EXHIBIT 99.1

FIRSTENERGY SOLUTIONS CORP.

SECOND QUARTER 2007 FINANCIAL STATEMENTS

FirstEnergy Solutions Corp. (FES) is a wholly owned subsidiary of FirstEnergy Corp. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its subsidiaries, FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp., owns and operates FirstEnergy’s fossil and hydroelectric generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FirstEnergy Nuclear Operating Company, a wholly owned subsidiary of FirstEnergy Corp., operates and maintains the nuclear generating facilities.

Contents	Page
Glossary of Terms	i-ii
Management's Discussion and Analysis of Financial Condition and Results of Operations	1-14
Consolidated Statements of Income (Unaudited)	15
Consolidated Balance Sheets (Unaudited)	16
Consolidated Statements of Cash Flows (Unaudited)	17
Notes to Consolidated Financial Statements (Unaudited)	18-35

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
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
FirstEnergy	FirstEnergy Corp., a diversified energy company
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	Met-Ed, Penelec and Penn
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AEP	American Electric Power Company, Inc.
AOCI	Accumulated Other Comprehensive Income
APIC	Additional Paid-In Capital
ARO	Asset Retirement Obligation
CAIR	Clean Air Interstate Rule
CAL	Confirmatory Action Letter
CAMR	Clean Air Mercury Rule
CO2	Carbon Dioxide
DOJ	United States Department of Justice
EITF	Emerging Issues Task Force
EITF 06-11	EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends or Share-Based    Payment Awards”
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
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”
FTR	Financial Transmission Rights
GAAP	Accounting Principles Generally Accepted in the United States
GAT	Intra-system transfer of non-nuclear generation and nuclear generation assets
GHG	Greenhouse Gases
IRS	United States Internal Revenue Service
KWH	Kilowatt-hours
MISO	Midwest Independent System Transmission Operator, Inc.
Moody’s	Moody’s Investors Service
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
OVEC	Ohio Valley Electric Corporation
PJM	PJM Interconnection L.L.C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreement

i

GLOSSARY OF TERMS Cont’d.
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RFP	Request for Proposal
S&P	Standard & Poor’s Ratings Service
SCR	Selective Catalytic Reduction
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 107	SFAS No. 107, “Disclosures about Fair Value of Financial Instruments”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 123(R)	SFAS No. 123(R), “Share-based Payment”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”
SIP	State Implementation Plan(s) Under the Clean Air Act
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
UCS	Union of Concerned Scientists

ii

FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements: This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), and the legal and regulatory changes resulting from the implementation of the EPACT (including, but not limited to, the repeal of the PUHCA), the uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated) or levels of emission reductions related to the consent decree resolving the Sammis NSR Litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC (including, but not limited to, the Demand for Information issued to FENOC on May 14, 2007) as disclosed in FirstEnergy’s SEC filings, the continuing availability and operation of generating units, the ability of our generating units to continue to operate at, or near full capacity, the inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives), the anticipated benefits from voluntary pension plan contributions, the ability to improve electric commodity margins, the ability to access the public securities and other capital markets and the cost of such capital, the risks and other factors discussed from time to time in FirstEnergy’s SEC filings, and other similar factors. Also, a security rating is not a recommendation to buy, sell or hold securities, and it may be subject to revision or withdrawal at any time and each such rating should be evaluated independently of any other rating. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

FES was organized under the laws of the State of Ohio in 1997 as a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services to wholesale and retail customers in the MISO and PJM markets. FES also owns and operates, through its subsidiary, FGCO, FirstEnergy’s fossil and hydroelectric generating facilities and owns, through its subsidiary, NGC, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities. In addition to the generation output of the facilities owned by FGCO and NGC, FES purchases the output relating to leasehold interests of OE, CEI and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full-output, cost-of-service power sale agreements. FGCO is also a sponsoring company and is entitled to a portion of the output from the plants owned by OVEC.

Revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective PLR obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies the majority of the PLR requirements of Penn at market-based rates as a result of a competitive solicitation conducted by Penn. FES’ existing contractual obligations to Penn expire on May 31, 2008, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.

Results of Operations

Net income increased to $151million in the second quarter of 2007 compared to $99million in the second quarter of 2006. In the first six months of 2007, net income increased to $254 million from $136 million in the same period of 2006. The increases in both periods of 2007 were primarily due to higher revenues, lower fuel and other operating expenses, partially offset by higher purchased power costs.

1

Revenues

Revenues increased by $75million in the second quarter of 2007 and $136 million in the first six months of 2007 compared to the same periods in 2006 due to increases in revenues from non-affiliated retail generation sales and affiliated wholesale sales, partially offset by lower non-affiliated wholesale sales. Retail generation sales revenues increased as a result of higher unit prices and increased KWH sales. Higher unit prices primarily reflected higher generation rates in the MISO and PJM markets where FES is an alternative supplier. Increased KWH sales to FES’ commercial and industrial customers during both periods of 2007 were partially offset by a decrease in sales to residential customers as a result of those customers returning to FES’ Ohio utility affiliates for their generation requirements. Affiliated wholesale revenues were higher as a result of increased sales and higher unit prices for sales to the Ohio Companies.

Non-affiliated wholesale revenues decreased as a result of lower sales of 27.9% and 31.4% in the second quarter and first six months of 2007, respectively, partially offset by higher unit prices. Lower non-affiliated wholesale sales resulted from less generation available for sale in the non-affiliated market due to increased affiliated company power sales requirements under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.

The increased affiliated company generation revenues in both periods of 2007 were due to higher unit prices and increased sales. The increase in sales to the Ohio Companies was due to their higher retail generation sales requirements. The higher unit prices resulted from the provision of the full-requirements PSA under which PSA revenue unit prices reflect the increase in the Ohio Companies’ retail generation sales unit prices. The higher sales to the Pennsylvania affiliates were due to increased Met-Ed and Penelec generation sales requirements. The increases were partially offset by lower sales to Penn as a result of the implementation of its competitive solicitation process in 2007.

Transmission revenue decreased by $19 million in the first six months of 2007 from the same period of 2006 primarily due to reduced retail MISO load, lower transmission tariff rates and reduced FTR revenue.

Changes in revenues in the second quarter and first six months of 2007 from the same periods of 2006 are summarized in the following tables:

	Three Months Ended
	June 30,				Increase
Revenues By Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	185	$	136	$	49
Wholesale		174		202		(28	)
Total Non-Affiliated Generation Sales		359		338		21
Affiliated Generation Sales		691		623		68
Transmission and Other		19		33		(14	)
Total Revenues	$	1,069	$	994	$	75

	Six Months Ended
	June 30,				Increase
Revenues by Type of Service	2007		2006		(Decrease)
	(In millions)
Non-Affiliated Generation Sales:
Retail	$	359	$	267	$	92
Wholesale		276		375		(99	)
Total Non-Affiliated Generation Sales		635		642		(7	)
Affiliated Generation Sales		1,404		1,235		169
Transmission		45		64		(19	)
Other		3		10		(7	)
Total Revenues	$	2,087	$	1,951	$	136

2

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated sales in the second quarter of 2007 compared to the second quarter of 2006:

	Increase
Source of Change in Non-Affiliated Generation Sales	(Decrease)
	(In millions)
Retail:
Effect of 20% increase in KWH sales	$	27
Change in prices		22
		49
Wholesale:
Effect of 28% decrease in sales volume		(56	)
Change in prices		28
		(28	)
Net Increase in Non-Affiliated Generation Sales	$	21

