Form 10-Q 3rd Quarter September 30, 2006

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 nine months ended September 30, 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.

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. On August 10, 2006, FirstEnergy repurchased 10.6 million shares, approximately 3.2%, of its outstanding common stock through an accelerated share repurchase program (see Note 10(D)). The initial purchase price was $600 million, or $56.44 per share. The final purchase price will be adjusted to reflect the ultimate cost to acquire the shares over a period of up to seven months. The 2006 basic and diluted earnings per share results reflect the impact associated with the August 2006 accelerated share repurchase program. FirstEnergy intends to settle, in shares or cash, any obligation on its part to pay the difference between the average of the daily volume-weighted average price of the shares as calculated under the program and the initial price of the shares. Since the effect of any potential settlement in shares is currently unknown and therefore not expected to be dilutive, there is no impact on reported diluted earnings per share. The following table reconciles the computation of basic and diluted earnings per share of common stock before discontinued operations:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Basic and Diluted Earnings per Share	2006		2005		2006			2005
	*(In millions, except per share amounts)*
Income Before Discontinued Operations	$	454	$	332	$	979		$	652
Less: Redemption premium on subsidiary preferred stock		-		-		(3	)		-
Earnings on Common Stock Before Discontinued Operations	$	454	$	332	$	976		$	652

Weighted Average Shares of Common Stock Outstanding:
Denominator for basic earnings per share		322		328		326			328
Assumed exercise of dilutive stock options and awards		3		2		3			2
Denominator for diluted earnings per share		325		330		329			330

Earnings Before Discontinued Operations per Common Share:
Basic		$1.41		$1.01		$2.99			$1.99
Diluted		$1.40		$1.01		$2.97			$1.98

3. - GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill.

FirstEnergy's 2006 annual review was completed in the third quarter of 2006 with no impairment indicated. As discussed in Note 11 to the consolidated financial statements, Met-Ed and Penelec have rate increase requests pending before the PPUC. The annual goodwill impairment analysis assumed management's best estimate of the rate increases that are expected to be granted in January 2007. If the PPUC authorizes less than the amounts assumed, an additional impairment analysis would be performed at that time and this could result in a future goodwill impairment loss that could be material. If rate relief were completely denied, it is estimated that approximately $604 million of Met-Ed’s goodwill would be impaired and approximately $374 million of Penelec’s goodwill would be impaired, and those amounts would be written off by those companies. However, no adjustment to FirstEnergy’s goodwill on a consolidated basis would be recognized in that circumstance because the fair value of its regulated segment (which represents FirstEnergy's reporting unit to evaluate goodwill) would continue to exceed the carrying value of its investment in the segment.

FirstEnergy's goodwill primarily relates to its regulated services segment. In the nine months ended September 30, 2006, FirstEnergy adjusted goodwill related to the divestiture of a non-core asset (62% interest in MYR), a successful tax claim relating to the former Centerior companies, and adjustments to the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. The following tables reconcile changes to goodwill for the three months and nine months ended September 30, 2006.

Three Months Ended	FirstEnergy			CEI		TE		JCP&L			Met-Ed		Penelec
	*(In millions)*
Balance as of July 1, 2006	$	5,940		$	1,688	$	501	$	1,978		$	860	$	878
Adjustments related to GPU acquisition		(5	)						(1	)				(4	)
Balance as of September 30, 2006	$	5,935		$	1,688	$	501	$	1,977		$	860	$	874

Nine Months Ended	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		(21	)							(9	)		(4	)		(8	)
Balance as of September 30, 2006	$	5,935		$	1,688		$	501	$	1,977		$	860		$	874

4. - DIVESTITURES AND DISCONTINUED OPERATIONS

In August 2006, FirstEnergy sold two FSG subsidiaries (Roth Bros. and Hattenbach) for a net after-tax gain of $1.9 million. The remaining FSG subsidiaries continue to be actively marketed and qualify as assets held for sale in accordance with SFAS 144 because FirstEnergy anticipates that the transfer of these assets, with a net carrying value of $30.6 million as of September 30, 2006, will qualify for recognition as completed sales within one year. As of September 30, 2006, the remaining FSG subsidiaries classified as held for sale did not meet the criteria for discontinued operations. The carrying amounts of FSG's assets and liabilities are not material and have not been presented separately as assets held for sale on FirstEnergy's Consolidated Balance Sheets. See Note 13 for FSG's segment financial information.

In March 2006, FirstEnergy sold 60% of its interest in MYR for an after-tax gain of $0.2 million. In June 2006, FirstEnergy sold an additional 1.67% interest. As a result of the March sale, FirstEnergy deconsolidated MYR in the first quarter of 2006 and accounts for its remaining 38.33% interest under the equity method.

In March 2005, 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.

During the first nine months of 2005, FirstEnergy sold three FSG subsidiaries (Cranston, Elliott-Lewis and Spectrum), an MYR subsidiary (Power Piping) and FES' retail natural gas business, resulting in aggregate after-tax gains of $17 million.

Net results (including the gains on sales of assets discussed above) for Cranston, Elliott-Lewis, Power Piping and FES' retail natural gas business of $18 million for the nine months ended September 30, 2005 are reported as discontinued operations on FirstEnergy's Consolidated Statements of Income. Pre-tax operating results for these entities were $2 million for the nine months ended September 30, 2005. Revenues associated with discontinued operations for the nine months ended September 30, 2005 were $207 million. The following table summarizes the sources of income from discontinued operations (in millions) for the nine months ended September 30, 2005:

Discontinued Operations (Net of tax)
Gain on sale:
Natural gas business	$	5
FSG and MYR subsidiaries		12
Reclassification of operating income		1
Total	$	18

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. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practices.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales exception criterion. 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 criterion 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 $48 million included in AOCL as of September 30, 2006, for derivative hedging activity, as compared to the December 31, 2005 balance of $78 million of net deferred losses, resulted from a net $13 million decrease related to current hedging activity and a $17 million decrease due to net hedge losses reclassified into earnings during the nine months ended September 30, 2006. Based on current estimates, approximately $15 million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2006 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

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 nine months ended September 30, 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 September 30, 2006, FirstEnergy had interest rate swaps with an aggregate notional value of $750 million and a fair value of ($29) million.

During 2005 and the first nine months 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 subsidiaries 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. FirstEnergy revised the tenor and timing of its financing plan during the first nine months of 2006. FirstEnergy terminated and revised forward swaps with an aggregate notional value of $600 million during the second quarter of 2006, ultimately terminating the swaps as its subsidiaries issued long-term debt. In the third quarter of 2006, FirstEnergy revised the timing of swaps with an aggregate notional value of $100 million. As required by SFAS 133, FirstEnergy assessed the amount of ineffectiveness of the hedges at each termination. FirstEnergy received cash gains of $43 million, of which approximately $6 million ($4 million net of tax) was deemed ineffective and recognized in earnings in the first nine months of 2006. The remaining gain deemed effective in the amount of approximately $38 million ($23 million net of tax) was recorded in other comprehensive income and will subsequently be recognized in earnings over the terms of the associated future debt. As of September 30, 2006, FirstEnergy had forward swaps with an aggregate notional amount of $725 million and a long-term debt securities fair value of ($2) million.

6. - STOCK BASED COMPENSATION

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 three months and nine months ended September 30, 2006 included the expense for all share-based payments granted prior to but not yet vested as of January 1, 2006. Results for prior periods were not restated.

Prior to the adoption of SFAS 123(R) on January, 1, 2006, FirstEnergy’s LTIP, EDCP, ESOP, and DCPD stock-based compensation programs were 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.

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), compensation 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 granted since 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 three months and nine months ended September 30, 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. Reference is made to FirstEnergy’s annual report on Form 10-K for the year ended December 31, 2005 for expanded annual disclosure.

The following table illustrates the effect on net income and earnings per share for the three months and nine months ended September 30, 2005, as if FirstEnergy had adopted SFAS 123(R) as of January 1, 2005:

	Three Months			Nine Months
	(In millions, except per share amounts)

Net Income, as reported	$	332		$	670

Add back compensation expense
reported in net income, net of tax (based on
APB 25)*		17			40

Deduct compensation expense based
upon estimated fair value, net of tax*		(19	)		(47	)

Pro forma net income	$	330		$	663
Earnings Per Share of Common Stock -
Basic
As Reported		$1.01			$2.04
Pro Forma		$1.01			$2.02
Diluted
As Reported		$1.01			$2.03
Pro Forma		$1.00			$2.01

* 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 nine months ended September 30, 2005, the impact on earnings would have been immaterial.

The ARO liability of $1.2 billion as of September 30, 2006 primarily relates 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 uses 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 September 30, 2006, the fair value of the decommissioning trust assets was $1.9 billion.

The following tables analyze changes to the ARO balances during the three months and nine months ended September 30, 2006 and 2005, respectively.

