10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

OR

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.
333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-2323	THE CLEVELAND ELECTRIC ILLUMINATING COMPANY	34-0150020
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-3583	THE TOLEDO EDISON COMPANY	34-4375005
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-3491	PENNSYLVANIA POWER COMPANY	25-0718810
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-3141	JERSEY CENTRAL POWER & LIGHT COMPANY	21-0485010
	(A New Jersey Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-446	METROPOLITAN EDISON COMPANY	23-0870160
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-3522	PENNSYLVANIA ELECTRIC COMPANY	25-0718085
	(A Pennsylvania Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402

Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X No

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act):

YesX	No	FirstEnergy Corp.
Yes	NoX	Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

 

	OUTSTANDING
CLASS	AS OF NOVEMBER 2, 2005
FirstEnergy Corp., $.10 par value	329,836,276
Ohio Edison Company, no par value	100
The Cleveland Electric Illuminating Company, no par value	79,590,689
The Toledo Edison Company, $5 par value	39,133,887
Pennsylvania Power Company, $30 par value	6,290,000
Jersey Central Power & Light Company, $10 par value	15,371,270
Metropolitan Edison Company, no par value	859,500
Pennsylvania Electric Company, $20 par value	5,290,596

FirstEnergy Corp. is the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company common stock. Ohio Edison Company is the sole holder of Pennsylvania Power Company common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.

This Form 10-Q 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, the continued ability of our regulated utilities to collect transition and other charges, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) or levels of emission reductions related to the settlement agreement resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of government investigations and oversight, including by the Securities and Exchange Commission, the United States Attorney’s Office and the Nuclear Regulatory Commission as disclosed in the registrants’ Securities and Exchange Commission filings, generally, and with respect to the Davis-Besse Nuclear Power Station outage and heightened scrutiny at the Perry Nuclear Power Plant in particular, the availability and cost of capital, rising interest rates and other inflationary trends, the continuing availability and operation of generating units, the ability of generating units to continue to operate at, or near full capacity, the inability to accomplish or realize anticipated benefits of strategic goals (including the proposed transfer of nuclear generation assets), the ability to improve electric commodity margins and to experience growth in the distribution business, any decision of the Pennsylvania Public Utility Commission regarding the plan filed by Penn on October 11, 2005 to secure electricity supply for its customers at a set rate, the ability to access the public securities and other capital markets, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the final outcome in the proceeding related to FirstEnergy's Application for a Rate Stabilization Plan (RSP) in Ohio, specifically, the PUCO's acceptance of the September 9, 2005 proposed supplement to the RSP, the risks and other factors discussed from time to time in the registrants' Securities and Exchange Commission filings, including their annual report on Form 10-K for the year ended December 31, 2004, and other similar factors. A security rating is not a recommendation to buy, sell or hold securities and it may be subject to revision or withdrawal. Dividends declared from time to time on FirstEnergy's common stock during any annual period may in aggregate vary from the indicated amounts due to circumstances considered by FirstEnergy's Board of Directors at the time of the actual declarations. The registrants expressly disclaim any current intention to update any forward-looking statements contained in this document as a result of new information, future events, or otherwise.

TABLE OF CONTENTS

		Pages
Glossary of Terms		iii-v
Part I.Financial Information
Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of             Results of Operation and Financial Condition
	Notes to Consolidated Financial Statements	1-25
FirstEnergy Corp.
	Consolidated Statements of Income	26
	Consolidated Statements of Comprehensive Income	27
	Consolidated Balance Sheets	28
	Consolidated Statements of Cash Flows	29
	Report of Independent Registered Public Accounting Firm	30
	Management's Discussion and Analysis of Results of Operations and	31-65
	Financial Condition
Ohio Edison Company
	Consolidated Statements of Income and Comprehensive Income	66
	Consolidated Balance Sheets	67
	Consolidated Statements of Cash Flows	68
	Report of Independent Registered Public Accounting Firm	69
	Management's Discussion and Analysis of Results of Operations and	70-82
	Financial Condition
The Cleveland Electric Illuminating Company
	Consolidated Statements of Income and Comprehensive Income	83
	Consolidated Balance Sheets	84
	Consolidated Statements of Cash Flows	85
	Report of Independent Registered Public Accounting Firm	86
	Management's Discussion and Analysis of Results of Operations and	87-98
	Financial Condition
The Toledo Edison Company
	Consolidated Statements of Income and Comprehensive Income	99
	Consolidated Balance Sheets	100
	Consolidated Statements of Cash Flows	101
	Report of Independent Registered Public Accounting Firm	102
	Management's Discussion and Analysis of Results of Operations and	103-114
	Financial Condition
Pennsylvania Power Company
	Consolidated Statements of Income and Comprehensive Income	115
	Consolidated Balance Sheets	116
	Consolidated Statements of Cash Flows	117
	Report of Independent Registered Public Accounting Firm	118
	Management's Discussion and Analysis of Results of Operations and	119-127
	Financial Condition

i

TABLE OF CONTENTS (Cont'd)

		Pages
Jersey Central Power & Light Company
	Consolidated Statements of Income and Comprehensive Income	128
	Consolidated Balance Sheets	129
	Consolidated Statements of Cash Flows	130
	Report of Independent Registered Public Accounting Firm	131
	Management's Discussion and Analysis of Results of Operations and	132-140
	Financial Condition
Metropolitan Edison Company
	Consolidated Statements of Income and Comprehensive Income	141
	Consolidated Balance Sheets	142
	Consolidated Statements of Cash Flows	143
	Report of Independent Registered Public Accounting Firm	144
	Management's Discussion and Analysis of Results of Operations and	145-153
	Financial Condition
Pennsylvania Electric Company
	Consolidated Statements of Income and Comprehensive Income	154
	Consolidated Balance Sheets	155
	Consolidated Statements of Cash Flows	156
	Report of Independent Registered Public Accounting Firm	157
	Management's Discussion and Analysis of Results of Operations and	158-166
	Financial Condition
Item 3.Quantitative and Qualitative Disclosures About Market Risk		167
Item 4.Controls and Procedures		167
Part II.Other Information
Item 1.Legal Proceedings		168
		168
Item 2.Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
Item 5.  Other Information		168
Item 6.Exhibits		169-184

ii

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, Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CFC	Centerior Funding Corporation, a wholly owned finance subsidiary of CEI
Companies	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
EUOC	Electric Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, and ATSI)
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstCom	First Communications, LLC, provides local and long-distance telephone service
FirstEnergy	FirstEnergy Corp., a registered public utility holding company
FSG	FirstEnergy Facilities Services Group, LLC, the parent company of several heating, ventilation,
	air conditioning and energy management companies
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on
	November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MYR	MYR Group, Inc., a utility infrastructure construction service company
NGC	FirstEnergy Nuclear Generation Corp. established to acquire FirstEnergy's nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
OE Companies	OE and Penn
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TEBSA	Termobarranquilla S. A., Empresa de Servicios Publicos

The following abbreviations and acronyms are used to identify frequently used terms in this report:

AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 25	APB Opinion No. 25, "Accounting for Stock Issued to Employees"
APB 29	APB Opinion No. 29, “Accounting for Nonmonetary Transactions”
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CAIR	Clean Air Interstate Rule
CAL	Confirmatory Action Letter
CAT	Commercial Activity Tax
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
DOJ	United States Department of Justice
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 03-1	EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain
	Investments”
EITF 04-13	EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”
EITF 99-19	EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent”
EPA	Environmental Protection Agency
ERO	Electric Reliability Organization
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FIN 46R	FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"

iii

FIN 47	FASB Interpretation 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”
FMBs	First Mortgage Bonds
FSP	FASB Staff Position
FSP EITF 03-1-1	FASB Staff Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of EITF Issue
	No. 03-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain
	Investments"
FSP 109-1	FASB Staff Position No. 109-1, “Application of FASB Statement No. 109, Accounting for Income  Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004”
GCAF	Generation Charge Adjustment Factor
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases
HVAC	Heating, Ventilation and Air-conditioning
IBEW	International Brotherhood of Electrical Workers
KWH	Kilowatt-hours
LOC	Letter of Credit
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
MOU	Memorandum of Understanding
MSG	Market Support Generation
MTC	Market Transition Charge
MW	Megawatts
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NJBPU	New Jersey Board of Public Utilities
NOAC	Northwest Ohio Aggregation Coalition
NOV	Notices of Violation
NOx	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NUG	Non-Utility Generation
OCA	Office of Consumer Advocate
OCC	Ohio Consumers' Counsel
OCI	Other Comprehensive Income
OPAE	Ohio Partners for Affordable Energy
OPEB	Other Post-Employment Benefits
OSBA	Office of Small Business Advocate
OTS	Office of Trial Staff
PCAOB	Public Company Accounting Oversight Board (United States)
PCRBs	Pollution Control Revenue Bonds
PICA	Penelec Industrial Customer Association
PJM	PJM Interconnection, L.L.C.
PLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PRP	Potentially Responsible Party
PSA	Purchase and Sale Agreement
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act of 1935
RCP	Rate Certainty Plan
RSP	Rate Stabilization Plan
RTC	Regulatory Transition Charge
S&P	Standard & Poor’s Ratings Service
SBC	Societal Benefits Charge
SEC	United States Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS 123	SFAS No. 123, "Accounting for Stock-Based Compensation"
SFAS 123(R)	SFAS No. 123 (revised 2004), “Share-Based Payment”
SFAS 131	SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and
	Extinguishment of Liabilities”
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 153	SFAS No. 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

iv

SFAS 154	SFAS No. 154, “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”
SO2	Sulfur Dioxide
TBC	Transition Bond Charge
TMI-2	Three Mile Island Unit 2
UWUA	Utility Workers Union of America
VIE	Variable Interest Entity

v

PART I. FINANCIAL INFORMATION

FIRSTENERGY CORP. AND SUBSIDIARIES

OHIO EDISON COMPANY AND SUBSIDIARIES

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES

THE TOLEDO EDISON COMPANY AND SUBSIDIARY

PENNSYLVANIA POWER COMPANY AND SUBSIDIARY

JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES

METROPOLITAN EDISON COMPANY AND SUBSIDIARIES

PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1 - ORGANIZATION AND BASIS OF PRESENTATION:

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

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

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2004 for FirstEnergy and the Companies. The consolidated unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain businesses divested in the nine months ended September 30, 2005 have been classified as discontinued operations on the Consolidated Statements of Income (see Note 6). As discussed in Note 16, interim period segment reporting in 2004 was reclassified to conform with the current year business segment organizations and operations.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 11) when it is determined to be the VIE's primary beneficiary. Investments in nonconsolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control, (20-50 percent owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheet and the percentage share of the entity’s earnings is reported in the Consolidated Statement of Income. Certain prior year amounts have been reclassified to conform to the current presentation.