	Increase
Source of Change in Affiliated Generation Sales	(Decrease)
	(In millions)
Ohio Companies:
Effect of 4% increase in sales volume	$	21
Change in prices		23
		44
Pennsylvania Companies:
Effect of 18% increase in sales volume		25
Change in prices		(1	)
		24
Net Increase in Affiliated Generation Sales	$	68

The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated sales in the first six months of 2007 compared to the same period last year:

	Increase
Source of Change in Non-Affiliated Generation Sales	(Decrease)
	(In millions)
Retail:
Effect of 19% increase in KWH sales	$	51
Change in prices		41
		92
Wholesale:
Effect of 31% decrease in sales volume		(118	)
Change in prices		19
		(99	)
Net Decrease in Non-Affiliated Generation Sales	$	(7	)

Source of Change in Affiliated Generation Sales	Increase
	(In millions)
Ohio Companies:
Effect of 5% increase in sales volume	$	43
Change in prices		77
		120
Pennsylvania Companies:
Effect of 14% increase in sales volume		40
Change in prices		9
		49
Net Increase in Affiliated Generation Sales	$	169

3

Expenses

Total expenses increased by $3 million in the second quarter of 2007 and decreased by $34 million in the first six months of 2007 as compared to the same periods of 2006.

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the second quarter and first six months of 2007 from the same periods last year:

Source of Change in Fuel and Purchased Power	Three Months			Six  Months
Increase (Decrease)	(In millions)
Nuclear Fuel:
Change due to increased unit costs	$	2		$	3
Change due to volume consumed		-			6
		2			9
Fossil Fuel:
Change due to increased (decreased) unit costs		(13	)		5
Change due to volume consumed		4			(41	)
		(9	)		(36	)
Purchased Power:
Change due to increased unit costs		17			18
Change due to volume purchased		21			41
		38			59
Net Increase in Fuel and Purchased Power Costs	$	31		$	32

Fossil fuel costs decreased $9 million in the second quarter and $36 million in the first six months as a result of reduced coal and emission allowance costs. Reduced coal costs reflect a $14 million coal inventory adjustment recorded in the second quarter of 2007 as a result of an interim physical inventory and decreased generation output in the first quarter of 2007 as a result of the planned maintenance outages at Sammis Units 6 and 7 and Eastlake Unit 5 and forced outages at Mansfield Units 1 and 2. The lower volume consumed in the first six months of 2007 was partially offset by the effect of higher coal prices.

The lower fossil fuel costs were partially offset by higher nuclear fuel costs of $2 million in the second quarter of 2007 and $9 million in the first six months of 2007. Higher nuclear fuel costs were due to higher unit costs for the second quarter and first six months of 2007 and increased nuclear generation in the six-month period of 2007 as compared to the same period of 2006.

Purchased power costs increased as a result of increased purchases and higher unit prices. Volumes purchased in the second quarter and first six months of 2007 increased by 10.9% and 9.6%, respectively, compared to the same periods of 2006, reflecting the effect of the outages at the Sammis, Eastlake, Mansfield and Perry plants.

Other operating expenses decreased by $34 million in the second quarter of 2007 from the same period of 2006 as a result of lower fossil operating costs due to the absence of air quality project removal costs recognized in 2006, lower employee benefit costs and the absence of expenses associated with FES exiting its wholesale gas business in 2006. Other operating expenses decreased by $79 million in the first six months of 2007 from the same period of 2006 primarily due to lower nuclear operating costs as a result of fewer outages and reduced employee benefit costs. MISO and PJM transmission expenses were lower in both periods of 2007 as a result of reduced transmission charges related to the dispatch of generation in MISO, partially offset by higher point-to-point transmission and congestion charges.

Depreciation expense increased by $3 million in the second quarter of 2007 and $8 million in the first six months of 2007 from the same periods of 2006 primarily due to fossil and nuclear property additions subsequent to the second quarter of 2006.

General taxes increased by $3 million in the second quarter of 2007 and $5 million in the first six months of 2007 compared to the same periods of 2006 as a result of higher property taxes.

Other Expense

Other expense decreased by $10 million in the second quarter of 2007 and $19 million in the first six months of 2007 from the same periods of 2006 as a result of higher miscellaneous income and lower interest expense. Other miscellaneous income increased in both periods primarily due to interest income earned on investments in FirstEnergy’s unregulated money pool. Lower interest expense was due to the repayment of GAT-related notes to associated companies, partially offset by assuming additional lower-cost pollution control debt subsequent to July 1, 2006.

4

Capital Resources and Liquidity

FES’ cash requirements in 2007 for operating expenses, construction expenditures and debt redemptions are expected to be met with a combination of cash from operations, an equity contribution from FirstEnergy and funds from the capital markets. FES’ $700 million equity contribution from FirstEnergy in February 2007 is further discussed under Cash Flows From Financing Activities below. Borrowing capacity under the unregulated money pool and bank credit facilities are expected to be available to manage working capital requirements. In subsequent years, FES expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

On July 13, 2007, FGCO completed the sale and leaseback of its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases.  The notes and certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. The transaction will be classified as a financing under GAAP by FES until FGCO’s and FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction are satisfied, at which time it is expected to be classified as an operating lease under GAAP. FGCO continues to operate the plant and is entitled to 779 MW of the unit’s net demonstrated capacity. CEI has an existing sale and leaseback arrangement for the remaining 51 MW portion of Bruce Mansfield Unit 1. Net after-tax proceeds of approximately $1.2 billion to FGCO from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy unregulated money pool. FGCO’s basic rent expense is expected to be approximately $44 million for 2007 and $81 million on an average annual basis for subsequent years during the lease term. There will be no material gain from this transaction reflected in earnings during the third quarter of 2007.

As of June 30, 2007, FES’ cash and cash equivalents of $2,000 remained unchanged from December 31, 2006.

Cash Flows From Operating Activities

Net cash provided from operating activities in the first six months of 2007 and 2006 is summarized as follows:

	Six Months Ended June 30,
Operating Cash Flows	2007			2006
	(In millions)
Net income	$	254		$	136
Non-cash charges		193			176
Pension trust contribution		(64	)		-
Working capital and other		(193	)		(152	)
Net cash provided from operating activities	$	190		$	160

Net cash provided from operating activities increased by $30 million in the first six months of 2007 compared to the same period of 2006 primarily due to a $118 million increase in net income (see Results of Operations) and a $17 million increase in non-cash charges, partially offset by a $41 million decrease from working capital and other and a $64 million pension trust contribution in the first quarter of 2007. The decrease from working capital and other changes primarily reflects an $82 million increase in receivables due to higher sales, partially offset by $35 million of decreased payments to suppliers.

Cash Flows From Financing Activities

Cash provided from financing activities was $282 million and $371 million in the first six months of 2007 and 2006, respectively. The decrease was primarily due to the pay-down of intercompany GAT-related promissory notes, partially offset by FirstEnergy's equity contribution and short-term borrowings, summarized as follows:

5

	Six Months Ended        June 30,
Securities Issued or Redeemed	2007		2006
	(In millions)
New Financing:
Pollution control notes	$	-	$	252
Equity contribution from parent		700		-
Redemptions:
Long-term associated company notes payable	$	746	$	-
Short-term borrowings, net	$	365	$	119

FES had approximately $1.4 billion of short-term indebtedness as of June 30, 2007 compared to approximately $1.0 billion as of December 31, 2006.

FirstEnergy and certain of its subsidiaries are parties to a $2.75 billion five-year revolving credit facility. FirstEnergy may request an increase in the total commitments available under this facility up to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2011, unless the lenders agree, at the request of the borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations. FES is currently able to borrow $250 million under the facility.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of June 30, 2007, FES’ debt to total capitalization ratio as defined under the revolving credit facility of 57% allows for additional debt capacity of approximately $1.5 billion.