Three Months Ended	FirstEnergy			OE			CEI			TE			Penn		JCP&L		Met-Ed		Penelec
	*(In millions)*
ARO Reconciliation
Balance, July 1, 2006	$	1,160		$	85		$	2		$	26		$	-	$	82	$	146	$	74
Liabilities incurred		-			-			-			-			-		-		-		-
Liabilities settled		-			-			-			-			-		-		-		-
Accretion		19			2			-			-			-		1		3		2
Revisions in estimated
cashflows		-			-			-			-			-		-		-		-
Balance, September 30, 2006	$	1,179		$	87		$	2		$	26		$	-	$	83	$	149	$	76

Balance, July 1, 2005	$	1,113		$	208		$	281		$	201		$	143	$	75	$	137	$	68
Liabilities incurred		-			-			-			-			-		-		-		-
Liabilities settled		-			-			-			-			-		-		-		-
Accretion		18			3			5			4			2		1		2		1
Revisions in estimated
cashflows		(1	)		(2	)		(5	)		(5	)		11		-		-		-
Balance, September 30, 2005	$	1,130		$	209		$	281		$	200		$	156	$	76	$	139	$	69

Nine Months Ended	FirstEnergy			OE			CEI			TE			Penn		JCP&L		Met-Ed		Penelec
	*(In millions)*
ARO Reconciliation
Balance, January 1, 2006	$	1,126		$	83		$	8		$	25		$	-	$	80	$	142	$	72
Liabilities incurred		-			-			-			-			-		-		-		-
Liabilities settled		(6	)		-			(6	)		-			-		-		-		-
Accretion		55			4			-			1			-		3		7		4
Revisions in estimated
cashflows		4			-			-			-			-		-		-		-
Balance, September 30, 2006	$	1,179		$	87		$	2		$	26		$	-	$	83	$	149	$	76

Balance, January 1, 2005	$	1,078		$	201		$	272		$	195		$	138	$	72	$	133	$	67
Liabilities incurred		-			-			-			-			-		-		-		-
Liabilities settled		-			-			-			-			-		-		-		-
Accretion		53			10			14			10			7		4		6		2
Revisions in estimated
cashflows		(1	)		(2	)		(5	)		(5	)		11		-		-		-
Balance, September 30, 2005	$	1,130		$	209		$	281		$	200		$	156	$	76	$	139	$	69

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 pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits.

The components of FirstEnergy's net periodic pension and other postretirement benefit costs (including amounts capitalized) for the three months and nine months ended September 30, 2006 and 2005 consisted of the following:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Pension Benefits	2006			2005			2006			2005
	*(In millions)*
Service cost	$	21		$	19		$	63		$	58
Interest cost		66			64			199			191
Expected return on plan assets		(99	)		(86	)		(297	)		(259	)
Amortization of prior service cost		2			2			7			6
Recognized net actuarial loss		15			9			44			27
Net periodic cost	$	5		$	8		$	16		$	23

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Other Postretirement Benefits	2006			2005			2006			2005
	*(In millions)*
Service cost	$	9		$	10		$	26		$	30
Interest cost		26			27			79			83
Expected return on plan assets		(12	)		(11	)		(35	)		(34	)
Amortization of prior service cost		(19	)		(11	)		(57	)		(33	)
Recognized net actuarial loss		14			10			42			30
Net periodic cost	$	18		$	25		$	55		$	76

Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. FirstEnergy’s subsidiaries 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 and nine months ended September 30, 2006 and 2005 were as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Pension Benefit Cost (Credit)	2006			2005			2006			2005
	*(In millions)*
OE	$	(1.1	)	$	0.2		$	(3.3	)	$	0.7
Penn		(0.4	)		(0.2	)		(1.2	)		(0.7	)
CEI		1.0			0.3			2.9			1.0
TE		0.2			0.3			0.7			1.0
JCP&L		(1.4	)		(0.3	)		(4.1	)		(0.8	)
Met-Ed		(1.7	)		(1.1	)		(5.2	)		(3.2	)
Penelec		(1.3	)		(1.3	)		(4.0	)		(4.0	)
Other FirstEnergy subsidiaries		9.9			9.6			29.9			28.6
	$	5.2		$	7.5		$	15.7		$	22.6

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Other Postretirement Benefit Cost	2006		2005		2006		2005
	*(In millions)*
OE	$	3.4	$	5.8	$	10.2	$	17.3
Penn		0.8		1.2		2.4		3.5
CEI		2.8		3.8		8.3		11.4
TE		2.0		2.2		6.1		6.5
JCP&L		0.6		1.5		1.8		5.7
Met-Ed		0.7		0.4		2.2		1.2
Penelec		1.8		2.0		5.4		5.9
Other FirstEnergy subsidiaries		6.1		8.0		18.1		24.5
	$	18.2	$	24.9	$	54.5	$	76.0

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 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-leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $655 million, $95 million and $506 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.

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. FirstEnergy expects any above-market costs it incurs to be recovered from customers. As of September 30, 2006, the net above-market loss liability projected for these eight NUG agreements was $239 million. Purchased power costs from these entities during the three months and nine months ended September 30, 2006 and 2005 are shown in the following table:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	*(In millions)*
JCP&L	$	29	$	33	$	63	$	74
Met-Ed		12		10		45		40
Penelec		8		7		22		21
Total	$	49	$	50	$	130	$	135

Securitized Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 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 September 30, 2006, outstanding guarantees and other assurances totaled approximately $3.6 billion consisting of contract guarantees $2.0 billion, surety bonds $0.2 billion and LOCs $1.4 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 credit support for subsidiary financings or refinancings of costs related to the acquisition of, or improvements to, 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 $2.0 billion discussed above) as of September 30, 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 September 30, 2006, FirstEnergy's maximum exposure under these collateral provisions was $487 million.

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $147 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.

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 September 30, 2006), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $27 million on October 15, 2006.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on 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.

FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they 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 SO₂ emissions 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 SO₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. A meeting was held on August 8, 2006 to discuss the alleged violations with the EPA. FirstEnergy has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at the August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated.

FirstEnergy complies with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. 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 at 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 SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_X and SO₂ emissions in two phases (Phase I in 2009 for NO_X, 2010 for SO₂ and Phase II in 2015 for both NO_X and SO₂). FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO₂ and NO_X emissions, whereas its New Jersey fossil-fired generation facility will be subject to only a cap on NO_X emissions. According to the EPA, SO₂ 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 SO₂ 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. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO₂ 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 then, new and non-emitting generating facilities, including renewables and nuclear, would be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

Pennsylvania has proposed a new rule to regulate mercury emissions from coal-fired power plants that does not provide a cap and trade approach as in CAMR, but rather follows a command and control approach imposing emission limits on individual sources. If adopted as proposed, Pennsylvania’s mercury regulation would deprive FirstEnergy of mercury emission allowances that were to be allocated to the Bruce Mansfield Plant under CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. The future cost of compliance with these regulations, if adopted and implemented as proposed, may be substantial.

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 SO₂ 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 ($400 million of which is expected to be spent in 2007 with the primary portion of the remaining $1.1 billion expected to be spent in 2008 and 2009). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of SO₂ emissions. FGCO also entered into an agreement with B&W on August 25, 2006 to supply flue gas desulfurization systems for the reduction of SO₂ emissions. Selective Catalytic Reduction (SCR) systems for the reduction of NOx emissions also are being installed at the W.H. Sammis Plant under a 1999 agreement with B&W.

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.

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 CO₂ emissions could require significant capital and other expenditures. The CO₂ emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic 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 September 30, 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 $73 million (JCP&L - $55 million, CEI - $1 million, and other subsidiaries- $17 million) have been accrued through September 30, 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.

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. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division because it effectively terminates this class action. Briefs are being prepared and filed, and legal argument is scheduled for late November 2006. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 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 Web site (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 is also 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 a result of adoption of mandatory reliability standards pursuant to the EPACT that could require additional material expenditures.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outages. 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. Three other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these three 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 sixth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. That case has been dismissed. On March 7, 2006, the PUCO issued a ruling, based on motions filed by the parties, 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 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. 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 that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed an amended complaint and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on October 16, 2007.

On October 10, 2006, various insurance carriers refiled a complaint in Cuyahoga County Common Pleas Court seeking reimbursement for claims paid to numerous insureds who allegedly suffered losses as a result of the August 14, 2003 outages. All of the insureds appear to be non-customers. The plaintiff insurance companies are the same claimants in one of the pending PUCO cases. FirstEnergy, the Ohio Companies and Penn were served on October 27, 2006, and expect to seek summary dismissal of these cases based on the prior court rulings noted above. No estimate of potential liability is available for any of these cases.

FirstEnergy was also named, along with several other entities, in a complaint in New Jersey State Court. The allegations against FirstEnergy were based, in part, on an alleged failure to protect the citizens of Jersey City from an electrical power outage. None of FirstEnergy’s subsidiaries serve customers in Jersey City. A responsive pleading has been filed. On April 28, 2006, the Court granted FirstEnergy's motion to dismiss. The plaintiff has not appealed.

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 had 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 (not deductible for income tax purposes) which reduced FirstEnergy'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.