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

2 - ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS

FES engages in purchase and sale transactions in the PJM Market to support the supply of end-use customers, including PLR requirements in Pennsylvania. In conjunction with FirstEnergy's dedication of its Beaver Valley Plant to PJM on January 1, 2005, FES began accounting for purchase and sale transactions in the PJM Market based on its net hourly position -- recording each hour as either an energy purchase in Fuel and purchased power expense or an energy sale, respectively, in the Consolidated Statements of Income relating to the Power Supply Management Services segment. Hourly energy positions are aggregated to recognize gross purchases and sales for the month.

1

This revised method of accounting, which has no impact on net income, is consistent with the practice of other energy companies that have dedicated generating capacity to PJM and correlates with PJM's scheduling and reporting of hourly energy transactions. FES also applies the net hourly methodology to purchase and sale transactions in MISO's energy market, which became active on April 1, 2005.

For periods prior to January 1, 2005, FirstEnergy did not have substantial generating capacity in PJM and as such, FES recognized purchases and sales in the PJM Market by recording each discrete transaction. Under these transactions, FES would often buy a specific quantity of energy at a certain location in PJM and simultaneously sell a specific quantity of energy at a different location. Physical delivery occurred and the risks and rewards of ownership transferred with each transaction. FES accounted for those transactions on a gross basis in accordance with EITF 99-19.

At its September 2005 meeting, the FASB's EITF reached a final consensus on EITF 04-13, which relates to the accounting for purchases and sales of inventory with the same counterparty. The Task Force concluded that two or more transactions with the same counterparty should be viewed as a single nonmonetary transaction within the scope of APB 29, when the transactions are entered into "in contemplation" of one another. The consensus will be effective for new arrangements entered into, or modifications of existing arrangements, in interim or annual periods beginning after March 15, 2006. Retrospective application to prior transactions and/or restatement of prior period financial statements is not permitted. Accordingly, EITF 04-13 is not applicable to FES' purchases and sales in the PJM Market made prior to January 1, 2005. The recognition of these transactions on a net basis in 2004 would have no impact on net income, but would have reduced both wholesale revenue and purchased power expense by $264 million and $828 million for the three months and nine months ended September 30, 2004, respectively.

3 - DEPRECIATION

During the second half of 2004, FirstEnergy engaged an independent third party to assist in reviewing the service lives of its fossil generation units. This study was completed in the first quarter of 2005. As a result of the analysis, FirstEnergy extended the estimated service lives of its fossil generation units for periods ranging from 11 to 33 years during the first quarter of 2005. Extension of the service lives will provide improved matching of depreciation expense with the expected economic lives of those generation units.

4 - EARNINGS PER SHARE

Basic earnings per share are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. Stock-based awards during the nine months ended September 30, 2004, to purchase 3.4 million shares of common stock were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. No stock-based awards were excluded from the calculation in the three months ended September 30, 2005 and 2004, and the nine months ended September 30, 2005. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Basic and Diluted Earnings per Share	2005		2004		2005		2004
	(In thousands, except per share amounts)
Income Before Discontinued Operations	$	331,832	$	296,125	$	651,627	$	670,334
Average Shares of Common Stock Outstanding:
Denominator for basic earnings per share
(weighted average shares outstanding)		328,119		327,499		328,030		327,280
Assumed exercise of dilutive stock options and awards		2,074		1,600		1,896		1,570
Denominator for diluted earnings per share		330,193		329,099		329,926		328,850
Income Before Discontinued Operations per Common Share:
Basic		$1.01		$0.90		$1.99		$2.05
Diluted		$1.01		$0.90		$1.98		$2.04

2

5 - GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment is indicated, FirstEnergy recognizes a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. FirstEnergy's 2005 annual review was completed in the third quarter of 2005 with no impairment indicated.

FirstEnergy's goodwill primarily relates to its regulated services segment. In the nine months ended September 30, 2005, FirstEnergy adjusted goodwill related to the divestiture of non-core operations (FES' retail natural gas business, MYR's Power Piping Company subsidiary, and a portion of its interest in FirstCom) as further discussed in Note 6. In addition, adjustments to the former GPU and Centerior companies' goodwill were recorded to reverse pre-merger tax accruals due to final resolution of these tax contingencies. FirstEnergy estimates that completion of transition cost recovery (see Note 14) will not result in an impairment of goodwill relating to its regulated business segment. A summary of the changes in goodwill for the three months and nine months ended September 30, 2005 is shown below.

Three Months Ended	FirstEnergy			CEI			TE			JCP&L		Met-Ed		Penelec
	(In millions)
Balance as of July 1, 2005	$	6,033		$	1,694		$	505		$	1,984	$	868	$	887
Pre-merger tax adjustments related to Centerior acquisition		(9	)		(5	)		(4	)		-		-		-
Balance as of September 30, 2005	$	6,024		$	1,689		$	501		$	1,984	$	868	$	887

Nine Months Ended	FirstEnergy			CEI			TE			JCP&L			Met-Ed			Penelec
	(In millions)
Balance as of January 1, 2005	$	6,050		$	1,694		$	505		$	1,985		$	870		$	888
Non-core asset sales		(13	)		-			-			-			-			-
Pre-merger tax adjustments related to Centerior acquisition		(9	)		(5	)		(4	)		-			-			-
Pre-merger tax adjustments related to GPU acquisition		(4	)		-			-			(1	)		(2	)		(1	)
Balance as of September 30, 2005	$	6,024		$	1,689		$	501		$	1,984		$	868		$	887

6 - DIVESTITURES AND DISCONTINUED OPERATIONS

In December 2004, FES' retail natural gas business qualified as assets held for sale in accordance with SFAS 144. On March 31, 2005, FES completed the sale for an after-tax gain of $5 million. In March 2005, FirstEnergy sold 51% of its interest in FirstCom, resulting in an after-tax gain of $4 million. FirstEnergy accounts for its remaining 31.85% interest in FirstCom on the equity basis.

During the nine months ended September 30, 2005, FirstEnergy sold certain of its FSG subsidiaries (Elliott-Lewis, Spectrum and Cranston), and MYR’s Power Piping Company subsidiary, resulting in an after-tax gain of $12 million. FSG's remaining subsidiaries qualify as assets held for sale in accordance with SFAS 144 and are expected to be recognized as completed sales within one year. The assets and liabilities of these remaining FSG subsidiaries are not material to FirstEnergy’s Consolidated Balance Sheet as of September 30, 2005, and therefore have not been separately classified as assets held for sale.

As of September 30, 2005, the remaining FSG businesses do not meet the criteria for discontinued operations; therefore, the net results from these subsidiaries have been included in continuing operations. See Note 16 for FSG's segment financial information.

Operating results from discontinued operations (including the gains on sales of assets discussed above) for Elliott-Lewis, Cranston, Power Piping and FES' retail natural gas business are summarized as follows:

 

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(In millions)
Revenues	$	1	$	151	$	214	$	508
Income before income taxes	$	1	$	4	$	10	$	10
Income from discontinued operations, net of tax	$	1	$	3	$	19	$	6

3

The following table summarizes the sources of income from discontinued operations.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(In millions)
Discontinued operations (net of tax)
Gain on sale:
Retail gas business	$	-	$	-	$	5	$	-
FSG and MYR subsidiaries		-		-		12		-
Reclassification of operating income, net of tax		1		3		2		6
Total	$	1	$	3	$	19	$	6

7 - DERIVATIVE INSTRUMENTS

FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight to risk management activities throughout the Company.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet that criteria are accounted for on the accrual basis. The changes in the fair value of a derivative instrument are recorded in current earnings, in other comprehensive income, or as part of the value of the hedged item depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness.

FirstEnergy has entered into fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. During the third quarter of 2005, FirstEnergy unwound swaps with a total notional amount of $350 million from which it received immaterial net cash gains. The gains will be recognized in earnings over the remaining maturity of each respective hedged security as reduced interest expense. As of September 30, 2005, the aggregate notional value of interest rate swap agreements outstanding was $1.05 billion.

FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings. The impact of ineffectiveness on earnings during the three months and nine months ended September 30, 2005 was not material.

During the third quarter of 2005, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the possible issuances of fixed-rate, long-term debt securities for one or more of its consolidated entities in the second half of 2006 as outstanding debt matures. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of September 30, 2005, FirstEnergy had entered into forward swaps with an aggregate notional amount of $500 million. As of September 30, 2005 the forward swaps had a fair value of $2 million.

The net deferred losses of $79 million included in AOCL as of September 30, 2005, for derivative hedging activity, as compared to the December 31, 2004 balance of $92 million of net deferred losses, resulted from a $6 million decrease related to current hedging activity, a $4 million increase due to the sale of gas business contracts and an $11 million decrease due to net hedge losses included in earnings during the nine months ended September 30, 2005. Approximately $14 million of the net deferred losses on derivative instruments in AOCL as of September 30, 2005 is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors.