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

FES has the ability to borrow from FirstEnergy to meet its short-term working capital requirements. FESC administers a money pool and tracks surplus funds of FirstEnergy and its unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2007 was 5.64%.

On February 21, 2007, FirstEnergy made a $700 million equity investment in FES, all of which was subsequently contributed to FGCO and used to pay-down portions of the GAT-related promissory notes owed to the Ohio Companies and Penn.

As described above, on July 13, 2007, FGCO completed the sale and leaseback of a 93.825% undivided interest in Unit 1 of the Bruce Mansfield Generating Plant. Net after-tax proceeds of approximately $1.2 billion to FGCO from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy unregulated money pool. The repayments and investment allowed FES to reduce its investment in that money pool in order to repay approximately $250 million of external bank borrowings and fund a $600 million equity repurchase from FirstEnergy.

Cash Flows From Investing Activities

Net cash used for investing activities in the first six months of 2007 decreased by $59 million compared to the same period of 2006. The decrease was principally due to a decrease in property additions, reflecting completion of the steam generator and reactor head replacement projects at Beaver Valley Unit 1 in 2006.

During the second half of 2007, capital requirements for property additions (excluding nuclear fuel) are expected to be approximately $350 million. These cash requirements are expected to be satisfied from a combination of internal cash and short-term credit arrangements.

6

FES’ capital spending for the period 2007-2011 is expected to be about $2.9 billion (excluding nuclear fuel), of which $591 million applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $1.2 billion, of which about $95 million applies to 2007. During the same period, FES’ nuclear fuel investments are expected to be reduced by approximately $804 million and $102 million, respectively, as the nuclear fuel is consumed.

Guarantees and Other Assurances

On March 26, 2007, S&P assigned FES a corporate credit rating of BBB. On March 27, 2007, Moody’s assigned FES an issuer rating of Baa2.  In support of these credit ratings, on March 26, 2007, FES entered into guarantees in favor of present and future holders of FGCO and NGC indebtedness. FGCO and NGC also entered into guarantees in favor of present and future holders of FES’ indebtedness. Accordingly, guaranteed parties will have claims against FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC. In addition, under provisions included in applicable FGCO and NGC 2005 and 2006 debt transactions, FES may elect to replace FirstEnergy as guarantor so long as FES maintains senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s.

As described above, on July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases.  The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.

Market Risk Information

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

Commodity Price Risk

FES is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices primarily due to fluctuations in electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, FES uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FES’ derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the table below. The change in the fair value of commodity derivative contracts related to energy production during the three months and six months ended June 30, 2007 is summarized in the following table:

	Three Months Ended									Six Months Ended
Increase (Decrease) in the Fair Value	June 30, 2007									June 30, 2007
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	$	(2	)	$	1		$	(1	)	$	(3	)	$	(17	)	$	(20	)
Additions/change in value of existing contracts		(3	)		(11	)		(14	)		(3	)		(6	)		(9	)
Settled contracts		1			(2	)		(1	)		2			11			13
Outstanding net liability at end of period	$	(4	)	$	(12	)	$	(16	)	$	(4	)	$	(12	)	$	(16	)
Impact of Changes in Commodity Derivative Contracts(*)
Income Statement effects (pre-tax)	$	(2	)	$	-		$	(2	)	$	(1	)	$	-		$	(1	)
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	(13	)	$	(13	)	$	-		$	5		$	5

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

7

Derivatives are included on the Consolidated Balance Sheet as of June 30, 2007 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current-
Other assets	$	-		$	35		$	35
Other liabilities		(4	)		(50	)		(54	)
Non-Current-
Other deferred charges		-			18			18
Other noncurrent liabilities		-			(15	)		(15	)
Net liabilities	$	(4	)	$	(12	)	$	(16	)

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FES relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FES uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. FES used other external sources for the valuation of commodity derivative contracts as of June 30, 2007.

FES performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on FES’ consolidated financial position (assets, liabilities and equity) or cash flows as of June 30, 2007. Based on derivative contracts held as of June 30, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $9 million for the next 12 months.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $915 million as of June 30, 2007. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $92 million reduction in fair value as of June 30, 2007.

Credit Risk

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

FES maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of FES’ credit program, FES aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of June 30, 2007, the largest credit concentration with one non-affiliated party (currently rated investment grade) represented 9.8% of its total credit risk. As of June 30, 2007, 99.3% of FES’ credit exposure, net of collateral and reserves, was with non-affiliated, investment-grade counterparties.

Power Supply Agreements with Regulated Affiliates

FES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO authorized billing rates.

FES has been supplying Met-Ed and Penelec with a portion of their PLR requirements through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained 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. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.

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On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.

Based on the outcome of the 2006 comprehensive transition rate filing, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.

As a result of Penn’s PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches is supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. This filing was accepted by the FERC on November 15, 2006, and no request for rehearing was filed.

FERC Matters

On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.

FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities.  FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM.  If approved by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities.  In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be maintained (known as the RECB Process).  Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.

The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint.  Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process.  If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.

AEP filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs.  AEP stated that it will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint.  Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM.  If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.

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Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC.  All or some of these proceedings may be consolidated by the FERC and set for hearing.  The outcome of these cases cannot be predicted.  Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates.  FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates.  Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.

Environmental Matters

FES 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 FES’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

FES 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. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FES has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4. TE, an affiliated company, owned the Bay Shore Power Plant at the time of the alleged violation. FES owns and operates the plant.

FES complies with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants and/or using emission allowances. 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 FES' 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. FES believes its facilities are also complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including SCR and SNCR systems, and/or using emission allowances.

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On July 25, 2007, FirstEnergy and PennFuture entered into a Tolling and Confidentiality Agreement that provides for a 60-day negotiation period during which the parties have agreed to not file a lawsuit.

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 allowed 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). FES’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO₂ and 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 FES operates affected facilities.

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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. FES’ future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES 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. FES would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FES will be disadvantaged if these model rules were implemented as proposed because FES’ substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FES system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Mansfield Plant, FES’ only coal-fired Pennsylvania power plant, until 2015, if at all.

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, and is now owned by FGCO. 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 the NSR cases and the case involving the Sammis Plant is referred to as the Sammis NSR Litigation.

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 Sammis NSR Litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield 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, FGCO and its affiliates, OE and Penn, could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires FGCO and its affiliates, OE and Penn, to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. On May 8, 2007, the EPA proposed to change the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. 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.

At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO₂ emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities.

FES cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂ emissions could require significant capital and other expenditures. The CO₂ emissions per KWH of electricity generated by FES is lower than many regional competitors due to its diversified generation sources, which include low or non- CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FES is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, 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.

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Under NRC regulations, FES and its affiliates, OE and TE, must ensure that adequate funds will be available to decommission their nuclear facilities in proportion to their respective ownership or leased interest in the nuclear units. As of June 30, 2007, NGC had approximately $1.3 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010; $63 million of which has been recognized as a note receivable from Penn on FES’ Consolidated Balance Sheet. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

Other Legal Proceedings

Nuclear Plant Matters

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. 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 would continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the NRC 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. By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).

On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance arbitration.  In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse.   Citing the findings in the expert witness' report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) the NRC conduct an independent review of the consultant's report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.

In a letter dated May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in significant corrosion.” The NRC also indicated that “no immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to shut down the facility). On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests, and provided an opportunity for UCS to provide additional information prior to the final determination. By letter dated July 12, 2007, the NRC denied the remainder of the UCS petition.