On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance at the Perry Nuclear Power 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 the Perry Nuclear Power Plant on March 14, 2006, the NRC again stated that the Perry Nuclear Power 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

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 the now repealed 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. On October 18, 2006, the Ohio Supreme Court transferred this case to a Tuscarawas County Common Pleas Court judge due to concerns over potential class membership by the Jefferson County Common Pleas Court.

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 arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss as premature a JCP&L appeal of the award filed on October 18, 2005. JCP&L intends to re-file an 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. Both filings were consolidated for hearing and decision. 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. On May 10, 2006, the PUCO issued its Opinion and Order dismissing the City’s complaint and approving the related tariffs, thus affirming OE’s entitlement to recovery of its transition charges. The City of Huron filed an application for rehearing of the PUCO’s decision on June 9, 2006 and OE filed a memorandum in opposition to that application on June 19, 2006. The PUCO denied the City’s application for rehearing on June 28, 2006. The City of Huron has taken no further action and the period for filing an appeal has expired.

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.

(D) ACCELERATED SHARE REPURCHASE PROGRAM

On August 9, 2006, FirstEnergy entered into an accelerated share repurchase agreement with a financial institution counterparty under which FirstEnergy repurchased 10.6 million shares, or approximately 3.2%, of its outstanding common stock on August 10, 2006 at an initial price of $56.44 per share, or a total initial purchase price of $600 million. This forward sale contract is being accounted for as an equity instrument. The final purchase price is subject to a contingent purchase price adjustment based on the average of the daily volume-weighted average prices over a subsequent purchase period of up to seven months, as well as other purchase price adjustments in the event of an extraordinary cash dividend or other dilution events. The price adjustment can be settled, at FirstEnergy’s option, in cash or in shares of its common stock. The size of any settlement amount and whether it is to be paid or received by FirstEnergy will depend upon the average of the daily volume-weighted average prices of the shares as calculated by the counterparty under the program. The settlement is expected to occur in the first quarter of 2007.

The accelerated share repurchase was completed under a program authorized by the Board of Directors on June 20, 2006 to repurchase up to 12 million shares of common stock. At management’s discretion, additional shares may be acquired under the program on the open market or through privately negotiated transactions, subject to market conditions and other factors. The Board’s authorization of the repurchase program does not require FirstEnergy to make any further repurchases of shares and the program may be terminated at any time.

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 equipment 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, all of which could require additional, material expenditures.

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 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 an SRM 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. The SRM completed his work and issued his final report to the NJBPU on June 1, 2006. A meeting was held between JCP&L and the NJBPU on June 29, 2006 to discuss the SRM’s final report. JCP&L filed a comprehensive response to the NJBPU on July 14, 2006. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC’s 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 reliability organizations (regional entities). The new FERC rule referred to above, further provides for reorganizing regional entities that would replace the current regional councils and for rearranging their 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. The ERO filing was noticed on April 7, 2006 and comments and reply comments were filed in May, June and July 2006. On July 20, 2006, the FERC certified the NERC as the ERO to implement the provisions of Section 215 of the Federal Power Act and directed the NERC to make a compliance filing within 90 days addressing such issues as the regional delegation agreements. The NERC made its compliance filing in October 2006. This filing is pending before the FERC.

On April 4, 2006, NERC also submitted a filing with the FERC seeking approval of mandatory reliability standards. These reliability standards are based, with some modifications and additions, on the current NERC Version O reliability standards. The reliability standards filing was noticed by the FERC on April 18, 2006. In that notice, the FERC announced its intent to issue a Notice of Proposed Rulemaking on the proposed reliability standards at a future date. On May 11, 2006, the FERC staff released a preliminary assessment that cited many deficiencies in the proposed reliability standards. The NERC and industry participants filed comments in response to the Staff’s preliminary assessment. The FERC held a technical conference on the proposed reliability standards on July 6, 2006. The FERC issued a Notice of Proposed Rulemaking on the proposed reliability standards on October 20, 2006. The FERC voted to adopt 83 of the proposed 107 reliability standards. The FERC asked the NERC to make technical improvements to 62 of the 83 standards approved. The 24 standards that were not adopted remain pending at the FERC awaiting further clarification and filings by the NERC and regional entities. The FERC also provided additional clarification on the proposed application of final standards in the NOPR. Interested parties will be given the opportunity to comment on the NOPR within 60 days of its publication in the Federal Register. Mandatory reliability standards are expected to be in place by the summer of 2007. In a separate order issued October 24, 2006, the FERC approved NERC’s 2007 budget and business plan subject to certain compliance filings.

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.

On May 2, 2006, the NERC Board of Trustees adopted eight new cyber security standards that replaced interim standards put in place in the wake of the September 11, 2001 terrorist attacks, and thirteen additional reliability standards. The security standards became effective on June 1, 2006, and the remaining standards will become effective throughout 2006 and 2007. NERC intends to file the standards with the FERC and relevant Canadian authorities for approval, but the cyber security standards were not included in the October 20, 2006 NOPR.

FirstEnergy believes it is in compliance with all current NERC reliability standards. However, based upon a review of the October 20, 2006 NOPR, it appears 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. 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.

OHIO

On October 21, 2003, the Ohio Companies filed their 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 the PUCO’s 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 the proceeding as well as the associated entries on rehearing. On May 3, 2006, the Supreme Court of Ohio issued an opinion affirming the PUCO's order with respect to the approval of the rate stabilization charge, approval of the shopping credits, the granting of interest on shopping credit incentive deferral amounts, and approval of the Ohio Companies’ financial separation plan. It remanded back to the PUCO the matter of ensuring the availability of sufficient means for customer participation in the competitive marketplace. The RSP contained a provision that permitted the Ohio Companies to withdraw and terminate the RSP in the event that the PUCO, or the Supreme Court of Ohio, rejected all or part of the RSP. In such event, the Ohio Companies have 30 days from the final order or decision to provide notice of termination. On July 20, 2006 the Ohio Companies filed with the PUCO a Request to Initiate a Proceeding on Remand. In their Request, the Ohio Companies provided notice of termination to those provisions of the RSP subject to termination, subject to being withdrawn, and also set forth a framework for addressing the Supreme Court of Ohio’s findings on customer participation, requesting the PUCO to initiate a proceeding to consider the Ohio Companies’ proposal. If the PUCO approves a resolution to the issues raised by the Supreme Court of Ohio that is acceptable to the Ohio Companies, the Ohio Companies’ termination will be withdrawn and considered to be null and void. Separately, the OCC and NOAC also submitted to the PUCO on July 20, 2006 a conceptual proposal dealing with the issue raised by the Supreme Court of Ohio. On July 26, 2006, the PUCO issued an Entry acknowledging the July 20, 2006 filings of the Ohio Companies and the OCC and NOAC, and giving the Ohio Companies 45 days to file a plan in a new docket to address the Court’s concern. On September 19, 2006, the PUCO issued an Entry granting the Ohio Companies’ motion for extension of time to file the remand proposal. The Ohio Companies filed their RSP Remand CBP on September 29, 2006. No further proceedings have been scheduled at this time.

The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. 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.

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. 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 8, 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 notices of appeal with the Supreme Court of Ohio alleging various errors made by the PUCO in its order approving the RCP. The Ohio Companies’ Motion to Intervene in the appeals was granted by the Supreme Court on June 8, 2006. The Appellants’ Merit Briefs were filed at the Supreme Court on July 5, 2006. The Appellees include the PUCO and the Ohio Companies. The Appellees’ Merit Briefs were filed on August 24, 2006 and the Appellants’ Reply Briefs were filed on September 21, 2006. The OCC filed an amicus brief on August 4, 2006, which the Ohio Companies moved to strike as improperly filed. The Supreme Court denied the Ohio Companies’ motion on October 18, 2006.

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 recovered from January 1 through June 30, 2006 were approximately $61 million. That amount included the recovery of a portion of the 2005 deferred MISO expenses as described below. On April 27, 2006, the Ohio Companies filed the annual update rider to determine revenues ($139 million) from July 2006 through June 2007. The filed rider went into effect on July 1, 2006.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period 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. On January 20, 2006, the OCC sought rehearing of the PUCO’s 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. 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 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 were heard on May 10, 2006. The Ohio Companies are awaiting a final ruling from the Ohio Supreme Court, which is expected before the end of 2006.

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 and the companies filed initial testimony on March 1, 2006. On May 4, 2006, the PPUC consolidated this proceeding with the April 10, 2006 comprehensive rate filing proceeding discussed below. Met-Ed and Penelec are unable to predict the outcome of this matter.

In an October 16, 2003 order, the PPUC approved June 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 were held on June 8, 2006. On July 19, 2006, the Commonwealth Court issued its decision affirming the PPUC’s prior orders. Although the decision denied the appeal of Met-Ed and Penelec, they had previously accounted for the treatment of costs required by the PPUC’s October 2003 orders.

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 an agent for Met-Ed or Penelec in procuring the services under 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. On September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for 33% of their PLR obligation for which Committed Resources have not been obtained for the period December 1, 2006 through December 31, 2008.