FirstEnergy trades commodity derivatives and periodically experiences net open positions. FirstEnergy’s risk management policies limit the exposure to market risk from open positions and require daily reporting to management of potential financial exposures. During the three months and nine months ended September 30, 2005, the effect of trading on earnings was not material.

4

8 - STOCK BASED COMPENSATION

FirstEnergy applies the recognition and measurement principles of APB 25 and related interpretations in accounting for its stock-based compensation plans. No material stock-based employee compensation expense is reflected in net income for options as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value.

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123 which requires expensing the fair value of stock options (see Note 15). In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. FirstEnergy will be required to adopt this standard beginning January 1, 2006. The table below summarizes the effects on FirstEnergy’s net income and earnings per share had FirstEnergy applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation in the current reporting periods.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands, except per share amounts)
Net income, as reported	$	332,360		$	298,622		$	670,078		$	676,666
Add back compensation expense
reported in net income, net of tax
(based on APB 25)(1)		17,404			13,549			39,785			29,355
Deduct compensation expense based
upon estimated fair value, net of tax(2)		(18,378	)		(16,981	)		(44,825	)		(40,380	)
Net income, as adjusted	$	331,386		$	295,190		$	665,038		$	665,641
Earnings Per Share of Common Stock -
Basic
As reported		$1.01			$0.91			$2.04			$2.07
As adjusted		$1.01			$0.90			$2.03			$2.03
Diluted
As reported		$1.01			$0.91			$2.03			$2.06
As adjusted		$1.00			$0.90			$2.02			$2.02
(1)Includes restricted stock, restricted stock units, stock options, performance shares, Employee Stock Ownership Plan,Executive Deferred Compensation Plan and Deferred Compensation Plan for outsideDirectors.
(2) Assumes vesting at age 65.

FirstEnergy reduced the use of stock options in 2005 and increased the use of performance-based, restricted stock units. Therefore, the pro forma effects of applying SFAS 123(R) may not be representative of its future effect. FirstEnergy does not expect to accelerate out-of-the-money options in anticipation of implementing SFAS 123(R) on January 1, 2006.

9 - ASSET RETIREMENT OBLIGATIONS

FirstEnergy has identified applicable legal obligations for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash disposal sites. The ARO liability of $1.130 billion as of September 30, 2005 included $1.115 billion for nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The Companies' share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.

In the third quarter of 2005, FirstEnergy revised the ARO associated with Beaver Valley Units 1 and 2 as a result of an updated decommissioning study. The present value of revisions in the estimated cash flows associated with projected decommissioning costs increased the ARO for Beaver Valley Unit 1 by $21 million and decreased the ARO for Beaver Valley Unit 2 by $22 million, resulting in a net decrease in the ARO liability and corresponding plant asset of $1 million (OE - ($2) million, CEI - ($5) million, TE - ($5) million and Penn - $11 million).

The Companies maintain trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2005, the fair value of the decommissioning trust assets was $1.7 billion.

5

The following tables analyze changes to the ARO balance during the three months and nine months ended September 30, 2005 and 2004, respectively.

Three Months Ended	FirstEnergy			OE			CEI			TE			Penn		JCP&L			Met-Ed			Penelec
	(In millions)
Balance, July 1, 2005	$	1,113		$	208		$	281		$	201		$	143	$	75		$	137		$	68
Liabilities incurred		-			-			-			-			-		-			-			-
Liabilities settled		-			-			-			-			-		-			-			-
Accretion		18			3			5			4			2		1			2			1
Revisions in estimated
cash flows		(1	)		(2	)		(5	)		(5	)		11		-			-			-
Balance, September 30, 2005	$	1,130		$	209		$	281		$	200		$	156	$	76		$	139		$	69
Balance, July 1, 2004	$	1,217		$	194		$	263		$	188		$	134	$	113		$	216		$	108
Liabilities incurred		-			-			-			-			-		-			-			-
Liabilities settled		-			-			-			-			-		-			-			-
Accretion		19			4			5			3			2		2			3			1
Revisions in estimated
cash flows		(176	)		-			-			-			-		(43	)		(89	)		(44	)
Balance, September 30, 2004	$	1,060		$	198		$	268		$	191		$	136	$	72		$	130		$	65

Nine Months Ended	FirstEnergy			OE			CEI			TE			Penn		JCP&L			Met-Ed			Penelec
	(In millions)
Balance, January 1, 2005	$	1,078		$	201		$	272		$	195		$	138	$	72		$	133		$	67
Liabilities incurred		-			-			-			-			-		-			-			-
Liabilities settled		-			-			-			-			-		-			-			-
Accretion		53			10			14			10			7		4			6			2
Revisions in estimated
cash flows		(1	)		(2	)		(5	)		(5	)		11		-			-			-
Balance, September 30, 2005	$	1,130		$	209		$	281		$	200		$	156	$	76		$	139		$	69
Balance, January 1, 2004	$	1,179		$	188		$	255		$	182		$	130	$	110		$	210		$	105
Liabilities incurred		-			-			-			-			-		-			-			-
Liabilities settled		-			-			-			-			-		-			-			-
Accretion		57			10			13			9			6		5			9			4
Revisions in estimated
cash flows		(176	)		-			-			-			-		(43	)		(89	)		(44	)
Balance, September 30, 2004	$	1,060		$	198		$	268		$	191		$	136	$	72		$	130		$	65

10 - PENSION AND OTHER POSTRETIREMENT BENEFITS:

The components of FirstEnergy's net periodic pension cost and other postretirement benefits cost (including amounts capitalized) for the three months and nine months ended September 30, 2005 and 2004, consisted of the following:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Pension Benefits	2005			2004			2005			2004
	(In millions)
Service cost	$	19		$	19		$	58		$	58
Interest cost		64			63			191			189
Expected return on plan assets		(86	)		(71	)		(259	)		(215	)
Amortization of prior service cost		2			2			6			7
Recognized net actuarial loss		9			10			27			29
Net periodic cost	$	8		$	23		$	23		$	68

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Other Postretirement Benefits	2005			2004			2005			2004
	(In millions)
Service cost	$	10		$	9		$	30		$	27
Interest cost		27			26			83			83
Expected return on plan assets		(11	)		(10	)		(34	)		(32	)
Amortization of prior service cost		(11	)		(9	)		(33	)		(28	)
Recognized net actuarial loss		10			9			30			29
Net periodic cost	$	25		$	25		$	76		$	79

Pension and postretirement benefit obligations are allocated to the FirstEnergy subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension benefits (credit) and net periodic postretirement benefits (including amounts capitalized) recognized by each of the Companies in the three months and nine months ended September 30, 2005 and 2004 were as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Pension Benefits (Credit)	2005			2004		2005			2004
	(In millions)
OE	$	0.2		$	1.7	$	0.7		$	5.2
Penn		(0.2	)		0.1		(0.7	)		0.4
CEI		0.3			1.6		1.0			4.8
TE		0.3			0.8		1.0			2.3
JCP&L		(0.3	)		1.9		(0.8	)		5.6
Met-Ed		(1.1	)		0.1		(3.2	)		0.2
Penelec		(1.3	)		0.1		(4.0	)		0.4

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Other Postretirement Benefits	2005		2004		2005		2004
	(In millions)
OE	$	5.8	$	5.7	$	17.3	$	17.7
Penn		1.2		1.2		3.5		3.7
CEI		3.8		4.4		11.4		13.7
TE		2.2		1.7		6.5		5.0
JCP&L		1.5		1.0		5.7		3.5
Met-Ed		0.4		0.7		1.2		2.5
Penelec		2.0		0.7		5.9		2.5

11 - VARIABLE INTEREST ENTITIES

Leases

FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $678 million, $103 million and $541 million, respectively, that would not be payable if the casualty value payments are made.

7

Power Purchase Agreements

In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants.

As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. Purchased power costs from these entities during the three months and nine months ended September 30, 2005 and 2004 are shown in the table below:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2005		2004		2005		2004
	(In millions)
JCP&L		$	33	$	26	$	74	$	71
Met-Ed			10		13		40		38
Penelec			7		7		21		20
Total		$	50	$	46	$	135	$	129

Securitized Transition Bonds

The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition, a wholly owned limited liability company of JCP&L. In June 2002, JCP&L Transition sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The transition bonds are obligations of JCP&L Transition only and are collateralized solely by the equity and assets of JCP&L Transition, which consist primarily of bondable transition property. The bondable transition property is solely the property of JCP&L Transition.

Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to JCP&L Transition and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $0.1 million that is payable from TBC collections.

12 - OHIO TAX LEGISLATION

On June 30, 2005, the State of Ohio enacted tax legislation that creates a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that were not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005.

8

The increase (in millions) to income taxes associated with the adjustment to net deferred taxes for the nine months ended September 30, 2005 is summarized below:

OE	$	36.0
CEI		7.5
TE		17.5
Other FirstEnergy subsidiaries		10.7
Total FirstEnergy	$	71.7

Income tax expenses were (increased) reduced during the three months and nine months ended September 30, 2005 by the initial phase-out of the Ohio income-based franchise tax and phase-in of the CAT tax as summarized below:

	Three Months Ended			Nine Months Ended
	September 30, 2005			September 30, 2005
	(In millions)
OE	$	1.6		$	6.5
CEI		(3.1	)		(1.7	)
TE		0.7			1.2
Other FirstEnergy subsidiaries		0.7			1.5
Total FirstEnergy	$	(0.1	)	$	7.5

13 - COMMITMENTS, GUARANTEES AND CONTINGENCIES:

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. Such agreements include contract guarantees, surety bonds and ratings contingent collateralization provisions. As of September 30, 2005, outstanding guarantees and other assurances aggregated approximately $2.7 billion and included contract guarantees ($1.3 billion), surety bonds ($0.3 billion) and LOCs ($1.1 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities - principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. Such parental guarantees amount to $0.8 billion (included in the $1.3 billion discussed above) as of September 30, 2005 and the likelihood is remote that such guarantees will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related contracts.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating-downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of September 30, 2005:

	Total		Collateral Paid				Remaining
Collateral Provisions	Exposure		Cash		LOC		Exposure
	(In millions)
Credit rating downgrade	$	445	$	213	$	18	$	214
Adverse event		77		-		5		72
Total	$	522	$	213	$	23	$	286

On October 3, 2005, S&P raised the senior unsecured ratings of FirstEnergy's holding company to 'BBB-' from 'BB+'. As a result of the rating upgrade, $109 million of cash collateral was subsequently returned to FirstEnergy.