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC following FENOC’s reply to an April 2, 2007 NRC request for information about the expert witnesses’ report and another report. The NRC indicated that this information is needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, FENOC received a Confirmatory Order issued by the NRC confirming its commitment to implement certain corrective actions designed to ensure that issues similar to those that gave rise to the May 14, 2007 Demand for Information do not recur. FES can provide no assurances as to the ultimate resolution of this matter.

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Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FES’ normal business operations pending against FES and its subsidiaries, the most significant of which are described above.

If it were ultimately determined that FES 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 FES’ or its subsidiaries' financial condition, results of operations and cash flows.

New Accounting Standards and Interpretations

SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB

Statement No. 115”

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. The Statement also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FES is currently evaluating the impact of this Statement 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. FES is currently evaluating the impact of this Statement on its financial statements.

EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to APIC. This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007. EITF 06-11 is not expected to have a material effect on FES’ financial statements.

FSP FIN 39-1 “Amendment of FASB Interpretation No. 39”

In April 2007, the FASB issued FPS FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1) which amends FIN 39 “Offsetting of Amounts Related to Certain Contracts” to allow companies with master netting agreements to offset fair value amounts recognized for the right to reclaim or return cash collateral against the fair value amounts recognized for derivative instruments held with the same counterparty.  FES is currently assessing the impact of netting under FSP FIN 39-1, which is effective for periods beginning after November 15, 2007. If elected, the impact would not be material to FES’ financial statements.

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(In thousands)
REVENUES:
Electric sales to affiliates	$	690,697		$	623,425		$	1,404,371		$	1,234,990
Other		378,034			370,606			682,653			715,552
Total revenues		1,068,731			994,031			2,087,024			1,950,542
EXPENSES:
Fuel		268,880			275,979			502,415			529,392
Purchased power from non-affiliates		162,873			125,382			349,076			303,629
Purchased power from affiliates		70,585			69,576			147,068			133,051
Other operating expenses		233,145			267,051			496,741			576,051
Provision for depreciation		48,520			45,898			96,530			88,520
General taxes		20,910			17,894			42,628			37,941
Total expenses		804,913			801,780			1,634,458			1,668,584
OPERATING INCOME		263,818			192,251			452,566			281,958
OTHER INCOME (EXPENSE):
Miscellaneous income		15,369			9,819			35,101			17,181
Interest expense - affiliates		(22,817	)		(40,473	)		(52,263	)		(81,248	)
Interest expense - other		(21,693	)		(6,418	)		(39,051	)		(9,966	)
Capitalized interest		4,423			2,476			7,632			6,309
Total other expense		(24,718	)		(34,596	)		(48,581	)		(67,724	)
INCOME BEFORE INCOME TAXES		239,100			157,655			403,985			214,234
INCOME TAXES		87,684			59,019			150,065			78,397
NET INCOME		151,416			98,636			253,920			135,837
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		(1,360	)		-			(2,720	)		-
Unrealized gain (loss) on derivative hedges		(13,170	)		1,677			4,588			(119	)
Change in unrealized gain on available for sale securities		41,340			(19,896	)		58,790			8,321
Other comprehensive income (loss)		26,810			(18,219	)		60,658			8,202
Income tax expense (benefit) related to other
comprehensive income		9,226			(6,773	)		21,559			3,095
Other comprehensive income (loss), net of tax		17,584			(11,446	)		39,099			5,107
TOTAL COMPREHENSIVE INCOME	$	169,000		$	87,190		$	293,019		$	140,944
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,		December 31,
	2007		2006
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers (less accumulated provisions of $8,682,000 and $7,938,000,
respectively, for uncollectible accounts)		152,397		129,843
Associated companies		289,102		235,532
Other (less accumulated provisions of $9,000 and $5,593,000,
respectively, for uncollectible accounts)		6,551		4,085
Notes receivable from associated companies		937,095		752,919
Materials and supplies, at average cost		474,697		460,239
Prepayments and other		82,440		57,546
		1,942,284		1,640,166
PROPERTY, PLANT AND EQUIPMENT:
In service		8,545,851		8,355,344
Less - Accumulated provision for depreciation		3,972,113		3,818,268
		4,573,738		4,537,076
Construction work in progress		464,404		339,886
		5,038,142		4,876,962
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		1,314,508		1,238,272
Long-term notes receivable from associated companies		62,900		62,900
Other		40,385		72,509
		1,417,793		1,373,681
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		24,248		24,248
Property taxes		44,111		44,111
Pension assets		9,703		-
Other		45,981		39,839
		124,043		108,198
	$	8,522,262	$	7,999,007
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,469,721	$	1,469,660
Short-term borrowings-
Associated companies		887,044		1,022,197
Other		500,000		-
Accounts payable-
Associated companies		389,474		556,049
Other		179,200		136,631
Accrued taxes		117,804		113,231
Other		118,850		100,941
		3,662,093		3,398,709
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares-
8 shares outstanding		1,751,870		1,050,302
Accumulated other comprehensive income		150,822		111,723
Retained earnings		913,648		697,338
Total common stockholder's equity		2,816,340		1,859,363
Long-term debt		869,607		1,614,222
		3,685,947		3,473,585
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		178,813		121,449
Accumulated deferred investment tax credits		63,434		65,751
Asset retirement obligation		784,495		760,228
Retirement benefits		52,476		103,027
Property taxes		44,433		44,433
Other		50,571		31,825
		1,174,222		1,126,713
COMMITMENTS AND CONTINGENCIES (Note 7)
	$	8,522,262	$	7,999,007
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2007			2006
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	253,920		$	135,837
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		96,530			88,520
Nuclear lease amortization		49,406			41,111
Deferred income taxes and investment tax credits, net		48,026			1,779
Investment impairment		10,856			-
Accrued compensation and retirement benefits		(2,597	)		4,437
Commodity derivative transactions, net		2,727			43,846
Gain on asset sales		(12,105	)		(3,765	)
Cash collateral, net		(3,120	)		43,795
Pension trust contribution		(64,020	)		-
Decrease (increase) in operating assets:
Receivables		(42,901	)		39,472
Materials and supplies		14,492			(39,606	)
Prepayments and other current assets		(8,270	)		(3,730	)
Increase (decrease) in operating liabilities:
Accounts payable		(148,755	)		(184,158	)
Accrued taxes		4,452			14,306
Accrued interest		387			885
Other		(9,185	)		(22,541	)
Net cash provided from operating activities		189,843			160,188
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			251,978
Equity contribution from parent		700,000			-
Short-term borrowings, net		364,847			119,484
Redemptions and Repayments-
Long-term debt		(745,536	)		-
Common stock dividend payments		(37,000	)		-
Net cash provided from financing activities		282,311			371,462
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(302,424	)		(327,496	)
Proceeds from asset sales		12,120			3,765
Sales of investment securities held in trusts		367,924			593,732
Purchases of investment securities held in trusts		(367,924	)		(593,732	)
Loans to associated companies, net		(184,176	)		(184,971	)
Other		2,326			(22,948	)
Net cash used for investing activities		(472,154	)		(531,650	)
Net change in cash and cash equivalents		-			-
Cash and cash equivalents at beginning of period		2			2
Cash and cash equivalents at end of period	$	2		$	2
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.  ORGANIZATION AND BASIS OF PRESENTATION

The consolidated financial statements include FES and its wholly owned subsidiaries, FGCO and NGC. FES is a wholly owned subsidiary of FirstEnergy. FirstEnergy also holds directly, or indirectly, all of the issued and outstanding common shares of its eight principal electric utility operating subsidiaries: OE, Penn, CEI, TE, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE.