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, further reduce, 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 CBP 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 of $37 million annually and an increase in distribution rates for Penelec of $20 million annually. The PPUC suspended the effective date (June 10, 2006) of these rate changes for seven months after the filing as permitted under Pennsylvania law. If the PPUC adopts the overall positions taken in the intervenors’ testimony as filed, this would have a material adverse effect on the financial statements of FirstEnergy, Met-Ed and Penelec. Hearings were held in late August 2006 and all reply briefs were filed by October 6, 2006. The ALJ’s recommended decision is due by November 8, 2006 and the PPUC decision is expected by January 12, 2007.

As of September 30, 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 were $297 million and $56 million, respectively. Penelec's $56 million is subject to the pending resolution of taxable income issues associated with NUG trust fund proceeds. The PPUC recently conducted a review and audit of a modification to the NUG purchased power stranded cost accounting methodology for Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of the PPUC’s Order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and filed a petition with the PPUC pursuant to its Order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999.

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 all intervened in the case. 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 above. On May 4, 2006, the PPUC approved the modified request. Accordingly, Met-Ed and Penelec have deferred approximately $90 million and $21 million, respectively, representing transmission costs that were incurred from January 1, 2006 through September 30, 2006. On June 5, 2006, the OCA filed before the Commonwealth Court a petition for review of the PPUC’s approval of the deferral. On July 12, 2006, the Commonwealth Court granted the PPUC’s motion to quash the OCA’s appeal. The ratemaking treatment of the deferrals will be determined in the comprehensive rate filing proceeding discussed further above.

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 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 before the PPUC 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. On April 20, 2006, the PPUC approved the Recommended Decision with additional modifications to use an RFP process with two separate solicitations. An initial solicitation was held for Penn in May 2006 with all tranches fully subscribed, which was approved by the PPUC on June 2, 2006. On July 18, 2006, the second PLR solicitation was held for Penn. The tranches for the Residential Group and Small Commercial Group were fully subscribed. However, supply was not acquired for two tranches for the Large Commercial Group. On July 20, 2006, the PPUC approved the submissions for the second bid. A contingency solicitation was held on August 15, 2006 for the two remaining Large Commercial Group tranches. The PPUC rejected the bids from the contingency solicitation and directed Penn’s independent auction manager to offer the two unfilled Large Commercial tranches to the companies which had won tranches in the prior solicitations. This resulted in the acquisition of a supplier for the two remaining tranches, which were filed and accepted by the PPUC in a secretarial letter that was entered on September 22, 2006. On August 24, 2006, Penn made a compliance filing. OCA and OSBA filed exceptions to the compliance filing. Penn filed reply exceptions on September 5, 2006. On September 21, 2006, Penn submitted a revised compliance filing to the PPUC for the Residential Group and Small Commercial Group as a result of an agreement between Penn, OCA and OSBA. The PPUC approved proposed rates for the large commercial and industrial customers at the PPUC Public meeting on October 19, 2006, and found that the results of the competitive solicitation process were consistent with prevailing market prices.

On May 25, 2006, Penn filed a Petition for Review of the PPUC’s Orders of April 28, 2006 and May 4, 2006, which together decided the issues associated with Penn’s proposed Interim PLR Supply Plan. Penn has asked the Commonwealth Court to review the PPUC’s decision to deny Penn’s recovery of certain PLR costs through a reconciliation mechanism and the PPUC’s decision to impose a geographic limitation on the sources of alternative energy credits. On June 7, 2006, the PaDEP filed a Petition for Review appealing the PPUC’s ruling on the method by which alternative energy credits may be acquired and traded. Penn is unable to predict the outcome of this appeal.

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 September 30, 2006, the accumulated deferred cost balance totaled approximately $340 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 June 8, 2006, the NJBPU approved JCP&L’s request to issue securitization bonds associated with BGS stranded cost deferrals. On August 10, 2006, JCP&L Transition Funding II, a wholly owned subsidiary of JCP&L, issued $182 million of transition bonds with a weighted average interest rate of 5.5%.

On December 2, 2005, JCP&L filed its 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 23, 2006, JCP&L filed updated data reflecting actual amounts through December 31, 2005 of $154 million of costs incurred since July 31, 2003. On March 29, 2006, a pre-hearing conference was held with the presiding ALJ. On July 18, 2006, JCP&L filed rebuttal testimony that included a request for an additional $14 million of costs that had been eliminated from the securitized amount. Evidentiary hearings were held during September 2006 and the briefing schedule has been postponed pending settlement discussions.

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 latest quarterly reliability reports were submitted on September 12, 2006. As of September 30, 2006, there were no performance penalties issued by the NJBPU.

Reacting 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. On June 21, 2006, the NJBPU approved the continued use of a descending block auction for the Fixed Price Residential Class. JCP&L filed its 2007 BGS company specific addendum on July 10, 2006. On October 27, 2006, the NJBPU approved the auction format to procure the 2007 Commercial Industrial Energy Price as well as the specific rules for both the Fixed Price and Commercial Industrial Energy Price auctions. These rules were essentially unchanged from the prior auctions.

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 the Ratepayer Advocate’s comments. A schedule for further NJBPU 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 repeal of PUHCA pursuant to 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 on February 7, 2006 and comments were submitted to the NJBPU. On August 16, 2006, the NJBPU approved the regulations with an effective date of October 2, 2006. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006.

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. JCP&L filed a request with the IRS for a ruling on the issue. JCP&L was advised by the IRS on April 10, 2006 that the ruling was tentatively adverse. On April 28, 2006, the NJBPU directed JCP&L to withdraw its request for a private letter ruling on this issue, which had been previously filed with the IRS as ordered by the NJBPU. On May 11, 2006, after a JCP&L Motion for Reconsideration was denied by the NJBPU, JCP&L filed to withdraw the request for a private letter ruling. On July 19, 2006, the IRS acknowledged that the JCP&L ruling request was withdrawn.

FERC MATTERS

On November 1, 2004, ATSI filed with the FERC a request to defer approximately $54 million of costs to be incurred from 2004 through 2007 in connection with ATSI’s 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 $34 million has been deferred as of September 30, 2006). On March 28, 2006, ATSI and MISO filed with the 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 was June 1, 2006. Various parties filed comments responsive to the March 28, 2006 submission. The FERC conditionally approved the filing on May 22, 2006, subject to a compliance filing that ATSI made on June 13, 2006. A request for rehearing of the FERC’s May 22, 2006 Order was filed by a party, which ATSI answered. On July 14, 2006, the FERC accepted ATSI’s June 13, 2006 compliance filing. The estimated annual revenues to ATSI from the VMEP cost recovery is $12 million for each of the five years beginning June 1, 2006. On October 25, 2006, the FERC denied the request for rehearing.

As a result of Penn’s PLR competitive solicitation process approved by the PPUC, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches will be supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. Interventions or protests were due on this filing on October 23, 2006. Penn was the only party to file an intervention in this proceeding. The FERC is expected to act on this filing on or before December 1, 2006.

On October 19, 2006, the FERC issued two final rules in connection with the Public Utility Holding Company Act of 2005 (PUHCA 2005). The final rules impose certain accounting, reporting and record-retention requirements for applicable holding companies and service companies, which includes FirstEnergy and certain of its subsidiaries.

12. - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SAB 108 - “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”

In September 2006, the SEC issued SAB 108, which provides interpretive guidance on how registrants should quantify financial statement misstatements. There is currently diversity in practice, with the two commonly used methods to quantify misstatements being the “rollover” method (which primarily focuses on the income statement impact of misstatements) and the “iron curtain” method (which focuses on the balance sheet impact). SAB 108 requires registrants to use a dual approach whereby both of these methods are considered in evaluating the materiality of financial statement errors. Prior materiality assessments will need to be reconsidered using both the rollover and iron curtain methods. This guidance will be effective for FirstEnergy in the fourth quarter of 2006. FE does not expect this Statement to have a material impact on its financial statements.

EITF 06-5 - “Accounting for Purchases of Life Insurance-Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4, Accounting for Purchases of Life Insurance”

In September 2006, the EITF reached a consensus on Issue 06-5 concluding that a policyholder should consider any additional amounts included in the contractual terms of the policy in determining the amount that could be realized under the insurance contract. Contractual limitations should be considered when determining the realizable amounts. Amounts that are recoverable by the policyholder at the discretion of the insurance company should be excluded from the amount that could be realized. Recoverable amounts in periods beyond one year from the surrender of the policy should be discounted in accordance with APB Opinion No. 21, “Interest on Receivables and Payables.” Consensus was also reached that a policyholder should determine the amount that could be realized under the insurance contract assuming the surrender of an individual-life by individual-life policy (or certificate by certificate in a group policy). Any amount that would ultimately be realized by the policyholder upon the assumed surrender of the final policy (or final certificate) should be included in the amount that could be realized under the insurance contract. The EITF also concluded that a policyholder should not discount the cash surrender value component of the amount that could be realized when contractual restrictions on the ability to surrender a policy exist. However, if the contractual limitations prescribe that the cash surrender value component of the amount that could be realized is a fixed amount, then the amount that could be realized should be discounted in accordance with APB Opinion No. 21. This Issue is effective for fiscal years beginning after December 15, 2006. FirstEnergy does not expect this EITF to have a material impact on its financial statements.

