON COMPANY
	Registrant
	PENNSYLVANIA ELECTRIC COMPANY
	Registrant

	/s/   Harvey L. Wagner
	Harvey L. Wagner
	Vice President, Controller
	and Chief Accounting Officer

 

 

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