On December 28, 2006, the NRC approved the transfer of ownership in NGC from FirstEnergy to FES. Effective December 31, 2006, NGC is a wholly owned subsidiary of FES and a second tier subsidiary of FirstEnergy. FENOC continues to operate and maintain the nuclear generation assets. FES’ results in 2006 reflect all of the GAT changes and therefore, no allocations or adjustments, except for those related to the NGC corporate restructuring were reflected in the 2006 financial statements.

FES follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC and the FERC. 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 FES’ 2006 Annual Report, which was furnished on FirstEnergy’s Form 8-K dated April, 20, 2007. The consolidated unaudited financial statements of FES reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods.

FES operates in one business segment that provides energy-related products and services to wholesale and retail customers in Ohio, Pennsylvania, Michigan and Maryland. The segment also generates and sells power to meet all or a portion of the PLR requirements for FirstEnergy’s Ohio and Pennsylvania utility subsidiaries.

Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

2.  DERIVATIVE INSTRUMENTS

FES 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, FES uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.

FES accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet those criteria are accounted for on the accrual basis. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are recorded as other expense, as AOCI, 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.

The net deferred losses of $7 million included in AOCI as of June 30, 2007, for derivative hedging activity, as compared to the December 31, 2006 balance of $10 million for net deferred losses, resulted from a net $3 million increase related to current hedging activity and a $6 million decrease due to net hedge losses reclassified into earnings during the six months ended June 30, 2007. Based on current estimates, approximately $9 million (after tax) of the net deferred gains on derivative instruments in AOCI as of June 30, 2007 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.

3.  ASSET RETIREMENT OBLIGATIONS

FES 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, FES has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47.

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The ARO liability of $784 million as of June 30, 2007 primarily related to the nuclear decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities. FES utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

FES maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of June 30, 2007, the fair value of the decommissioning trust assets was approximately $1.3 billion.

The following tables analyze changes to the ARO balance during the first six months of 2007 and 2006, respectively.

ARO Reconciliation	2007			2006
	(In millions)
Balance, January 1	$	760		$	716
Accretion		25			24
Revisions in estimated cash flows		(1	)		3
Balance, June 30	$	784		$	743

4.  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’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31, 2006. On January 2, 2007, FirstEnergy made a $300 million (FES’ share was $64 million) voluntary cash contribution to its qualified pension plan. Projections indicate that additional cash contributions are not expected to be required before 2016. 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. During 2006, FirstEnergy amended the health care plan effective in 2008 to cap the monthly contribution for many of the retirees and their spouses receiving subsidized health care coverage. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

The components of FirstEnergy's net periodic pension and other postretirement benefit costs (including amounts capitalized) for the three months and six months ended June 30, 2007 and 2006 consisted of the following:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Pension Benefits	2007			2006			2007			2006
	(In millions)
Service cost	$	21		$	21		$	42		$	41
Interest cost		71			66			142			133
Expected return on plan assets		(113	)		(99	)		(225	)		(198	)
Amortization of prior service cost		3			2			5			5
Recognized net actuarial loss		11			15			21			29
Net periodic cost (credit)	$	(7	)	$	5		$	(15	)	$	10
FES’ share of net periodic cost (credit)	$	2		$	4		$	3		$	8

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Other Postretirement Benefits	2007			2006			2007			2006
	(In millions)
Service cost	$	5		$	9		$	10		$	17
Interest cost		17			26			34			52
Expected return on plan assets		(12	)		(12	)		(25	)		(23	)
Amortization of prior service cost		(37	)		(19	)		(74	)		(37	)
Recognized net actuarial loss		11			14			23			27
Net periodic cost (credit)	$	(16	)	$	18		$	(32	)	$	36
FES’ share of net periodic cost (credit)	$	(2	)	$	1		$	(3	)	$	3

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5.  INCOME TAXES

FES is included in FirstEnergy’s consolidated federal income tax return. The consolidated tax liability is calculated on a “stand-alone” company basis, with FES recognizing any tax losses or credits it contributes to the consolidated return. On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 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 is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.

As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits calculated for FES was $14 million. FES recorded a $0.6 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $6 million would favorably affect FES’ effective tax rate upon recognition. During the first six months of 2007, there were no material changes to FES’ unrecognized tax benefits. As of June 30, 2007, the entire liability for uncertain tax positions is included in other non-current liabilities and changes to FES’ tax contingencies that are reasonably possible in the next 12 months are not material.

FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FES includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. As of January 1, 2007, FES’ net amount of interest accrued was $2.7 million. During the first six months of 2007, there were no material changes to the amount of interest accrued.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2006. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audit for years 2004 and 2005 began in June 2006 and is not expected to close before December 2007. The IRS began auditing the year 2006 in April 2006 under its Compliance Assurance Process experimental program, and is not expected to close before December 2007. Management believes that adequate reserves have been recognized, and final settlement of these audits is not expected to have a material adverse effect on FES’ financial condition or results of operations.

6.  POWER SUPPLY AGREEMENTS WITH REGULATED AFFILIATES

FES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO authorized billing rates.

FES has been supplying Met-Ed and Penelec with a portion of their PLR requirements through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained 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. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy costs during the term of these agreements with FES.

On April 7, 2006, the parties entered into a tolling agreement that arose from FES’ notice to Met-Ed and Penelec that FES elected to exercise its right to terminate the partial requirements agreement effective midnight December 31, 2006. On November 29, 2006, Met-Ed, Penelec and FES agreed to suspend the April 7 tolling agreement pending resolution of the PPUC’s proceedings regarding the Met-Ed and Penelec comprehensive transition rate cases filed April 10, 2006. Separately, on September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that substantially exceed the fixed price in the partial requirements agreements.

20

Based on the outcome of the 2006 comprehensive transition rate filing, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the tolling, suspension and supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.

As a result of Penn’s PLR competitive solicitation process approved by the PPUC for the period January 1, 2007 through May 31, 2008, FES was selected as the winning bidder for a number of the tranches for individual customer classes. The balance of the tranches is supplied by unaffiliated power suppliers. On October 2, 2006, FES filed an application with the FERC under Section 205 of the Federal Power Act for authorization to make these affiliate sales to Penn. This filing was accepted by the FERC on November 15, 2006, and no request for rehearing was filed.

7.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)  GUARANTEES AND OTHER ASSURANCES

On March 26, 2007, S&P assigned FES a corporate credit rating of BBB. On March 27, 2007, Moody’s assigned FES an issuer rating of Baa2.  In support of these credit ratings, on March 26, 2007, FES entered into guarantees in favor of present and future holders of FGCO and NGC indebtedness. FGCO and NGC also entered into guarantees in favor of present and future holders of FES’ indebtedness. Accordingly, guaranteed parties will have claims against FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC. In addition, as previously disclosed, under provisions included in applicable FGCO and NGC 2005 and 2006 debt transactions, FES may elect to replace FirstEnergy as guarantor so long as FES maintains senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s.

On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1, representing 779 MW of net demonstrated capacity. The purchase price of approximately $1.329 billion for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases.  The notes and certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. The transaction will be classified as a financing under GAAP until FGCO’s and FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction are satisfied, at which time it is expected to be classified as an operating lease under GAAP. FGCO continues to operate the plant. Net after-tax proceeds of approximately $1.2 billion to FGCO from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy unregulated money pool. FGCO’s basic rent expense is expected to be approximately $44 million for 2007 and $81 million on an average annual basis for subsequent years during the lease term. There will be no material gain from this transaction reflected in earnings during the third quarter of 2007.

(B)  FERC MATTERS

On August 1, 2007, a number of filings were made with the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.