SFAS 157 - “Fair Value Measurements”

In September 2006, the FASB issued SFAS 157, that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements.

This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.

SFAS 158 - “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)”

In September 2006, the FASB issued SFAS 158, which requires companies to recognize a net liability or asset to report the overfunded or underfunded status of their defined benefit pension and other postretirement benefit plans on their balance sheets and recognize changes in funded status in the year in which the changes occur through other comprehensive income. The funded status to be measured is the difference between plan assets at fair value and the benefit obligation. This Statement requires that gains and losses and prior service costs or credits, net of tax, that arise during the period be recognized as a component of other comprehensive income and not as components of net periodic benefit cost. Additional information should also be disclosed in the notes to the financial statements about certain effects on net periodic benefit cost for the next fiscal year that arise from delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation. Upon the initial application of this Statement and subsequently, an employer should continue to apply the provisions in Statements 87, 88 and 106 in measuring plan assets and benefit obligations as of the date of its statement of financial position and in determining the amount of net periodic benefit cost. This Statement is effective for FirstEnergy as of December 31, 2006. Based upon the December 31, 2005 measurement date, the estimated balance sheet impacts of adopting this Statement are a reduction in total assets of $0.4 billion, an increase in liabilities of $0.6 billion and a decrease in equity of $1 billion, before recognition of any related regulatory assets that may be appropriate under the circumstances.

FSP FIN 46(R)-6 - “Determining the Variability to Be Considered in Applying FASB interpretation No. 46(R)”

In April 2006, the FASB issued FSP FIN 46(R)-6 that addresses how a reporting enterprise should determine the variability to be considered in applying FASB interpretation No. 46 (revised December 2003). FirstEnergy adopted FIN 46(R) in the first quarter of 2004, consolidating VIE’s when FirstEnergy or one of its subsidiaries is determined to be the VIE’s primary beneficiary. The variability that is considered in applying interpretation 46(R) affects the determination of (a) whether the entity is a VIE; (b) which interests are variable interests in the entity; and (c) which party, if any, is the primary beneficiary of the VIE. This FSP states that the variability to be considered shall be based on an analysis of the design of the entity, involving two steps:

Step 1:	Analyze the nature of the risks in the entity
Step 2:	Determine the purpose(s) for which the entity was created and determine the variability the entity is designed to create and pass along to its interest holders.

After determining the variability to consider, the reporting enterprise can determine which interests are designed to absorb that variability. The guidance in this FSP is applied prospectively to all entities (including newly created entities) with which that enterprise first becomes involved and to all entities previously required to be analyzed under interpretation 46(R) when a reconsideration event has occurred after July 1, 2006. FirstEnergy does not expect this Statement to have a material impact on its financial statements.

FIN 48 - “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109.”

In June 2006, the FASB issued FIN 48 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken on a tax return. This interpretation also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation will be a two-step process. The first step will determine if it is more likely than not that a tax position will be sustained upon examination and should therefore be recognized. The second step will measure a tax position that meets the more likely than not recognition threshold to determine the amount of benefit to recognize in the financial statements. This interpretation is effective for fiscal years beginning after December 15, 2006. FirstEnergy is currently evaluating the impact of this Statement.

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 September 30, 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 the electric power needs of FirstEnergy’s end-use customers through retail and wholesale arrangements, including regulated retail sales to meet all or a portion of the PLR requirements of FirstEnergy's Ohio and Pennsylvania companies and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns and operates FirstEnergy's generating facilities and purchases electricity 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 revised 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 the revised 2005 segment reporting primarily includes the transfer 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 rates used in the two reportable segments’ results for 2005 and 2006 have been changed to 40% from the 41% previously reported in their 2005 segment results. The net amounts of the changes in the 2005 reportable segments' income taxes reclassifications have been correspondingly offset in the 2005 "Reconciling Adjustments." FSG is being disclosed as a reportable 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."

Segment Financial Information			Power
			Supply
	Regulated		Management			Facilities					Reconciling
Three Months Ended	Services		Services			Services		Other			Adjustments			Consolidated
	*(In millions)*
September 30, 2006
External revenues	$	1,290	$	2,066		$	47	$	14		$	(16	)	$	3,401
Internal revenues		-		-			-		-			-			-
Total revenues		1,290		2,066			47		14			(16	)		3,401
Depreciation and amortization		280		(44	)		-		1			6			243
Investment Income		67		19			-		-			(40	)		46
Net interest charges		102		56			-		1			21			180
Income taxes		200		119			-		(15	)		(32	)		272
Income before discontinued operations		297		180			1		27			(51	)		454
Discontinued operations		-		-			-		-			-			-
Net income		297		180			1		27			(51	)		454
Total assets		24,181		6,822			30		290			839			32,162
Total goodwill		5,911		24			-		-			-			5,935
Property additions		123		126			-		-			3			252

September 30, 2005
External revenues	$	1,481	$	1,824		$	59	$	138		$	2		$	3,504
Internal revenues		79		-			-		-			(79	)		-
Total revenues		1,560		1,824			59		138			(77	)		3,504
Depreciation and amortization		409		(22	)		-		1			5			393
Investment income		83		-			-		-			-			83
Net interest charges		88		11			-		1			57			157
Income taxes		264		(9	)		-		3			(21	)		237
Income before discontinued operations		395		(13	)		-		6			(56	)		332
Discontinued operations		-		-			-		-			-			-
Net income		395		(13	)		-		6			(56	)		332
Total assets		28,385		1,741			82		522			644			31,374
Total goodwill		5,938		24			-		62			-			6,024
Property additions		207		79			-		1			7			294

Nine Months Ended

September 30, 2006
External revenues	$	3,417	$	5,364		$	150		$	149		$	(49	)	$	9,031
Internal revenues		-		-			-			-			-			-
Total revenues		3,417		5,364			150			149			(49	)		9,031
Depreciation and amortization		765		(54	)		-			3			17			731
Investment Income		204		36			-			1			(121	)		120
Net interest charges		291		160			-			5			57			513
Income taxes		499		236			2			(21	)		(93	)		623
Income before discontinued operations		736		355			(11	)		37			(138	)		979
Discontinued operations		-		-			-			-			-			-
Net income		736		355			(11	)		37			(138	)		979
Total assets		24,181		6,822			30			290			839			32,162
Total goodwill		5,911		24			-			-			-			5,935
Property additions		492		473			-			2			23			990

September 30, 2005
External revenues	$	3,923	$	4,617		$	162		$	385		$	10		$	9,097
Internal revenues		238		-			-			-			(238	)		-
Total revenues		4,161		4,617			162			385			(228	)		9,097
Depreciation and amortization		1,128		(26	)		-			2			18			1,122
Investment income		171		-			-			-			-			171
Net interest charges		285		29			1			4			170			489
Income taxes		613		(43	)		4			13			12			599
Income before discontinued operations		920		(64	)		(6	)		18			(216	)		652
Discontinued operations		-		-			13			5			-			18
Net income		920		(64	)		7			23			(216	)		670
Total assets		28,385		1,741			82			522			644			31,374
Total goodwill		5,938		24			-			62			-			6,024
Property additions		506		226			1			5			18			756

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.

15. - JCP&L RESTATEMENT

JCP&L's earnings for the three months and nine months ended September 30, 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 $0.7 million and $0.6 million, respectively, in the third quarter of 2005 and understated by $1.6 million and $1.8 million, respectively, in the nine months ended September 30, 2005. The effects of these adjustments on JCP&L's Consolidated Statements of Income for the three months and nine months ended September 30, 2005 are as follows:

		Three Months			Nine Months
		As Previously		As	As Previously		As
		Reported		Restated	Reported		Restated
		*(In millions)*
Operating Revenues	$	900.3	$	900.3	$	2,024.7	$	2,024.7
Operating Expenses and
Taxes		809.2		809.9		1,825.1		1,826.7
Operating Income		91.1		90.4		199.6		198.0
Other Income		3.0		3.0		3.3		3.3
Net Interest Charges		18.9		19.5		57.9		59.7
Net Income	$	75.2	$	73.9	$	145.0	$	141.6
Earnings Applicable
to Common Stock	$	75.0	$	73.8	$	144.6	$	141.3

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

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.

333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3491	PENNSYLVANIA POWER COMPANY	25-0718810
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

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

	OUTSTANDING
CLASS	AS OF OCTOBER 31, 2006
FirstEnergy Corp., $.10 par value	319,205,517
Ohio Edison Company, no par value	80
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

		Pages
Glossary of Terms		iii-v

Part I. Financial Information

Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations.

	Notes to Consolidated Financial Statements	1-30

FirstEnergy Corp.