9

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $307 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

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

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

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($47 million as of September 30, 2005) which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $36 million on October 15, 2005.

(B)ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future changes in regulatory policies and what, if any, the effects of such changes would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $670 million for 2005 through 2007.

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

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

Clean Air Act Compliance

FirstEnergy is required to meet federally approved SO₂ 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. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

FirstEnergy believes it is complying 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 from FirstEnergy's facilities. The EPA's NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85 percent reduction in utility plant NO_x emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO_x emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO_x budgets established under State Implementation Plans through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

10

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂) in all cases from the 2003 levels. FirstEnergy's Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO₂ and NO_x emissions, whereas their New Jersey fossil-fired generation facilities will be subject to a cap on NO_x emissions only. According to the EPA, SO₂ emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO₂ emissions in affected states to just 2.5 million tons annually. NO_x emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NO_x cap of 1.3 million tons annually. The future cost of compliance with these regulations may be substantial and will depend on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the "Clean Air Mercury Rule," 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 Clean Air Mercury Rule have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, was approved by the Court on July 11, 2005, requires OE and Penn to reduce No_x and SO₂ emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). As disclosed in FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, during the first quarter of 2005, for probable future cash contributions toward environmentally beneficial projects.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (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 Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

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FirstEnergy cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per kilowatt-hour of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

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

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

Regulation of Hazardous Waste

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

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $64 million (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed - $0.1 million and other - $14.6 million) have been accrued through September 30, 2005.

(C)OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Division. JCP&L has filed a motion for summary judgment. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 2005.

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On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of the four cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and American Electric Power Co. as well) for claims paid to insureds for claims allegedly arising as a result of the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

Nuclear Plant Matters

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. FirstEnergy accrued $2.0 million for a potential fine prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Effective July 1, 2005, the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.

On August 12, 2004, the NRC notified FENOC that it would increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the preceding two years and the licensee's failure to take prompt and corrective action. FENOC operates the Perry Nuclear Power Plant, which is currently owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry 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. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

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Other Legal Matters

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

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

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties’ collective bargaining agreement. At the conclusion of the June 1, 2005, hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of this award by filing a motion to vacate in Federal Court in New Jersey on October 18, 2005. JCP&L recognized a liability for the potential $16.1 million award during the three months ended September 30, 2005.

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

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

14 - REGULATORY MATTERS:

Reliability Initiatives

In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. In 2004, FirstEnergy completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training and emergency response preparedness recommended for completion in 2004. On July 14, 2004, NERC independently verified that FirstEnergy had implemented the various initiatives to be completed by June 30 or summer 2004, with minor exceptions noted by FirstEnergy, which exceptions are now essentially complete. FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the Energy Policy Act of 2005 that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

In May 2004, the PPUC issued an order approving revised reliability benchmarks and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004, due to their implementation of automated outage management systems following restructuring. Evidentiary hearings have been scheduled for November 2005. FirstEnergy is unable to predict the outcome of this proceeding.

The Energy Policy Act of 2005 provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On September 1, 2005, the FERC issued a Notice of Proposed Rulemaking to establish certification requirements for the ERO, as well as regional entities envisioned to assume monitoring and compliance responsibility for the new reliability standards. The FERC expects to adopt a final rule on or before February 2006 regarding certification requirements for the ERO and regional entities.

The NERC is expected to reorganize its structure to meet the FERC’s certification requirements for the ERO. Following adoption of the final rule, the NERC will be required to make a filing with the FERC to obtain certification as the ERO. The proposed rule also provides for regional reliability organizations designed to replace the current regional councils. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have signed an MOU designed to consolidate their regions into a new regional reliability organization known as ReliabilityFirst Corporation. Their intent is to file and obtain certification under the final rule as a “regional entity”. All of FirstEnergy’s facilities would be located within the ReliabilityFirst region.

On a parallel path, the NERC is establishing working groups to develop reliability standards to be filed for approval with the FERC following the NERC’s certification as an ERO. These reliability standards are expected to build on the current NERC Version 0 reliability standards. It is expected that the proposed reliability standards will be filed with the FERC in early 2006.

The impact of this effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC Version 0 standards. The financial impact of complying with the new standards cannot be determined at this time. However, the Energy Policy Act of 2005 requires that all prudent costs incurred to comply with the new reliability standards be recovered in rates.

Ohio

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, the Ohio Companies filed an application with the PUCO to establish a GCAF rider under the RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.

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On September 9, 2005, the Ohio Companies filed an application with the PUCO that, if approved, would supplement their existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

· Maintain the existing level of base distribution rates through December 31, 2008 for OE and TE, and

 April 30, 2009 for CEI;

· Defer and capitalize certain distribution costs to be incurred during the period January 1, 2006

 through December 31, 2008, not to exceed $150 million in each of the three years;

· Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized

 costs will occur as of December 31, 2008 for OE and TE, and as of December 31, 2010 for CEI;

· Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE,

 $45 million for TE, and $85 million for CEI by accelerating the application of each respective

 company's accumulated cost of removal regulatory liability; and

· Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and

 2008, respectively, from all OE and TE distribution and transmission customers through a fuel

 recovery mechanism and OE, TE, and CEI may defer and capitalize increased fuel costs above the

 amount collected through the fuel recovery mechanism.

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

	Estimated Net Amortization
	RCP								RSP
Amortization							Total								Total
Period	OE		CEI		TE		Ohio		OE		CEI		TE		Ohio
	(In millions)
2006	$	169	$	100	$	80	$	349	$	175	$	94	$	73	$	342
2007		176		111		89		376		237		104		82		423
2008		198		129		100		427		206		122		159		487
2009		-		216		-		216		-		318		-		318
2010		-		268		-		268		-		271		-		271
Net Amortization*	$	543	$	824	$	269	$	1,636	$	618	$	909	$	314	$	1,841
* RCP aggregate amortization is less than amortization under the RSP due to the accelerated application of regulatory liabilities to reduce deferred shopping incentives.

Under provisions of the RSP, the PUCO may require the Ohio Companies to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

Pennsylvania

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

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In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

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

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation, and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to defer differences between NUG contract costs and current market prices. On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase. 

In October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

New Jersey

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of September 30, 2005, the accumulated deferred cost balance totaled approximately $508 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the July 31, 2003 deferred balance. JCP&L is in discussions with the NJBPU staff as a result of the stipulated settlement agreements (as further discussed below) which recommended that the NJBPU issue an order regarding JCP&L's application. On July 20, 2005, JCP&L requested the NJBPU to set a procedural schedule for this matter and is awaiting NJBPU action.

The 2003 NJBPU decision on JCP&L's base electric rate proceeding (the Phase I Order) disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The Phase I order also provided for a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system's reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the Phase I Order, respectively. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

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· An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the Phase I Order reconsideration;

· An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's Phase II Petition;

· An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred cost balance;

· An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

· A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in JCP&L's authorized return on common equity from 9.75% to 9.5% if the target is not met for two consecutive quarters. The authorized return on common equity would then be restored to 9.75% if the target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenue increase also reflects a three-year amortization of JCP&L's one-time service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with accelerated tree trimming and other reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of common stock) in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order for the period June 1, 2005 through May 31, 2006. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On July 1, 2005, JCP&L filed its BGS procurement proposals for post transition year four. The auction is scheduled to take place in February 2006 for the annual supply period beginning June 1, 2006.

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

Transmission

On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs estimated to be incurred from 2004 through 2007. On March 4, 2005, the FERC approved ATSI's request to defer those costs ($21 million deferred as of September 30, 2005). ATSI expects to file an application with the FERC in the second quarter of 2006 that would include recovery of the deferred costs.

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The Ohio Companies reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by the Ohio Companies, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $61.2 million. This amount includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, the Companies will file a modification to the rider to determine revenues from July 2006 through June 2007.

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The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in the PUCO order issued on August 31, 2005 approving the stipulation referred to above. The OCC, OPAE and the Ohio Companies each filed applications for rehearing. The Ohio Companies sought authority to defer the transmission and ancillary service-related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied the Ohio Companies' and OCC’s applications and, at the request of the Ohio Companies, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

On January 12, 2005, Met-Ed and Penelec filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and neither company has yet implemented deferral accounting for these costs.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate proceedings are currently being litigated before the FERC. The outcome of these cases cannot be predicted.

Regulatory Assets

The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods. Without such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans. Under the RSP, recovery of these regulatory assets (OE - $302 million, CEI - $402 million, TE - $122 million, as of September 30, 2005) would have begun through a surcharge rate equal to the RTC rate in effect only after the transition costs have been fully recovered. Under the proposed RCP, OE's and TE's recovery of the new regulatory assets would begin January 1, 2006 and expected to be completed by December 31, 2008. CEI's new regulatory asset recovery would still begin after full recovery of its transition costs (estimated as of mid-2009) and expected to be completed by December 31, 2010. Amortization of the new regulatory assets for each accounting period would equal the amount of the surcharge revenue recognized during that period.