FirstEnergy joined in a filing made by the MISO transmission owners that would maintain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities.  FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM.  If approved by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities.  In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be maintained (known as the RECB Process).  Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.

21

The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint.  Further, Indianapolis Power and Light Company separately moved the FERC to reopen the cost allocation for the RECB Process.  If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV transmission facilities to the FirstEnergy footprint, and increase the transmission rates paid by load-serving FirstEnergy affiliates.

American Electric Power (AEP) filed a letter with the FERC Commissioners stating its intent to file a complaint under Section 206 of the Federal Power Act challenging the justness and reasonableness of the rate designs underlying the MISO and PJM transmission tariffs.  AEP stated that it will propose the adoption of a regional rate design that is expected to reallocate the cost of both existing and new high voltage transmission facilities across the combined MISO and PJM footprint.  Based upon the position advocated by AEP in a related proceeding, the AEP proposal is expected to result in a greater allocation of costs to FirstEnergy transmission zones in MISO and PJM.  If approved by the FERC, AEP’s proposal would increase the transmission rates paid by load-serving FirstEnergy affiliates.

Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC.  All or some of these proceedings may be consolidated by the FERC and set for hearing.  The outcome of these cases cannot be predicted.  Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates.  FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates.  Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.

(C)  ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy, FES and their respective subsidiaries with regard to air and water quality and other environmental matters. The effects of compliance on FES with regard to environmental matters could have a material adverse effect on its 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. FES estimates capital expenditures for environmental compliance of approximately $1.8 billion for 2007 through 2011.

FES 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 FES’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.

Clean Air Act Compliance

FES 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. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006 alleging violations to various sections of the Clean Air Act. FES has disputed those alleged violations based on its Clean Air Act permit, the Ohio SIP and other information provided at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4. TE, an affiliated company, owned the Bay Shore Power Plant at the time of the alleged violation. FES owns and operates the plant.

FES complies with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants and/or using emission allowances. 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 FES' 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. FES believes its facilities are also complying with the NO_X budgets established under SIPs through combustion controls and post-combustion controls, including SCR and SNCR systems, and/or using emission allowances.

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On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act, alleging violations of air pollution laws at the Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On July 25, 2007, FirstEnergy and PennFuture entered into a Tolling and Confidentiality Agreement that provides for a 60-day negotiation period during which the parties have agreed to not file a lawsuit.

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 allowed 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). FES’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to caps on SO₂ and 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 FES 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. FES’ future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FES 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. FES would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FES will be disadvantaged if these model rules were implemented as proposed because FES’ substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap and trade approach as in the CAMR, but rather follows a command and control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FES system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Mansfield Plant, FES’ only coal-fired Pennsylvania power plant, until 2015, if at all.

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, and is now owned by FGCO. 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 the NSR cases and the case involving the Sammis Plant is referred to as the Sammis NSR Litigation.

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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 Sammis NSR Litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NO_X and SO₂ emissions at the Sammis, Burger, Eastlake and Mansfield 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, FGCO and its affiliates, OE and Penn, could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreement are currently estimated to be $1.7 billion ($400 million of which is expected to be spent during 2007, with the largest portion of the remaining $1.3 billion expected to be spent in 2008 and 2009).

The Sammis NSR Litigation consent decree also requires FGCO and its affiliates, OE and Penn, to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.

On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. On May 8, 2007, the EPA proposed to change the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.

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. At the international level, efforts have begun to develop climate change agreements for post-2012 GHG reductions. 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.

At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO₂ emissions from automobiles as “air pollutants” under the Clean Air Act. Although this decision did not address CO₂ emissions from electric generating plants, the EPA has similar authority under the Clean Air Act to regulate “air pollutants” from those and other facilities.

FES cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂ emissions could require significant capital and other expenditures. The CO₂ emissions per KWH of electricity generated by FES is lower than many regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

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

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On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system, and entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. On January 26, 2007, the federal Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to EPA for further rulemaking and eliminated the restoration option from EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FES is evaluating various control options and their costs and effectiveness. Depending on the outcome of such studies, the EPA’s further rulemaking and any action taken by the states exercising BPJ, 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.

Under NRC regulations, FES and its affiliates, OE and TE, must ensure that adequate funds will be available to decommission their nuclear facilities in proportion to their respective ownership or leased interest in the nuclear units. As of June 30, 2007, NGC had approximately $1.3 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley and Perry. As part of the application to the NRC to transfer the ownership of these nuclear facilities to NGC, FirstEnergy agreed to contribute another $80 million to these trusts by 2010; $63 million of which has been recognized as a note receivable from Penn on FES’ Consolidated Balance Sheet. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans to seek for these facilities.

(D)  OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

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. 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 would continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the NRC 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. By two letters dated March 2, 2007, the NRC closed the CAL commitments for Perry, the two outstanding white findings and crosscutting issues. Moreover, the NRC removed Perry from the Multiple Degraded Cornerstone Column of the NRC Action Matrix and placed the plant in the Licensee Response Column (regular agency oversight).

On April 30, 2007, the UCS filed a petition with the NRC under Section 2.206 of the NRC’s regulations based on a report prepared at FENOC’s request by expert witnesses for an insurance arbitration.  In December 2006, the expert witnesses for FENOC completed a report that analyzed the crack growth rates in control rod drive mechanism penetrations and wastage of the former reactor pressure vessel head at Davis-Besse.   Citing the findings in the expert witness' report, the Section 2.206 petition requested that: (1) Davis-Besse be immediately shut down; (2) the NRC conduct an independent review of the consultant's report and that all pressurized water reactors be shut down until remedial actions can be implemented; and (3) Davis-Besse’s operating license be revoked.

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In a letter dated May 18, 2007, the NRC stated that the “current reactor pressure vessel (RPV) head inspection requirements are adequate to detect RPV degradation issues before they result in significant corrosion.” The NRC also indicated that “no immediate safety concern exists at Davis-Besse” and denied UCS’ first demand (to shut down the facility). On June 18, 2007, the NRC Petition Review Board indicated that the agency had initially denied petitioner’s other requests, and provided an opportunity for UCS to provide additional information prior to the final determination. By letter dated July 12, 2007, the NRC denied the remainder of the UCS petition.

On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC following FENOC’s reply to an April 2, 2007 NRC request for information about the expert witnesses’ report and another report. The NRC indicated that this information is needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC held a public meeting on June 27, 2007 with FENOC to discuss FENOC’s response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarify certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplemental response to the NRC on July 16, 2007. On August 15, 2007, FENOC received a Confirmatory Order issued by the NRC confirming its commitment to implement certain corrective actions designed to ensure that issues similar to those that gave rise to the May 14, 2007 Demand for Information do not recur. FES can provide no assurances as to the ultimate resolution of this matter.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FES’ normal business operations pending against FES and its subsidiaries, the most significant of which are described above.

If it were ultimately determined that FES 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 FES’ or its subsidiaries' financial condition, results of operations and cash flows.

8.  NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”

In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. The Statement also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157 and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FES is currently evaluating the impact of this Statement 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. FES is currently evaluating the impact of this Statement on its financial statements.

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EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”

In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to APIC. This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007. EITF 06-11 is not expected to have a material effect on FES’ financial statements.

FSP FIN 39-1 “Amendment of FASB Interpretation No. 39”

In April 2007, the FASB issued FPS FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1) which amends FIN 39 “Offsetting of Amounts Related to Certain Contracts” to allow companies with master netting agreements to offset fair value amounts recognized for the right to reclaim or return cash collateral against the fair value amounts recognized for derivative instruments held with the same counterparty.  FES is currently assessing the impact of netting under FSP FIN 39-1, which is effective for periods beginning after November 15, 2007. If elected, the impact would not be material to FES’ financial statements.