	Consolidated Statements of Income	31
	Consolidated Statements of Comprehensive Income	32
	Consolidated Balance Sheets	33
	Consolidated Statements of Cash Flows	34
	Report of Independent Registered Public Accounting Firm	35
	Management's Discussion and Analysis of Results of Operations and	36-76
	Financial Condition

Ohio Edison Company

	Consolidated Statements of Income and Comprehensive Income	77
	Consolidated Balance Sheets	78
	Consolidated Statements of Cash Flows	79
	Report of Independent Registered Public Accounting Firm	80
	Management's Discussion and Analysis of Results of Operations and	81-96
	Financial Condition

The Cleveland Electric Illuminating Company

	Consolidated Statements of Income and Comprehensive Income	97
	Consolidated Balance Sheets	98
	Consolidated Statements of Cash Flows	99
	Report of Independent Registered Public Accounting Firm	100
	Management's Discussion and Analysis of Results of Operations and	101-114
	Financial Condition

The Toledo Edison Company

	Consolidated Statements of Income and Comprehensive Income	115
	Consolidated Balance Sheets	116
	Consolidated Statements of Cash Flows	117
	Report of Independent Registered Public Accounting Firm	118
	Management's Discussion and Analysis of Results of Operations and	119-131
	Financial Condition

Pennsylvania Power Company

	Consolidated Statements of Income	132
	Consolidated Balance Sheets	133
	Consolidated Statements of Cash Flows	134
	Report of Independent Registered Public Accounting Firm	135
	Management's Discussion and Analysis of Results of Operations and	136-144
	Financial Condition

		Pages
Jersey Central Power & Light Company

	Consolidated Statements of Income and Comprehensive Income	145
	Consolidated Balance Sheets	146
	Consolidated Statements of Cash Flows	147
	Report of Independent Registered Public Accounting Firm	148
	Management's Discussion and Analysis of Results of Operations and	149-159
	Financial Condition

Metropolitan Edison Company

	Consolidated Statements of Income and Comprehensive Income	160
	Consolidated Balance Sheets	161
	Consolidated Statements of Cash Flows	162
	Report of Independent Registered Public Accounting Firm	163
	Management's Discussion and Analysis of Results of Operations and	164-174
	Financial Condition

Pennsylvania Electric Company

	Consolidated Statements of Income and Comprehensive Income	175
	Consolidated Balance Sheets	176
	Consolidated Statements of Cash Flows	177
	Report of Independent Registered Public Accounting Firm	178
	Management's Discussion and Analysis of Results of Operations and	179-189
	Financial Condition

Item 3. Quantitative and Qualitative Disclosures About Market Risk.		190

Item 4. Controls and Procedures.		190

Part II. Other Information

Item 1. Legal Proceedings.		191

Item 1A. Risk Factors.		191

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.		191

Item 6. Exhibits.		192-193

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 Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
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 No. 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
B&W	Babcock & Wilcox Company
Bechtel	Bechtel Power Corporation
BGS	Basic Generation Service
BTU	British Thermal Unit
CAIDI	Customer Average Interruption Duration Index
CAIR	Clean Air Interstate Rule
CAL	Confirmatory Action Letter
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CIEP	Commercial Industrial Energy Price
CO₂	Carbon Dioxide
CTC	Competitive Transition Charge
DCPD	Deferred Compensation Plan for Outside Directors
DIG C20	Derivatives Implementation Group Issue No. C20, “Scope Exceptions: Interpretations of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature”

DOJ	U.S. Department of Justice
DRA	Division of the Ratepayer Advocate
ECAR	East Central Area Reliability Coordination Agreement
EDCP	Executive Deferred Compensation Plan
EITF	Emerging Issues Task Force
EPA	U.S. Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ERO	Electric Reliability Organization
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	U.S. Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46(R)	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"
FIN 46(R)-6	FIN 46(R)-6, “Determining the Variability to be Considered in Applying FASB interpretation No. 46(R)”
FIN 47	FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No.109”
FMB	First Mortgage Bonds
FSP	FASB Staff Position
FSP FIN 13-2	FSP FIN 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction”
GAAP	Accounting Principles Generally Accepted in the United States
GCAF	Generation Charge Adjustment Factor
GHG	Greenhouse Gases
KWH	Kilowatt-hours
LOC	Letter of Credit
LTIP	Long-Term Incentive Program
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MOU	Memorandum of Understanding
MSG	Market Support Generation
MTC	Market Transition Charge
MW	Megawatts
MWH	Megawatt-hours
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NJBPU	New Jersey Board of Public Utilities
NOAC	Northwest Ohio Aggregation Coalition
NOPR	Notice of Proposed Rulemaking
NOV	Notices of Violation
NO_X	Nitrogen Oxide
NRC	U.S. 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
PaDEP	Pennsylvania Department of Environmental Protection
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
RTOR	Regional Through and Out Rates
S&P	Standard & Poor’s Ratings Service
SAB 108	SEC Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”
SAIFI	System Average Interruption Frequency Index
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
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 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
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 157	SFAS No. 157, “Fair Value Measurements”
SFAS 158	SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)”
SIP	State Implementation Plan(s) Under the Clean Air Act
SO₂	Sulfur Dioxide
SRM	Special Reliability Master
TBC	Transition Bond Charge
TMI-2	Three Mile Island Unit 2
VIE	Variable Interest Entity
VMEP	Vegetation Management Enhancement Project

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	*(In millions, except per share amounts)*
REVENUES:
Electric utilities	$	2,996		$	2,853		$	7,677		$	7,403
Unregulated businesses		405			651			1,354			1,694
Total revenues		3,401			3,504			9,031			9,097

EXPENSES:
Fuel and purchased power		1,317			1,287			3,306			3,115
Other operating expenses		794			993			2,446			2,750
Provision for depreciation		153			152			445			444
Amortization of regulatory assets		243			366			665			983
Deferral of new regulatory assets		(153	)		(125	)		(379	)		(305	)
General taxes		187			188			553			541
Total expenses		2,541			2,861			7,036			7,528

OPERATING INCOME		860			643			1,995			1,569

OTHER INCOME (EXPENSE):
Investment income		46			83			120			171
Interest expense		(185	)		(162	)		(528	)		(488	)
Capitalized interest		7			8			21			12
Subsidiaries’ preferred stock dividends		(2	)		(3	)		(6	)		(13	)
Total other expense		(134	)		(74	)		(393	)		(318	)

INCOME BEFORE INCOME TAXES AND
DISCONTINUED OPERATIONS		726			569			1,602			1,251

INCOME TAXES		272			237			623			599

INCOME BEFORE DISCONTINUED OPERATIONS		454			332			979			652

Discontinued operations (net of income tax benefit
of $9 million) (Note 4)		-			-			-			18

NET INCOME	$	454		$	332		$	979		$	670

BASIC EARNINGS PER SHARE OF COMMON STOCK:
Earnings before discontinued operations (Note 2)	$	1.41		$	1.01		$	2.99		$	1.99
Discontinued operations (Note 4)		-			-			-			0.05
Net earnings per basic share	$	1.41		$	1.01		$	2.99		$	2.04

WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING		322			328			326			328

DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Earnings before discontinued operations (Note 2)	$	1.40		$	1.01		$	2.97		$	1.98
Discontinued operations (Note 4)		-			-			-			0.05
Net earnings per diluted share	$	1.40		$	1.01		$	2.97		$	2.03

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING		325			330			329			330

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.45		$	0.43		$	1.35		$	1.255

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
statements.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006		2005
	*(In millions)*

NET INCOME	$	454		$	332		$	979	$	670

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on derivative hedges		(28	)		18			45		19
Unrealized gain (loss) on available for sale securities		26			(13	)		39		(37	)
Other comprehensive income (loss)		(2	)		5			84		(18	)
Income tax expense (benefit) related to other
comprehensive income		(1	)		(2	)		30		(8	)
Other comprehensive income (loss), net of tax		(1	)		7			54		(10	)

COMPREHENSIVE INCOME	$	453		$	339		$	1,033	$	660


The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of
these statements.