Regulatory transition costs as of September 30, 2005 for JCP&L and Met-Ed are approximately $2.4 billion and $0.6 billion, respectively. Deferral of above-market costs from power supplied by NUGs to JCP&L are approximately $1.4 billion and are being recovered through BGS and MTC revenues. Met-Ed has deferred above-market NUG costs totaling approximately $200 million. These costs are being recovered through CTC revenues. The regulatory asset for above-market NUG future obligations and the corresponding liability are adjusted to fair value at the end of each quarter. Recovery of the remaining regulatory transition costs is expected to continue under the provisions of the various regulatory proceedings in New Jersey and Pennsylvania.

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15 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FSP No. FAS 13-1, "Accounting for Rental Costs Incurred during the Construction Period"

 Issued in October 2005, FSP No. FAS 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. The effective date of the FSP guidance is the first reporting period beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP and its impact on the financial statements.

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

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. See Note 2 for an example of FirstEnergy's application of this Issue.

EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with FirstEnergy's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for FirstEnergy in the fourth quarter of 2005. FirstEnergy and the Companies are currently evaluating the effect this Interpretation will have on their financial statements.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy and the Companies will adopt this Statement effective January 1, 2006.

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SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for FirstEnergy. This FSP is not expected to have a material impact on FirstEnergy's financial statements.

SFAS 123(R), “Share-Based Payment”

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for companies with a fiscal year beginning January 1. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. FirstEnergy expects to adopt modified prospective application, without restatement of prior interim periods. Potential cumulative adjustments, if any, have not yet been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options for disclosure purposes only and expects to apply this pricing model upon adoption of SFAS 123(R).

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy beginning January 1, 2006. FirstEnergy is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP Issue and any impact on its investments.

FSP 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004”

Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to nine percent (when fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS 109, “Accounting for Income Taxes", which is consistent with FirstEnergy's accounting.

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16 - SEGMENT INFORMATION:

FirstEnergy has three reportable segments: regulated services, power supply management services and FSG. The aggregate “Other” segments do not individually meet the criteria to be considered a reportable segment. FirstEnergy's primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOCs in Ohio, Pennsylvania and New Jersey. The power supply management services segment primarily consists of the subsidiaries (FES, FGCO, NGC and FENOC) that sell electricity in deregulated markets and operate the generation facilities of OE, CEI, TE and Penn resulting from the deregulation of the Companies' electric generation business. “Other” consists of MYR (a construction service company), retail natural gas operations (recently sold - see Note 6) and telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable segments.”

The regulated services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition cost recovery. Assets of the regulated services segment as of September 30, 2005 and 2004, included generating units that were leased or whose output was sold to the power supply management services segment. The regulated services segment’s internal revenues represent the rental revenues for the generating unit leases.

The power supply management services segment has responsibility for FirstEnergy’s generation operations. Its net income is primarily derived from all electric generation sales revenues, which consist of generation services to regulated franchise customers who have not chosen an alternative generation supplier, retail sales in deregulated markets and all domestic unregulated electricity sales in the retail and wholesale markets, less the related costs of electricity generation and sourcing of commodity requirements. Its net income also reflects the expense of the intersegment generating unit leases and power sales agreements discussed above and property taxes related to those generating units.

Segment reporting for interim periods in 2004 have been reclassified to conform with the current year business segment organization and operations that were reported in the 2004 Form 10-K, emphasizing FirstEnergy's regulated electric businesses and power supply management operations and the reclassification of discontinued operations (see Note 6). FSG is being disclosed as a reporting segment due to its subsidiaries qualifying as held for sale (see Note 6 for discussion of the divestiture of three of those subsidiaries in 2005). Interest expense on holding company debt and corporate support services revenues and expenses are included in "Reconciling Items."

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Segment Financial Information
			Power
			Supply
	Regulated		Management		Facilities						Reconciling
	Services		Services		Services			Other			Adjustments			Consolidated
	(In millions)
Three Months Ended:
September 30, 2005
External revenues	$	1,676	$	1,712	$	59		$	138		$	2		$	3,587
Internal revenues		79		-		-			-			(79	)		-
Total revenues		1,755		1,712		59			138			(77	)		3,587
Depreciation and amortization		377		9		-			1			6			393
Net interest charges		88		11		-			2			57			158
Income taxes		254		7		-			4			(28	)		237
Income before discontinued operations		366		10		(2	)		6			(49	)		331
Discontinued operations		-		-		-			1			-			1
Net income (loss)		366		10		(2	)		7			(49	)		332
Total assets		28,385		1,741		82			522			644			31,374
Total goodwill		5,938		24		-			62			-			6,024
Property additions		207		79		-			1			7			294
September 30, 2004
External revenues	$	1,481	$	1,756	$	61		$	90		$	(3	)	$	3,385
Internal revenues		80		-		-			-			(80	)		-
Total revenues		1,561		1,756		61			90			(83	)		3,385
Depreciation and amortization		374		9		-			-			9			392
Net interest charges		82		9		-			-			60			151
Income taxes		226		30		-			(1	)		(41	)		214
Income before discontinued operations		315		44		-			(2	)		(61	)		296
Discontinued operations		-		-		1			2			-			3
Net income (loss)		315		44		1			-			(61	)		299
Total assets		28,416		1,467		182			596			564			31,225
Total goodwill		5,965		24		37			75			-			6,101
Property additions		157		46		-			1			7			211

Nine Months Ended:
September 30, 2005
External revenues	$	4,366	$	4,346		$	161		$	385		$	19		$	9,277
Internal revenues		237		-			-			-			(237	)		-
Total revenues		4,603		4,346			161			385			(218	)		9,277
Depreciation and amortization		1,076		26			-			2			19			1,123
Net interest charges		285		29			1			4			170			489
Income taxes		595		(10	)		3			13			(2	)		599
Income before discontinued operations		856		(15	)		(6	)		18			(201	)		652
Discontinued operations		-		-			13			5			-			18
Net income (loss)		856		(15	)		7			23			(201	)		670
Total assets		28,385		1,741			82			522			644			31,374
Total goodwill		5,938		24			-			62			-			6,024
Property additions		506		226			1			5			18			756
September 30, 2004
External revenues	$	4,049	$	4,828		$	156		$	324		$	4		$	9,361
Internal revenues		239		-			-			-			(239	)		-
Total revenues		4,288		4,828			156			324			(235	)		9,361
Depreciation and amortization		1,098		26			1			-			28			1,153
Net interest charges		301		30			-			2			169			502
Income taxes		541		55			(1	)		(19	)		(70	)		506
Income before discontinued operations		761		79			(1	)		39			(207	)		671
Discontinued operations		-		-			3			3			-			6
Net income (loss)		761		79			2			42			(207	)		677
Total assets		28,416		1,467			182			596			564			31,225
Total goodwill		5,965		24			37			75			-			6,101
Property additions		377		149			2			1			17			546
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily
consist of interest expense related to holding company debt, corporate support services revenues and expenses, fuel marketing revenues, which are
reflected as reductions to expenses for internal management reporting purposes, and elimination of intersegment transactions.

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17 - FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

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

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to the May 13, and May 18, 2005 agreements and FGCO's purchase option under the Master Facility Lease.

As contemplated by the agreements entered into in May 2005, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC currently operates and maintains the nuclear generation assets to be transferred. FirstEnergy currently expects to complete the nuclear asset transfers in the fourth quarter of 2005, subject to the receipt of required regulatory approvals.

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

The following table provides the value of assets pending sale along with the related liabilities as of September 30, 2005:

		OE			Penn		CEI		TE
	(In millions)
Assets Pending Sale
Property, plant and equipment		$	1,598		$	440	$	1,305	$	687
Other property and investments			363			147		433		276
Current assets			93			38		73		42
Deferred charges			(60	)		2		-		-
Total		$	1,994		$	627	$	1,811	$	1,005
Liabilities Related to Assets
Pending Sale
Long-term debt		$	238		$	53	$	-	$	-
Current liabilities			40			31		434		253
Noncurrent liabilities			280			226		362		202
Total		$	558		$	310	$	796	$	455
Net Assets Pending Sale		$	1,436		$	317	$	1,015	$	550

25

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands, except per share amounts)
REVENUES:
Electric utilities	$	2,935,547		$	2,526,971		$	7,573,858		$	6,874,574
Unregulated businesses (Note 2)		651,240			858,497			1,703,281			2,485,959
Total revenues		3,586,787			3,385,468			9,277,139			9,360,533
EXPENSES:
Fuel and purchased power (Note 2)		1,287,225			1,285,355			3,115,153			3,514,816
Other operating expenses		992,436			868,440			2,758,378			2,500,182
Provision for depreciation		152,786			147,052			444,443			439,017
Amortization of regulatory assets		364,337			324,300			981,750			905,488
Deferral of new regulatory assets		(123,827	)		(78,767	)		(303,496	)		(191,487	)
General taxes		187,562			177,452			540,606			514,174
Total expenses		2,860,519			2,723,832			7,536,834			7,682,190
INCOME BEFORE INTEREST AND INCOME TAXES		726,268			661,636			1,740,305			1,678,343
NET INTEREST CHARGES:
Interest expense		162,104			152,348			488,462			504,396
Capitalized interest		(7,005	)		(6,536	)		(11,957	)		(18,286	)
Subsidiaries’ preferred stock dividends		2,626			5,354			12,912			16,024
Net interest charges		157,725			151,166			489,417			502,134
INCOME TAXES		236,711			214,345			599,261			505,875
INCOME BEFORE DISCONTINUED OPERATIONS		331,832			296,125			651,627			670,334
Discontinued operations (net of income taxes (benefit) of
$367,000 and $1,625,000 in the three months ended
September 30, and ($8,684,000) and $3,762,000 in the nine
months ended September 30, of 2005 and 2004, respectively)
(Note 6)		528			2,497			18,451			6,332
NET INCOME	$	332,360		$	298,622		$	670,078		$	676,666
BASIC EARNINGS PER SHARE OF COMMON STOCK:
Earnings before discontinued operations	$	1.01		$	0.90		$	1.99		$	2.05
Discontinued operations (Note 6)		-			0.01			0.05			0.02
Net earnings per basic share	$	1.01		$	0.91		$	2.04		$	2.07
WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING		328,119			327,499			328,030			327,280
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
Earnings before discontinued operations	$	1.01		$	0.90		$	1.98		$	2.04
Discontinued operations (Note 6)		-			0.01			0.05			0.02
Net earnings per diluted share	$	1.01		$	0.91		$	2.03		$	2.06
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING		330,193			329,099			329,926			328,850
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.43		$	0.375		$	1.255		$	1.125
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements.