9.  SUPPLEMENTAL GUARANTOR INFORMATION

On July 13, 2007, FGCO, a wholly-owned subsidiary of FES, completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Plant Unit 1.  The purchase price of approximately $1.329 billion for the undivided interest was funded through a combination of equity investments in six lessor trusts and proceeds from the sale of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034.  A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates.  FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases that secure the secured notes.

The following supplemental consolidating financial statements present the condensed consolidating statements of income for the three months and six months ended June 30, 2007 and 2006, consolidating balance sheets as of June 30, 2007 and December 31, 2006 and condensed consolidating statements of cash flows for the six months ended June 30, 2007 and 2006 for FirstEnergy Solutions Corp. (Parent), FGCO and NGC (non-guarantor). Investments in subsidiaries are accounted for by FES using the equity method for purposes of this presentation.  Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings.  The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions.

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
For the Three Months Ended June 30, 2007	FirstEnergy Solutions Corp.			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,074,858		$	453,553		$	279,092		$	(738,772	)	$	1,068,731
EXPENSES:
Fuel		7,513			235,653			25,714			-			268,880
Purchased power from non-affiliates		162,873			-			-			-			162,873
Purchased power from affiliates		731,260			57,291			20,806			(738,772	)		70,585
Other operating expenses		30,519			65,694			136,932			-			233,145
Provision for depreciation		469			25,239			22,812			-			48,520
General taxes		5,601			9,051			6,258			-			20,910
Total expenses		938,235			392,928			212,522			(738,772	)		804,913
OPERATING INCOME		136,623			60,625			66,570			-			263,818
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		74,781			(623	)		4,215			(63,004	)		15,369
Interest expense - affiliates		-			(17,990	)		(4,827	)		-			(22,817	)
Interest expense - other		(5,774	)		(6,115	)		(9,804	)		-			(21,693	)
Capitalized interest		6			3,056			1,361			-			4,423
Total other income (expense)		69,013			(21,672	)		(9,055	)		(63,004	)		(24,718	)
INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES		205,636			38,953			57,515			(63,004	)		239,100
INCOME TAXES		54,220			12,892			20,572			-			87,684
NET INCOME	$	151,416		$	26,061		$	36,943		$	(63,004	)	$	151,416

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
For the Three Months Ended June 30, 2006	FirstEnergy Solutions Corp.			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	993,638		$	470,227		$	297,617		$	(767,451	)	$	994,031
EXPENSES:
Fuel		1,683			250,410			23,886			-			275,979
Purchased power from non-affiliates		125,382			-			-			-			125,382
Purchased power from affiliates		771,327			50,305			15,395			(767,451	)		69,576
Other operating expenses		55,637			74,344			137,070			-			267,051
Provision for depreciation		453			24,251			21,194			-			45,898
General taxes		3,000			9,374			5,520			-			17,894
Total expenses		957,482			408,684			203,065			(767,451	)		801,780
OPERATING INCOME		36,156			61,543			94,552			-			192,251
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		78,310			198			3,397			(72,086	)		9,819
Interest expense - affiliates		(241	)		(28,788	)		(11,444	)		-			(40,473	)
Interest expense - other		(162	)		(2,248	)		(4,008	)		-			(6,418	)
Capitalized interest		4			1,023			1,449			-			2,476
Total other income (expense)		77,911			(29,815	)		(10,606	)		(72,086	)		(34,596	)
INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES		114,067			31,728			83,946			(72,086	)		157,655
INCOME TAXES		15,431			11,381			32,207			-			59,019
NET INCOME	$	98,636		$	20,347		$	51,739		$	(72,086	)	$	98,636

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
For the Six Months Ended June 30, 2007	FirstEnergy Solutions Corp.			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	2,094,245		$	1,004,908		$	513,183		$	(1,525,312	)	$	2,087,024
EXPENSES:
Fuel		9,880			436,884			55,651			-			502,415
Purchased power from non-affiliates		349,076			-			-			-			349,076
Purchased power from affiliates		1,515,432			118,727			38,221			(1,525,312	)		147,068
Other operating expenses		81,768			164,789			250,184			-			496,741
Provision for depreciation		922			50,175			45,433			-			96,530
General taxes		10,536			19,618			12,474			-			42,628
Total expenses		1,967,614			790,193			401,963			(1,525,312	)		1,634,458
OPERATING INCOME		126,631			214,715			111,220			-			452,566
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		188,729			294			9,415			(163,337	)		35,101
Interest expense - affiliates		-			(42,321	)		(9,942	)		-			(52,263	)
Interest expense - other		(7,158	)		(12,876	)		(19,017	)		-			(39,051	)
Capitalized interest		11			5,155			2,466			-			7,632
Total other income (expense)		181,582			(49,748	)		(17,078	)		(163,337	)		(48,581	)
INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES		308,213			164,967			94,142			(163,337	)		403,985
INCOME TAXES		54,293			62,181			33,591			-			150,065
NET INCOME	$	253,920		$	102,786		$	60,551		$	(163,337	)	$	253,920

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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
For the Six Months Ended June 30, 2006	FirstEnergy Solutions Corp.			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
REVENUES	$	1,951,126		$	869,448		$	551,928		$	(1,421,960	)	$	1,950,542
EXPENSES:
Fuel		4,018			478,831			46,543			-			529,392
Purchased power from non-affiliates		303,629			-			-			-			303,629
Purchased power from affiliates		1,432,211			89,912			32,888			(1,421,960	)		133,051
Other operating expenses		106,927			155,554			313,570			-			576,051
Provision for depreciation		858			48,122			39,540			-			88,520
General taxes		6,045			20,605			11,291			-			37,941
Total expenses		1,853,688			793,024			443,832			(1,421,960	)		1,668,584
OPERATING INCOME		97,438			76,424			108,096			-			281,958
OTHER INCOME (EXPENSE):
Miscellaneous income (expense), including
net income from equity investees		77,273			(4,746	)		17,429			(72,775	)		17,181
Interest expense - affiliates		(241	)		(57,330	)		(23,677	)		-			(81,248	)
Interest expense - other		(357	)		(2,901	)		(6,708	)		-			(9,966	)
Capitalized interest		(8	)		2,073			4,244			-			6,309
Total other income (expense)		76,667			(62,904	)		(8,712	)		(72,775	)		(67,724	)
INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES		174,105			13,520			99,384			(72,775	)		214,234
INCOME TAXES		38,268			3,162			36,967			-			78,397
NET INCOME	$	135,837		$	10,358		$	62,417		$	(72,775	)	$	135,837