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,			December 31,
		2006			2005
		*(In millions)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	41		$	64
Receivables -
Customers (less accumulated provisions of $44 million and
$38 million, respectively, for uncollectible accounts)		1,226			1,293
Other (less accumulated provisions of $26 million and
$27 million, respectively, for uncollectible accounts)		194			205
Materials and supplies, at average cost		585			518
Prepayments and other		168			237
		2,214			2,317
PROPERTY, PLANT AND EQUIPMENT:
In service		23,823			22,893
Less - Accumulated provision for depreciation		9,986			9,792
		13,837			13,101
Construction work in progress		673			897
		14,510			13,998
INVESTMENTS:
Nuclear plant decommissioning trusts		1,874			1,752
Investments in lease obligation bonds		830			890
Other		770			709
		3,474			3,351
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,935			6,010
Regulatory assets		4,434			4,486
Prepaid pension costs		1,008			1,023
Other		587			656
		11,964			12,175
	$	32,162		$	31,841
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	1,667		$	2,043
Short-term borrowings		1,213			731
Accounts payable		611			727
Accrued taxes		752			800
Other		1,021			1,152
		5,264			5,453
CAPITALIZATION:
Common stockholders’ equity -
Common stock, $.10 par value, authorized 375,000,000 shares -
319,205,517 and 329,836,276 shares outstanding, respectively		32			33
Other paid-in capital		6,460			7,043
Accumulated other comprehensive income (loss)		34			(20	)
Retained earnings		2,695			2,159
Unallocated employee stock ownership plan common stock -
718,671 and 1,444,796 shares, respectively		(13	)		(27	)
Total common stockholders' equity		9,208			9,188
Preferred stock of consolidated subsidiaries		80			184
Long-term debt and other long-term obligations		8,760			8,155
		18,048			17,527
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,778			2,726
Asset retirement obligations		1,179			1,126
Power purchase contract loss liability		1,205			1,226
Retirement benefits		1,372			1,316
Lease market valuation liability		788			851
Other		1,528			1,616
		8,850			8,861
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	32,162		$	31,841

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	September 30,
	2006			2005
	*(In millions)*

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	979		$	670
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation		445			444
Amortization of regulatory assets		665			983
Deferral of new regulatory assets		(379	)		(305	)
Nuclear fuel and lease amortization		67			63
Deferred purchased power and other costs		(323	)		(258	)
Deferred income taxes and investment tax credits, net		36			24
Deferred rents and lease market valuation liability		(54	)		(71	)
Accrued compensation and retirement benefits		78			72
Commodity derivative transactions, net		28			(8	)
Gain on asset sales		(38	)		-
Income from discontinued operations		-			(18	)
Cash collateral		(98	)		49
Decrease (increase) in operating assets -
Receivables		(7	)		(226	)
Materials and supplies		(30	)		(40	)
Prepayments and other current assets		(49	)		(57	)
Increase (decrease) in operating liabilities -
Accounts payable		(93	)		60
Accrued taxes		(35	)		207
Accrued interest		104			92
Electric service prepayment programs		(45	)		218
Other		(8	)		17
Net cash provided from operating activities		1,243			1,916

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		1,235			334
Short-term borrowings, net		482			77
Redemptions and Repayments -
Common stock		(600	)		-
Preferred stock		(107	)		(170	)
Long-term debt		(993	)		(852	)
Net controlled disbursement activity		(22	)		(27	)
Common stock dividend payments		(439	)		(411	)
Net cash used for financing activities		(444	)		(1,049	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(990	)		(756	)
Proceeds from asset sales		83			61
Proceeds from nuclear decommissioning trust fund sales		1,325			1,140
Investments in nuclear decommissioning trust funds		(1,336	)		(1,216	)
Cash investments		109			21
Other		(13	)		(30	)
Net cash used for investing activities		(822	)		(780	)

Net increase (decrease) in cash and cash equivalents		(23	)		87
Cash and cash equivalents at beginning of period		64			53
Cash and cash equivalents at end of period	$	41		$	140

The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

Non-GAAP to GAAP Reconciliation	2006						2005
	After-tax			Basic			After-tax			Basic
	Amount			Earnings			Amount			Earnings
Three Months Ended September 30,	(Millions)			Per Share			(Millions)			Per Share
Earnings Before Unusual Items (Non-GAAP)	$	459		$	1.42		$	342		$	1.04
Unusual Items:
PPUC NUG adjustment applicable to prior years		(6	)		(0.02	)		-			-
Non-core asset sales/impairments		1			0.01			-			-
JCP&L arbitration decision		-			-			(10	)		(0.03	)
Net Income (GAAP)	$	454		$	1.41		$	332		$	1.01

Nine Months Ended September 30,
Earnings Before Unusual Items (Non-GAAP)	$	995		$	3.04		$	730		$	2.22
Unusual Items:
PPUC NUG adjustment applicable to prior years		(6	)		(0.02	)		-			-
Non-core asset sales/impairments		(10	)		(0.03	)		22			0.07
Sammis plant New Source Review settlement		-			-			(14	)		(0.04	)
Davis-Besse NRC fine		-			-			(3	)		(0.01	)
New regulatory assets - JCP&L rate settlement								16			0.05
JCP&L arbitration decision		-			-			(10	)		(0.03	)
Ohio tax write-off		-			-			(71	)		(0.22	)
Net Income (GAAP)	$	979		$	2.99		$	670		$	2.04

·	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 or, in some cases, purchased from independent suppliers in the states where the utility subsidiaries operate.

·	Power Supply Management Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including regulated retail sales to meet all or a portion of the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns and operates FirstEnergy's generating facilities and purchases electricity 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.

	Three Months Ended September 30,									Nine Months Ended September 30,
							Increase									Increase
	2006			2005			(Decrease)			2006			2005			(Decrease)
	*(In millions, except per share amounts)*
Net Income (Loss)
By Business Segment:
Regulated Services	$	297		$	395		$	(98	)	$	736		$	920		$	(184	)
Power supply management services		180			(13	)		193			355			(64	)		419
Other and reconciling adjustments*		(23	)		(50	)		27			(112	)		(186	)		74
Total	$	454		$	332		$	122		$	979		$	670		$	309

Basic Earnings Per Share:
Earnings before discontinued operations	$	1.41		$	1.01		$	0.40		$	2.99		$	1.99		$	1.00
Discontinued operations		-			-			-			-			0.05			(0.05	)
Net earnings per basic share	$	1.41		$	1.01		$	0.40		$	2.99		$	2.04		$	0.95

Diluted Earnings Per Share:
Earnings before discontinued operations	$	1.40		$	1.01		$	0.39		$	2.97		$	1.98		$	0.99
Discontinued operations		-			-			-			-			0.05			(0.05	)
Net earnings per diluted share	$	1.40		$	1.01		$	0.39		$	2.97		$	2.03		$	0.94

				Power
				Supply			Other and
	Regulated			Management			Reconciling			FirstEnergy
3rd Quarter 2006 Financial Results	Services			Services			Adjustments			Consolidated
	*(In millions)*
Revenues:
External
Electric	$	1,124		$	1,991		$	-		$	3,115
Other		166			75			45			286
Internal		-			-			-			-
Total Revenues		1,290			2,066			45			3,401

Expenses:
Fuel and purchased power		-			1,317			-			1,317
Other operating expenses		338			414			42			794
Provision for depreciation		96			50			7			153
Amortization of regulatory assets		238			5			-			243
Deferral of new regulatory assets		(54	)		(99	)		-			(153	)
General taxes		140			43			4			187
Total Expenses		758			1,730			53			2,541

Operating Income (Loss)		532			336			(8	)		860
Other Income (Expense):
Investment income		67			19			(40	)		46
Interest expense		(104	)		(58	)		(23	)		(185	)
Capitalized interest		4			2			1			7
Subsidiaries' preferred stock dividends		(2	)		-			-			(2	)
Total Other Income (Expense)		(35	)		(37	)		(62	)		(134	)

Income before income taxes		497			299			(70	)		726
Income tax expense (benefit)		200			119			(47	)		272
Net Income (Loss)	$	297		$	180		$	(23	)	$	454

				Power
Change Between 3rd Quarter 2006 and				Supply			Other and
3rd Quarter 2005 Financial Results	Regulated			Management			Reconciling			FirstEnergy
Increase (Decrease)	Services			Services			Adjustments			Consolidated
	*(In millions)*
Revenues:
External
Electric	$	(216	)	$	214		$	-		$	(2	)
Other		25			28			(154	)		(101	)
Internal		(79	)		-			79			-
Total Revenues		(270	)		242			(75	)		(103	)

Expenses:
Fuel and purchased power		-			30			-			30
Other operating expenses		1			(123	)		(77	)		(199	)
Provision for depreciation		(41	)		41			1			1
Amortization of regulatory assets		(128	)		5			-			(123	)
Deferral of new regulatory assets		40			(68	)		-			(28	)
General taxes		(10	)		10			(1	)		(1	)
Total Expenses		(138	)		(105	)		(77	)		(320	)

Operating Income		(132	)		347			2			217
Other Income (Expense):
Investment income		(16	)		19			(40	)		(37	)
Interest expense		(13	)		(46	)		35			(24	)
Capitalized interest		(2	)		1			1			-
Subsidiaries' preferred stock dividends		1			-			-			1
Total Other Income (Expense)		(30	)		(26	)		(4	)		(60	)

Income before income taxes		(162	)		321			(2	)		157
Income taxes		(64	)		128			(29	)		35
Net Income	$	(98	)	$	193		$	27		$	122

	Three Months Ended September 30,
					Increase
Revenues By Type of Service	2006		2005		(Decrease)
	*(In millions)*
Distribution services	$	1,124	$	1,340	$	(216	)
Transmission services		109		117		(8	)
Internal lease revenues		-		79		(79	)
Other		57		24		33
Total Revenues	$	1,290	$	1,560	$	(270	)

Electric Distribution Deliveries
Residential	(4.9	)%
Commercial	(1.0	)%
Industrial	(0.6	)%
Total Distribution Deliveries	(2.3	)%

Sources of Change in Distribution Revenues	Increase (Decrease)
	*(In millions)*
Changes in customer usage	$	(70	)
Ohio shopping incentives		77
Reduced Ohio transition rates		(244	)
Other		21

Net Decrease in Distribution Revenues	$	(216	)

	Increase
Source of Change in Electric Generation Sales	(Decrease)
	*(In millions)*
Retail:
Effect of 7.7% increase in customer usage	$	97
Increased prices		289
		386
Wholesale:
Effect of 32.9% decrease in KWH sales		(141	)
Lower prices		(60	)
		(201	)
Net Increase in Electric Generation Sales	$	185

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	*(In millions)*
Fuel:
Change due to increased unit costs	$	12
Change due to volume consumed		(4	)
		8
Purchased Power:
Change due to increased unit costs		68
Change due to volume purchased		(32	)
PPUC NUG adjustment applicable to prior year		10
Increase in NUG costs deferred		(24	)
		22

Net Increase in Fuel and Purchased Power Costs	$	30

·	Investment income in the third quarter of 2006 increased by $19 million over the prior year primarily due to nuclear decommissioning trust investments acquired through the generation asset transfers; and

·	Interest expense increased by $46 million in the third quarter of 2006 primarily due to the interest expense on associated company notes payable that financed the generation asset transfers.