26

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005			2004		2005			2004
	(In thousands)
NET INCOME	$	332,360		$	298,622	$	670,078		$	676,666
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain on derivative hedges		17,723			5,927		19,023			26,536
Unrealized gain (loss) on available for sale securities		(13,093	)		8,715		(37,216	)		5,265
Other comprehensive income (loss)		4,630			14,642		(18,193	)		31,801
Income tax expense (benefit) related to other
comprehensive income		(1,797	)		2,498		(7,704	)		11,026
Other comprehensive income (loss), net of tax		6,427			12,144		(10,489	)		20,775
COMPREHENSIVE INCOME	$	338,787		$	310,766	$	659,589		$	697,441
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
statements.

27

FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2005			2004
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	139,812		$	52,941
Receivables -
Customers (less accumulated provisions of $37,429,000 and
$34,476,000, respectively, for uncollectible accounts)		1,336,969			979,242
Other (less accumulated provisions of $26,416,000 and
$26,070,000, respectively, for uncollectible accounts)		198,256			377,195
Materials and supplies, at average cost -
Owned		378,937			363,547
Under consignment		117,265			94,226
Prepayments and other		235,496			145,196
		2,406,735			2,012,347
PROPERTY, PLANT AND EQUIPMENT:
In service		22,777,299			22,213,218
Less - Accumulated provision for depreciation		9,688,122			9,413,730
		13,089,177			12,799,488
Construction work in progress		684,042			678,868
		13,773,219			13,478,356
INVESTMENTS:
Nuclear plant decommissioning trusts		1,711,112			1,582,588
Investments in lease obligation bonds		905,504			951,352
Other		773,994			740,026
		3,390,610			3,273,966
DEFERRED CHARGES:
Goodwill		6,024,376			6,050,277
Regulatory assets		5,045,838			5,532,087
Other		733,164			720,911
		11,803,378			12,303,275
	$	31,373,942		$	31,067,944
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	983,412		$	940,944
Short-term borrowings		246,505			170,489
Accounts payable		651,941			610,589
Accrued taxes		852,477			657,219
Other		1,110,511			929,194
		3,844,846			3,308,435
CAPITALIZATION:
Common stockholders’ equity -
Common stock, $0.10 par value, authorized 375,000,000 shares -
329,836,276 shares outstanding		32,984			32,984
Other paid-in capital		7,033,726			7,055,676
Accumulated other comprehensive loss		(323,601	)		(313,112	)
Retained earnings		2,115,434			1,856,863
Unallocated employee stock ownership plan common stock -
1,642,223 and 2,032,800 shares, respectively		(30,584	)		(43,117	)
Total common stockholders' equity		8,827,959			8,589,294
Preferred stock of consolidated subsidiaries		183,719			335,123
Long-term debt and other long-term obligations		9,418,734			10,013,349
		18,430,412			18,937,766
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,345,281			2,324,097
Asset retirement obligations		1,130,194			1,077,557
Power purchase contract loss liability		1,920,358			2,001,006
Retirement benefits		1,343,461			1,238,973
Lease market valuation liability		872,650			936,200
Other		1,486,740			1,243,910
		9,098,684			8,821,743
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
	$	31,373,942		$	31,067,944
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
balance sheets.

28

FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	332,360		$	298,622		$	670,078		$	676,666
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		152,786			147,052			444,443			439,017
Amortization of regulatory assets		364,337			324,300			981,750			905,488
Deferral of new regulatory assets		(123,827	)		(78,767	)		(303,496	)		(191,487	)
Nuclear fuel and lease amortization		25,785			26,776			63,363			71,782
Amortization of electric service obligation		(8,630	)		(3,336	)		(24,135	)		(12,877	)
Deferred purchased power and other costs		(39,215	)		(118,409	)		(231,438	)		(263,290	)
Deferred income taxes and investment tax credits, net		(37,851	)		37,138			24,034			(56,995	)
Deferred rents and lease market valuation liability		29,834			28,402			(71,275	)		(52,182	)
Accrued retirement benefit obligations		56,116			42,397			104,488			106,897
Accrued compensation, net		4,380			25,864			(32,895	)		48,186
Commodity derivative transactions, net		(55,101	)		17,336			(40,993	)		(37,443	)
Cash collateral from suppliers		76,978			-			76,978			-
Income from discontinued operations (Note 6)		(528	)		(2,497	)		(18,451	)		(6,332	)
Pension trust contribution		-			(500,000	)		-			(500,000	)
Decrease (increase) in operating assets -
Receivables		(90,673	)		16,288			(225,982	)		187,730
Materials and supplies		11,976			6,210			(39,876	)		7,173
Prepayments and other current assets		102,025			46,969			(57,192	)		(42,625	)
Increase (decrease) in operating liabilities -
Accounts payable		(44,369	)		(37,049	)		59,662			(145,691	)
Accrued taxes		167,851			152,009			207,006			296,668
Accrued interest		95,721			82,221			91,934			75,158
Prepayment for electric service - education programs		-			-			241,685			-
Other		(38,799	)		15,979			(7,416	)		32,370
Net cash provided from operating activities		981,156			527,505			1,912,272			1,538,213
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		88,950			86,754			334,300			961,474
Short-term borrowings, net		-			228,072			77,295			-
Redemptions and Repayments -
Preferred stock		(30,000	)		(1,000	)		(169,650	)		(1,000	)
Long-term debt		(162,939	)		(772,451	)		(851,687	)		(1,752,394	)
Short-term borrowings, net		(308,319	)		-			-			(219,032	)
Net controlled disbursement activity		(27,118	)		(19,129	)		(27,594	)		(36,400	)
Common stock dividend payments		(141,023	)		(123,965	)		(411,507	)		(367,751	)
Net cash used for financing activities		(580,449	)		(601,719	)		(1,048,843	)		(1,415,103	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(294,443	)		(211,243	)		(756,118	)		(545,743	)
Proceeds from asset sales		-			1,662			61,207			213,109
Proceeds from certificates of deposit		-			277,763			-			277,763
Nonutility generation trust contributions		-			-			-			(50,614	)
Contributions to nuclear decommissioning trusts		(25,370	)		(25,370	)		(76,112	)		(76,112	)
Cash investments		(13,950	)		(7,316	)		21,171			19,640
Other		23,120			7,072			(26,706	)		(7,236	)
Net cash provided from (used for) investing activities		(310,643	)		42,568			(776,558	)		(169,193	)
Net change in cash and cash equivalents		90,064			(31,646	)		86,871			(46,083	)
Cash and cash equivalents at beginning of period		49,748			99,538			52,941			113,975
Cash and cash equivalents at end of period	$	139,812		$	67,892		$	139,812		$	67,892
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these
statements.

29

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of September 30, 2005, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(K) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 1, 2005

30

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

EXECUTIVE SUMMARY

Net income in the third quarter of 2005 was $332 million, or basic and diluted earnings of $1.01 per share of common stock, compared to net income of $299 million, or basic and diluted earnings of $0.91 per share of common stock for the third quarter of 2004. Net income in the first nine months of 2005 was $670 million, or basic earnings of $2.04 per share of common stock ($2.03 diluted) compared to $677 million in the first nine months of 2004, or basic earnings of $2.07 per share of common stock ($2.06 diluted). The following Non-GAAP Reconciliation displays the unusual items resulting in the difference between GAAP and non-GAAP earnings.

Reconciliation of non-GAAP to GAAP	2005						2004
	After-tax			Basic			After-tax			Basic
	Amount			Earnings			Amount			Earnings
Three Months Ended September 30,	(Millions)			Per Share			(Millions)			Per Share
Earnings Before Unusual Items (Non-GAAP)	$	342		$	1.04		$	319		$	0.97
Unusual Items:
Non-core asset sales gains/losses, net		-			-			(16	)		(0.05	)
JCP&L arbitration decision		(10	)		(0.03	)		-			-
Other		-			-			(4	)		(0.01	)
Net Income (GAAP)	$	332		$	1.01		$	299		$	0.91
Nine Months Ended September 30,
Earnings Before Unusual Items (Non-GAAP)	$	730		$	2.22		$	753		$	2.30
Unusual Items:
Non-core asset sales gains/losses, net		22			0.07			(23	)		(0.07	)
Davis-Besse impacts		-			-			(38	)		(0.12	)
EPA settlement		(14	)		(0.04	)		-			-
NRC fine		(3	)		(0.01	)		-			-
JCP&L rate settlement		16			0.05			-			-
JCP&L arbitration decision		(10	)		(0.03	)		-			-
Ohio tax write-off		(71	)		(0.22	)		-			-
Class-action lawsuit settlement		-			-			(11	)		(0.03	)
Other		-			-			(4	)		(0.01	)
Net Income (GAAP)	$	670		$	2.04		$	677		$	2.07

The Non-GAAP measure above, earnings before unusual items, is not calculated in accordance with GAAP because it excludes the impact of "unusual items." Unusual items reflect the impact on earnings of events that are not routine or for which management believes the financial impact will disappear or become immaterial within a near-term finite period. By removing the earnings effect of such issues that have been resolved or are expected to be resolved over the near term, management and investors can better measure FirstEnergy’s business and earnings potential. In particular, the non-core asset sales item refers to a finite set of energy-related assets that have been previously disclosed as held for sale, a substantial portion of which has already been sold. In addition, as Davis-Besse restarted in 2004, further impacts from its extended outage are not expected. Similarly, further litigation settlements similar to the class action settlements in 2004 are not reasonably expected over the near term. Furthermore, FirstEnergy believes presenting normalized earnings calculated in this manner provides useful information to investors in evaluating the ongoing results of its businesses, over the longer term and assists investors in comparing FirstEnergy’s operating performance to the operating performance of others in the energy sector.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter of 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

31

On September 20, 2005, FirstEnergy raised its quarterly dividend to $0.43 per share of outstanding common stock - 4.2% higher than the previous quarterly rate of $0.4125 per share. This action represents the second dividend payment increase this year. The dividend payment was last increased by 10% for the dividend paid on March 1, 2005. The new dividend is payable December 1, 2005 to shareholders of record on November 7, 2005. The Company’s dividend policy, established on November 30, 2004, targets sustainable annual dividend increases after 2005, generally reflecting an annual growth rate of 4% to 5%, and an earnings payout ratio generally within the range of 50% to 60%. The Board of Directors will continue to review the Company's dividend policy regularly. The amount and timing of all dividend payments are subject to the Board's consideration of business conditions, results of operations, financial condition and other factors.