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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
	FirstEnergy
As of June 30, 2007	Solutions Corp.		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		152,397		-		-		-			152,397
Associated companies		252,826		174,978		90,669		(229,371	)		289,102
Other		5,588		963		-		-			6,551
Notes receivable from associated companies		836,467		-		100,628		-			937,095
Materials and supplies, at average cost		195		257,477		217,025		-			474,697
Prepayments and other		65,097		15,589		1,754		-			82,440
		1,312,572		449,007		410,076		(229,371	)		1,942,284
PROPERTY, PLANT AND EQUIPMENT:
In service		16,439		5,025,269		3,504,143		-			8,545,851
Less - Accumulated provision for depreciation		6,677		2,526,647		1,438,789		-			3,972,113
		9,762		2,498,622		2,065,354		-			4,573,738
Construction work in progress		9,632		307,363		147,409		-			464,404
		19,394		2,805,985		2,212,763		-			5,038,142
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,314,508		-			1,314,508
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		2,371,347		-		-		(2,371,347	)		-
Other		5,736		34,447		202		-			40,385
		2,377,083		34,447		1,377,610		(2,371,347	)		1,417,793
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		24,248		-		-		-			24,248
Property taxes		-		20,946		23,165		-			44,111
Pension assets		1,171		8,532		-		-			9,703
Accumulated deferred income taxes		32,588		-		-		(32,588	)		-
Other		30,454		10,449		5,078		-			45,981
		88,461		39,927		28,243		(32,588	)		124,043
	$	3,797,510	$	3,329,366	$	4,028,692	$	(2,633,306	)	$	8,522,262
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	608,456	$	861,265	$	-		$	1,469,721
Notes payable-
Associated companies		-		887,044		-		-			887,044
Other		500,000		-		-		-			500,000
Accounts payable-
Associated companies		233,866		157,115		227,864		(229,371	)		389,474
Other		71,128		108,072		-		-			179,200
Accrued taxes		72,826		21,523		23,455		-			117,804
Other		65,383		41,939		11,528		-			118,850
		943,203		1,824,149		1,124,112		(229,371	)		3,662,093
CAPITALIZATION:
Common stockholder's equity		2,816,340		880,551		1,490,796		(2,371,347	)		2,816,340
Long-term debt		-		440,900		428,707		-			869,607
		2,816,340		1,321,451		1,919,503		(2,371,347	)		3,685,947
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		-		35,903		175,498		(32,588	)		178,813
Accumulated deferred investment tax credits		-		37,474		25,960		-			63,434
Asset retirement obligations		-		24,041		760,454		-			784,495
Retirement benefits		7,693		44,783		-		-			52,476
Property taxes		-		21,268		23,165		-			44,433
Other		30,274		20,297		-		-			50,571
		37,967		183,766		985,077		(32,588	)		1,174,222
	$	3,797,510	$	3,329,366	$	4,028,692	$	(2,633,306	)	$	8,522,262

32

FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
	FirstEnergy
As of December 31, 2006	Solutions Corp.		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	-	$	-	$	-		$	2
Receivables-
Customers		129,843		-		-		-			129,843
Associated companies		201,281		160,965		69,751		(196,465	)		235,532
Other		2,383		1,702		-		-			4,085
Notes receivable from associated companies		460,023		-		292,896		-			752,919
Materials and supplies, at average cost		195		238,936		221,108		-			460,239
Prepayments and other		45,314		10,389		1,843		-			57,546
		839,041		411,992		585,598		(196,465	)		1,640,166
PROPERTY, PLANT AND EQUIPMENT:
In service		16,261		4,960,453		3,378,630		-			8,355,344
Less - Accumulated provision for depreciation		5,738		2,477,004		1,335,526		-			3,818,268
		10,523		2,483,449		2,043,104		-			4,537,076
Construction work in progress		345		170,063		169,478		-			339,886
		10,868		2,653,512		2,212,582		-			4,876,962
INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,238,272		-			1,238,272
Long-term notes receivable from associated companies		-		-		62,900		-			62,900
Investment in associated companies		1,471,184		-		-		(1,471,184	)		-
Other		6,474		65,833		202		-			72,509
		1,477,658		65,833		1,301,374		(1,471,184	)		1,373,681
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		24,248		-		-		-			24,248
Property taxes		-		20,946		23,165		-			44,111
Accumulated deferred income taxes		32,939		-		-		(32,939	)		-
Other		23,544		11,542		4,753		-			39,839
		80,731		32,488		27,918		(32,939	)		108,198
	$	2,408,298	$	3,163,825	$	4,127,472	$	(1,700,588	)	$	7,999,007
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	-	$	608,395	$	861,265	$	-		$	1,469,660
Notes payable to associated companies		-		1,022,197		-		-			1,022,197
Accounts payable-
Associated companies		375,328		11,964		365,222		(196,465	)		556,049
Other		32,864		103,767		-		-			136,631
Accrued taxes		54,537		32,028		26,666		-			113,231
Other		49,906		41,401		9,634		-			100,941
		512,635		1,819,752		1,262,787		(196,465	)		3,398,709
CAPITALIZATION:
Common stockholder's equity		1,859,363		78,542		1,392,642		(1,471,184	)		1,859,363
Long-term debt		-		1,057,252		556,970		-			1,614,222
		1,859,363		1,135,794		1,949,612		(1,471,184	)		3,473,585
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		-		25,293		129,095		(32,939	)		121,449
Accumulated deferred investment tax credits		-		38,894		26,857		-			65,751
Asset retirement obligations		-		24,272		735,956		-			760,228
Retirement benefits		10,255		92,772		-		-			103,027
Property taxes		-		21,268		23,165		-			44,433
Other		26,045		5,780		-		-			31,825
		36,300		208,279		915,073		(32,939	)		1,126,713
	$	2,408,298	$	3,163,825	$	4,127,472	$	(1,700,588	)	$	7,999,007

33

 

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2007	FirstEnergy Solutions Corp.			FGCO			NGC			Eliminations			Consolidated
	(In thousands)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	(77,782	)	$	255,301		$	12,324		$	-		$	189,843
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Equity contribution from parent		700,000			700,000			-			(700,000	)		700,000
Short-term borrowings, net		500,000			-			-			(135,153	)		364,847
Redemptions and Repayments-
Long-term debt		-			(616,792	)		(128,744	)		-			(745,536	)
Short-term borrowings, net		-			(135,153	)		-			135,153			-
Common stock dividend payments		(37,000	)		-			-			-			(37,000	)
Net cash provided from (used for) financing activities		1,163,000			(51,945	)		(128,744	)		(700,000	)		282,311
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(9,466	)		(215,804	)		(77,154	)		-			(302,424	)
Proceeds from asset sales		-			12,120			-			-			12,120
Sales of investment securities held in trusts		-			-			367,924			-			367,924
Purchases of investment securities held in trusts		-			-			(367,924	)		-			(367,924	)
Loans to associated companies		(376,444	)		-			192,268			-			(184,176	)
Investment in subsidiary		(700,000	)		-			-			700,000			-
Other		692			328			1,306			-			2,326
Net cash provided from (used for) investing activities		(1,085,218	)		(203,356	)		116,420			700,000			(472,154	)
Net change in cash and cash equivalents		-			-			-			-			-
Cash and cash equivalents at beginning of year		2			-			-			-			2
Cash and cash equivalents at end of year	$	2		$	-		$	-		$	-		$	2

34

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2006	FirstEnergy Solutions Corp.			FGCO			NGC			Eliminations		Consolidated
	(In thousands)
NET CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES	$	2,494		$	(11,420	)	$	169,114		$	-	$	160,188
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			146,718			105,260			-		251,978
Short-term borrowings, net		-			119,484			-			-		119,484
Net cash provided from financing activities		-			266,202			105,260			-		371,462
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(282	)		(87,256	)		(239,958	)		-		(327,496	)
Proceeds from asset sales		-			3,765			-			-		3,765
Sales of investment securities held in trusts		-			-			593,732			-		593,732
Purchases of investment securities held in trusts		-			-			(593,732	)		-		(593,732	)
Loans to associated companies		(2,906	)		(146,740	)		(35,325	)		-		(184,971	)
Other		694			(24,551	)		909			-		(22,948	)
Net cash used for investing activities		(2,494	)		(254,782	)		(274,374	)		-		(531,650	)
Net change in cash and cash equivalents		-			-			-			-		-
Cash and cash equivalents at beginning of year		2			-			-			-		2
Cash and cash equivalents at end of year	$	2		$	-		$	-		$	-	$	2

35