				Power
Change Between First Nine Months of 2006				Supply			Other and
and First Nine Months of 2005	Regulated			Management			Reconciling			FirstEnergy
Financial Results - Increase (Decrease)	Services			Services			Adjustments			Consolidated
	*(In millions)*
Revenues:
External
Electric	$	(537	)	$	684		$	-		$	147
Other		31			63			(307	)		(213	)
Internal		(238	)		-			238			-
Total Revenues		(744	)		747			(69	)		(66	)

Expenses:
Fuel and purchased power		-			191			-			191
Other operating expenses		(42	)		(235	)		(27	)		(304	)
Provision for depreciation		(119	)		120			-			1
Amortization of regulatory assets		(333	)		15			-			(318	)
Deferral of new regulatory assets		89			(163	)		-			(74	)
General taxes		(14	)		26			-			12
Total Expenses		(419	)		(46	)		(27	)		(492	)

Operating Income		(325	)		793			(42	)		426
Other Income (Expense):
Investment income		33			36			(120	)		(51	)
Interest expense		(8	)		(140	)		108			(40	)
Capitalized interest		(1	)		9			1			9
Subsidiaries' preferred stock dividends		3			-			4			7
Total Other Income (Expense)		27			(95	)		(7	)		(75	)

Income before income taxes and discontinued operations		(298	)		698			(49	)		351
Income taxes		(114	)		279			(141	)		24
Income before discontinued operations		(184	)		419			92			327
Discontinued operations		-			-			(18	)		(18	)
Net Income	$	(184	)	$	419		$	74		$	309

·	Investment income in the first nine months of 2006 was $36 million higher primarily due to nuclear decommissioning trust investments acquired through the generation asset transfers; and

·	Interest expense increased by $140 million, primarily due to interest on the associated company notes payable that financed the generation asset transfers. This increase was partially offset by an additional $9 million of capitalized interest.

	Nine Months Ended
	September 30,
Operating Cash Flows	2006		2005
	*(In millions)*
Cash earnings *	$ 1,472		$ 1,572
Working capital and other	(229	)	344
Net cash provided from operating activities	$ 1,243		$ 1,916

* Cash earnings are a Non-GAAP measure (see reconciliation below).

	Nine Months Ended
	September 30,
Reconciliation of Cash Earnings	2006			2005
	*(In millions)*
Net income (GAAP)	$	979		$	670
Non-cash charges (credits):
Provision for depreciation		445			444
Amortization of regulatory assets		665			983
Deferral of new regulatory assets		(379	)		(305	)
Nuclear fuel and lease amortization		67			63
Deferred purchased power and other costs		(323	)		(258	)
Deferred income taxes and investment tax credits		36			24
Deferred rents and lease market valuation liability		(54	)		(71	)
Accrued compensation and retirement benefits		78			72
Gain on asset sales		(38	)		-
Income from discontinued operations		-			(18	)
Other non-cash expenses		(4	)		(32	)
Cash earnings (Non-GAAP)	$	1,472		$	1,572

	Nine Months Ended
	September 30,
Securities Issued or Redeemed	2006		2005
	*(In millions)*
New issues
Pollution control notes	$	253	$	334
Secured notes		382		-
Unsecured notes		600		-
	$	1,235	$	334
Redemptions
First mortgage bonds	$	-	$	178
Pollution control notes		311		377
Secured notes		182		74
Unsecured notes		500		8
Long-term revolving credit		-		215
Common stock		600		-
Preferred stock		107		170
	$	1,700	$	1,022

Short-term borrowings, net	$	482	$	77

Borrowing Capability
Short-term credit facilities⁽¹⁾	$	2,870
Accounts receivable financing facilities		550
Utilized		(1,207	)
LOCs		(85	)
Net	$	2,128

⁽¹⁾ A $2.75 billion revolving credit facility that expires in 2011 is available in various amounts to FirstEnergy and certain of its subsidiaries, as described further below. A $100 million revolving credit facility that expires in December 2006 and a $20 million uncommitted line of credit facility are both available to FirstEnergy only.

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations⁽¹⁾
	*(In millions)*
FirstEnergy	$	2,750		$	1,500
OE		500			500
Penn		50			44
CEI		250	⁽3)		600
TE		250	⁽³⁾		500
JCP&L		425			429
Met-Ed		250			250	⁽²⁾
Penelec		250			250	⁽²⁾
FES		-	⁽⁴⁾		n/a
ATSI		-	⁽⁴⁾		50

Issuer	Securities	S&P	Moody’s	Fitch

FirstEnergy	Senior unsecured	BBB-	Baa3	BBB-

OE	Senior unsecured	BBB-	Baa2	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+

Met-Ed	Senior secured	BBB+	Baa1	BBB+
	Senior unsecured	BBB	Baa2	BBB

Penelec	Senior unsecured	BBB	Baa2	BBB

Summary of Cash Flows	Property
Used for Investing Activities	Additions				Investments			Other			Total
Sources (Uses)		*(In millions)*

Nine Months Ended September 30, 2006
Regulated services	$		(492	)	$	142		$	(8	)	$	(358	)
Power supply management services			(473	)		(7	)		(1	)		(481	)
Other			(1	)		(2	)		-			(3	)
Reconciling items			(24	)		24			20			20
Total	$		(990	)	$	157		$	11		$	(822	)

Nine Months Ended September 30, 2005
Regulated services	$		(506	)	$	(14	)	$	(7	)	$	(527	)
Power supply management services			(226	)		15			-			(211	)
Other			(6	)		3			(17	)		(20	)
Reconciling items			(18	)		(9	)		5			(22	)
Total	$		(756	)	$	(5	)	$	(19	)	$	(780	)

	Maximum
Guarantees and Other Assurances	Exposure
	*(In millions)*
FirstEnergy Guarantees of Subsidiaries:
Energy and Energy-Related Contracts⁽¹⁾	$	887
Other⁽²⁾		1,094
		1,981

Surety Bonds		147
LOC⁽³⁾⁽⁴⁾		1,434

Total Guarantees and Other Assurances	$	3,562

	Three Months Ended									Nine Months Ended
Increase (Decrease) in the Fair Value	September 30, 2006									September 30, 2006
of Commodity Derivative Contracts	Non-Hedge			Hedge			Total			Non-Hedge			Hedge			Total
	*(In millions)*
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability at beginning of period	$	(1,081	)	$	(4	)	$	(1,085	)	$	(1,170	)	$	(3	)	$	(1,173	)
New contract value when entered		-			-			-			-			-			-
Additions/change in value of existing contracts		(164	)		(6	)		(170	)		(195	)		(16	)		(211	)
Change in techniques/assumptions		-			-			-			-			-			-
Settled contracts		85			1			86			218			10			228
Other		-			-			-			(13	)		-			(13	)
Outstanding net liability at end of period ⁽¹⁾		(1,160	)		(9	)		(1,169	)		(1,160	)		(9	)		(1,169	)

Non-commodity Net Liabilities at End of Period:
Interest rate swaps ⁽²⁾		-			(32	)		(32	)		-			(32	)		(32	)
Net Liabilities - Derivative Contracts at End of Period	$	(1,160	)	$	(41	)	$	(1,201	)	$	(1,160	)	$	(41	)	$	(1,201	)

Impact of Changes in Commodity Derivative Contracts⁽³⁾
Income Statement effects (pre-tax)	$	3		$	-		$	3		$	-		$	-		$	-
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	(5	)	$	(5	)	$	-		$	(6	)	$	(6	)
Regulatory assets (net)	$	82		$	-		$	82		$	(23	)	$	-		$	(23	)

Balance Sheet Classification	Non-Hedge			Hedge			Total
	*(In millions)*
Current-
Other assets	$	-		$	10		$	10
Other liabilities		(1	)		(20	)		(21	)

Non-Current-
Other deferred charges		46			4			50
Other noncurrent liabilities		(1,205	)		(35	)		(1,240	)

Net liabilities	$	(1,160	)	$	(41	)	$	(1,201	)