On September 9, 2005, FirstEnergy filed on behalf of the Ohio Companies an RCP that, if approved by the PUCO, would essentially maintain current electricity prices through 2008. The RCP was developed as a result of concerns about potential impacts to customer rates due to rising fuel prices and other factors. A stipulated agreement in support of the plan has been signed by the cities of Cleveland and Akron, along with the Industrial Energy Users - Ohio and the Ohio Energy Group. Also, the Mayor of the City of Parma has agreed to support the stipulation. The Parma City Council passed a resolution in support of the RCP plan on September 19, 2005.

During the third quarter of 2005, several FirstEnergy operating companies reached employment agreements with various local unions. On July 13, 2005, UWUA 118 and 126 - representing 445 workers - ratified an agreement with OE. On August 17, 2005, UWUA Local 180 - representing 170 workers - ratified an agreement with Penelec. On August 25, 2005, IBEW Local 1194 - representing 240 employees - ratified an agreement with OE. The collective bargaining agreement with IBEW Local 29 representing approximately 450 workers at the Beaver Valley Nuclear Power Station expired pursuant to its terms on September 30, 2005. The parties are currently negotiating a new agreement.

On September 14, 2005, FENOC announced that it would pay the $5.45 million fine proposed in April 2005 by the NRC related to the reactor head issue at the Davis-Besse Nuclear Power Station. FirstEnergy accrued $2.0 million of the fine in 2004 and the remaining amount in the first quarter of 2005. In a letter to the NRC, the Company noted that paying the fine brings regulatory closure to this issue and enables it to continue focusing on safe, reliable plant operations. The letter also reiterated that FENOC acknowledges full responsibility for the significant performance deficiencies that led to the reactor head issue, and that the NRC has indicated that the cited violations regarding the past plant operations do not represent current performance.

FirstEnergy announced on September 22, 2005, that FGCO plans to install an Electro-Catalytic Oxidation (ECO) system on the 215-megawatt Unit 4 of its Bay Shore Plant in Oregon, Ohio. ECO is a multipollutant-control technology for coal-based electric utility plants that was developed by Powerspan Corp., a clean energy technology company in which FirstEnergy has a minority ownership interest.

ECO is currently being demonstrated at FGCO's R. E. Burger Plant, and has proven effective in reducing NO_x, SO₂, mercury, acid gases, and fine particulates (soot). The ECO process also produces a highly marketable ammonium sulfate fertilizer co-product, currently being sold to the fertilizer market.

FGCO expects design engineering of the Bay Shore ECO system to commence in the first quarter of 2006, and estimates the overall cost of the system, including a fertilizer processing plant, to be approximately $100 million.

FIRSTENERGY’S BUSINESS

FirstEnergy is a registered public utility holding company headquartered in Akron, Ohio that operates primarily through two core business segments.

· Regulated Services transmits, distributes and sells electricity through eight utility operating companies that collectively comprise the nation’s fifth largest investor-owned electric system, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. This business segment primarily derives its revenue from the delivery of electricity, including transition cost recovery.

32

· Power Supply ManagementServices supplies the electric power needs of end-use customers (principally in Ohio, Pennsylvania and New Jersey) through retail and wholesale arrangements, including sales to meet the PLR requirements of FirstEnergy’s Ohio Companies and Penn. This business segment operates FirstEnergy's generating facilities and purchases from the wholesale market to meet its sales obligations. Pursuant to an asset transfer on October 24, 2005, it now owns as well as operates FirstEnergy's fossil and hydroelectric generation facilities previously owned by the EUOC. It also purchases the entire output of the nuclear plants currently owned or leased by the EUOC. This business segment principally derives its revenues from electric generation sales.

Other operating segments provide a wide range of services, including heating, ventilation, air-conditioning, refrigeration, electrical and facility control systems, high-efficiency electrotechnologies and telecommunication services. FirstEnergy is in the process of divesting non-core businesses. See Note 6 to the consolidated financial statements. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable segments”.

FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

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

On October 24, 2005, the Ohio Companies and Penn completed the intra-system transfer of non-nuclear generation assets to FGCO. Prior to the transfer, FGCO, as lessee under a Master Facility Lease with the Ohio Companies and Penn, leased, operated and maintained the non-nuclear generation assets that it now owns. The asset transfers were consummated pursuant to the May 13 and May 18, 2005 agreements and FGCO's purchase option under the Master Facility Lease.

As contemplated by the agreements entered into in May 2005, the Ohio Companies and Penn intend to transfer their respective interests in the nuclear generation assets to NGC through, in the case of OE and Penn, a spin-off by way of dividend and, in the case of CEI and TE, a sale at net book value. FENOC currently operates and maintains the nuclear generation assets to be transferred. FirstEnergy currently expects to complete the nuclear asset transfers in the fourth quarter of 2005, subject to the receipt of required regulatory approvals.

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

See Note 17 for disclosure of the assets held for sale by the Ohio Companies and Penn as of September 30, 2005.

33

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 16 to the consolidated financial statements. The FSG business segment is included in “Other and Reconciling Adjustments” in this discussion due to its immaterial impact on current period financial results, but is presented separately in segment information provided in Note 16 to the consolidated financial statements. Net income (loss) by major business segment is as follows:

	Three Months Ended									Nine Months Ended
	September 30,						Increase			September 30,						Increase
	2005			2004			(Decrease)			2005			2004			(Decrease)
	(In millions, except per share amounts)
Net Income (Loss)
By Business Segment:
Regulated Services	$	366		$	315		$	51		$	856		$	761		$	95
Power supply management services		10			44			(34	)		(15	)		79			(94	)
Other and reconciling adjustments*		(44	)		(60	)		16			(171	)		(163	)		(8	)
Total	$	332		$	299		$	33		$	670		$	677		$	(7	)
Basic Earnings Per Share:
Income before discontinued operations	$	1.01		$	0.90		$	0.11		$	1.99		$	2.05		$	(0.06	)
Discontinued operations		--			0.01			(0.01	)		0.05			0.02			0.03
Net earnings per basic share	$	1.01		$	0.91		$	0.10		$	2.04		$	2.07		$	(0.03	)
Diluted Earnings Per Share:
Income before discontinued operations	$	1.01		$	0.90		$	0.11		$	1.98		$	2.04		$	(0.06	)
Discontinued operations		--			0.01			(0.01	)		0.05			0.02			0.03
Net earnings per diluted share	$	1.01		$	0.91		$	0.10		$	2.03		$	2.06		$	(0.03	)
* Represents other operating segments and reconciling items including interest expense on holding company debt and corporate support services revenues and expenses.

Net income in the regulated services segment for the three months and nine months ended September 30, 2005 increased due to additional customer demand. However, net income for the power supply management services segment was lower in both the three months and nine months ended September 30, 2005 compared to the same periods in 2004, as a result of higher costs for fossil fuel, purchased power (excluding 2004 PJM transactions on a gross basis) and nuclear refueling costs which, in aggregate, more than offset the revenue from increased electric generation sales.

A decrease in wholesale electric revenues and purchased power costs in the 2005 periods compared to the corresponding periods last year primarily resulted from FES recording PJM sales and purchased power transactions on an hourly net position basis beginning in the first quarter of 2005 compared with recording each discrete transaction (on a gross basis) in 2004 (See Note 2 - Accounting for Wholesale Energy Transactions). This change had no impact on earnings and resulted from the dedication of FirstEnergy’s Beaver Valley Power Station to PJM in January 2005. Wholesale electric revenues and purchased power costs in the three months and nine months ended September 30, 2004 each included additional amounts of $264 million and $828 million, respectively, due to recording those transactions on a gross basis.

Excluding the effect of recording the wholesale electric revenue transactions in PJM on a gross basis in 2004, total operating revenues in the three months and nine months ended September 30, 2005 increased 14.9% and 8.7%, respectively, reflecting in large part warmer than normal temperatures during the summer of 2005 compared to 2004.

 

34

Summary of Results of Operations - Third Quarter of 2005 compared with the Third Quarter of 2004

Financial results for FirstEnergy and its major business segments in the third quarter of 2005 and 2004 were as follows:

				Power
				Supply		Other and
3rd Quarter 2005	Regulated			Management		Reconciling			FirstEnergy
Quarterly Financial Results	Services			Services		Adjustments			Consolidated
	(In millions)
Revenue:
External
Electric	$	1,432		$	1,684	$	--		$	3,116
Other		244			28		199			471
Internal		79			--		(79	)		--
Total Revenues		1,755			1,712		120			3,587
Expenses:
Fuel and purchased power		--			1,287		--			1,287
Other operating		511			364		118			993
Provision for depreciation		137			9		7			153
Amortization of regulatory assets		364			--		--			364
Deferral of new regulatory assets		(124	)		--		--			(124	)
General taxes		159			24		5			188
Total Expenses		1,047			1,684		130			2,861
Net interest charges		88			11		59			158
Income taxes		254			7		(24	)		237
Income before discontinued operations		366			10		(45	)		331
Discontinued operations		--			--		1			1
Net Income (Loss)	$	366		$	10	$	(44	)	$	332

				Power
				Supply		Other and
3rd Quarter 2004	Regulated			Management		Reconciling			FirstEnergy
Quarterly Financial Results	Services			Services		Adjustments			Consolidated
	(In millions)
Revenue:
External
Electric	$	1,309		$	1,721	$	--		$	3,030
Other		172			35		148			355
Internal		80			--		(80	)		--
Total Revenues		1,561			1,756		68			3,385
Expenses:
Fuel and purchased power		--			1,285		--			1,285
Other operating		414			356		99			869
Provision for depreciation		129			9		9			147
Amortization of regulatory assets		324			--		--			324
Deferral of new regulatory assets		(79	)		--		--			(79	)
General taxes		150			23		5			178
Total Expenses		938			1,673		113			2,724
Net interest charges		82			9		60			151
Income taxes		226			30		(42	)		214
Income before discontinued operations		315			44		(63	)		296
Discontinued operations		--			--		3			3
Net Income (Loss)	$	315		$	44	$	(60	)	$	299

35

Change Between				Power
3rd Quarter 2005 and 2004				Supply			Other and
Quarterly Financial Results	Regulated			Management			Reconciling			FirstEnergy
Increase (Decrease)	Services			Services			Adjustments(1)			Consolidated
	(In millions)
Revenue:
External
Electric	$	123		$	(37	)	$	--		$	86
Other		72			(7	)		51			116
Internal		(1	)		--			1			--
Total Revenues		194			(44	)		52			202
Expenses:
Fuel and purchased power		--			2			--			2
Other operating		97			8			19			124
Provision for depreciation		8			--			(2	)		6
Amortization of regulatory assets		40			--			--			40
Deferral of new regulatory assets		(45	)		--			--			(45	)
General taxes		9			1			--			10
Total Expenses		109			11			17			137
Net interest charges		6			2			(1	)		7
Income taxes		28			(23	)		18			23
Income before discontinued operations		51			(34	)		18			35
Discontinued operations		--			--			(2	)		(2	)
Net Income (Loss)	$	51		$	(34	)	$	16		$	33
(1) The impact of the new Ohio tax legislation is included with FirstEnergy’s other operating segments and reconciling adjustments.

Regulated Services - Third Quarter 2005 Compared with Third Quarter 2004

Net income increased $51 million, or 16% to $366 million, in the third quarter of 2005 compared to $315 million in the third quarter of 2004, as a result of increased customer usage.

Revenues -

Total revenues increased by $194 million in the third quarter 2005 compared to the same period in 2004, resulting from the following sources:

	Three Months Ended
	September 30,
Revenues by Type of Service	2005		2004		Increase
	(In millions)
Distribution services	$	1,432	$	1,309	$	123
Transmission services		117		81		36
Lease revenue from affiliates		79		79		--
Other		127		92		35
Total Revenues	$	1,755	$	1,561	$	194

Changes in distribution deliveries by customer class in the third quarter of 2005 compared with the third quarter of 2004 are summarized in the following table:

Electric Distribution Deliveries	Increase
Residential		15.4	%
Commercial		7.8	%
Industrial		5.2	%
Total Distribution Deliveries		9.6	%

36

Increased consumption offset in part by lower composite prices to customers resulted in higher distribution delivery revenue. The following table summarizes major factors contributing to the $123 million increase in distribution services revenue in the third quarter of 2005:

	Increase
Sources of Change in Distribution Revenues	(Decrease)
	(In millions)
Changes in customer usage	$	135
Changes in prices:
Rate changes --
Ohio shopping credits		(11	)
JCP&L rate settlements		21
Billing component reallocations		(22	)
Net Increase in Distribution Revenues	$	123

Distribution revenues benefited from warmer summer temperatures in the third quarter of 2005, compared to 2004, that increased the air-conditioning load of residential and commercial customers. While industrial deliveries also increased, that impact was more than offset by lower unit prices to that sector. Higher base rates from JCP&L's stipulated rate settlements were more than offset by additional credits provided to customers under the Ohio transition plan and a reallocation of billing components primarily related to special contracts. Shopping credits do not affect current period earnings due to deferral of the incentives for future recovery from customers.

Transmission revenues increased $36 million in the third quarter of 2005 from the same period last year due in part to increased loads due to warmer weather and higher transmission usage prices. Other revenues increased $35 million primarily due to higher gains realized on nuclear decommissioning trust investments.

Expenses-

The increase in total revenues discussed above was partially offset by the following increases in total expenses:

·Other operating expenses increased by $97 million in the third quarter of 2005 compared to the same

     period in 2004 primarily due to increased transmission expenses resulting in part from increased loads

     and higher transmission system usage charges;

·Increased provision for depreciation of $8 million that resulted from property additions and increased

     leasehold improvement amortization;

·     Additional amortization of regulatory assets of $40 million, principally Ohio transition costs;

·         Higher general taxes of $9 million resulting from increased EUOC sales which increased the Ohio KWH         tax and the Pennsylvania gross receipts tax;

·      Increased interest charges of $6 million primarily due to the absence of $11 million in interest rate swap

     savings achieved in the third quarter of 2004; and

·      Higher income taxes of $28 million due to increased taxable income.

Partially offsetting those increases was the effect of additional deferred regulatory assets of $45 million, primarily due to the PUCO-approved deferral of MISO administrative costs, shopping incentives and related interest.

Power Supply Management Services - Third Quarter 2005 Compared with Third Quarter 2004

Net income for this segment decreased $34 million to $10 million in the third quarter of 2005 from $44 million in the same period last year, due to a decrease in the gross generation margin and higher operating costs.

37

Revenues -

Excluding the effect of the change in recording PJM wholesale transactions on a gross basis in 2004 ($264 million), electric generation revenues increased $227 million in the third quarter of 2005 compared to the same period of 2004 primarily as a result of a 5.2% increase in KWH sales due to higher retail customer usage and a 21% rise in unit prices in the wholesale market. The increase in retail sales reduced energy available for sale to the wholesale market, resulting in a 9% reduction in wholesale sales (before the PJM adjustment).

The change in reported segment revenues resulted from the following:

	Three Months Ended
	September 30,				Increase
Revenues by Type of Service	2005		2004		(Decrease)
	(In millions)
Electric generation sales:
Retail	$	1,254	$	1,069	$	185
Wholesale		430		388		42
Total electric generation sales		1,684		1,457		227
Transmission		16		20		(4	)
Other		12		15		(3	)
Total		1,712		1,492		220
PJM gross transactions		--		264		(264	)
Total Revenues	$	1,712	$	1,756	$	(44	)

The following table summarizes the price and volume factors contributing to increased sales to retail and wholesale customers.

	Increase
Source of Change in Electric Generation Sales	(Decrease)
	(In millions)
Retail:
Effect of 9.9% increase in customer usage	$	113
Change in prices		72
		185
Wholesale:
Effect of 8.7% reduction in customer usage(1)		(41	)
Change in prices		83
		42
Net Increase in Electric Generation Sales	$	227
(1) Decrease of 46.4% including the effect of the PJM revision.

38

Expenses -

Excluding the effect of $264 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased in aggregate by $254 million in the third quarter of 2005 compared to the same period of 2004. Higher fuel and purchased power costs contributed $2 million ($266 million, net of $264 million PJM effect) of the increase, resulting from higher fuel costs of $121 million and increased purchased power costs of $145 million. Factors contributing to the higher costs are summarized in the following table:

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	(In millions)
Fuel:
Change due to increased unit costs	$	92
Change due to volume consumed		29
		121
Purchased Power:
Change due to increased unit costs		130
Change due to volume purchased		(16	)
Reduction in costs deferred		31
		145
PJM gross transactions		(264	)
Net Increase in Fuel and Purchased Power Costs	$	2

FirstEnergy’s generation fleet established an output record of 21.7 billion KWH in the third quarter of 2005. As a result, increased coal consumption and the related cost of emission allowances combined to increase fossil fuel expense. Higher coal costs resulted from increased market purchases, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to higher costs associated with the increase in generation from the fossil units relative to nuclear generation. Fossil generation output increased 16% in the third quarter of 2005 while nuclear output increased by 1%, compared to the same period in 2004.

Other operating costs increased $8 million in the third quarter of 2005 compared to the same period of 2004. This increase resulted from higher transmission costs due primarily to increased loads and higher transmission system usage charges. The higher costs this year were offset in part by lower non-fuel nuclear costs resulting from expenses incurred late in the third quarter of 2004 in preparation for the fourth quarter of 2004 Beaver Valley Unit 1 refueling outage.

Offsetting higher operating costs were lower income taxes of $23 million due to lower taxable income.

Other - Third Quarter 2005 Compared with Third Quarter 2004

FirstEnergy’s financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a net increase of $16 million in net income in the third quarter of 2005 compared to the same quarter of 2004. The increase was primarily due to the absence this year of losses recognized in 2004 on the sale of securities and impairment of several partnership investments.

39

Summary of Results of Operations - Nine Months ended September 30, 2005 compared with the Nine Months ended September 30, 2004

Financial results for FirstEnergy and its major business segments for the nine months ended September 30, 2005 and 2004 were as follows:

				Power
				Supply			Other and
Nine Months ended September 30, 2005	Regulated			Management			Reconciling			FirstEnergy
Financial Results	Services			Services			Adjustments			Consolidated
	(In millions)
Revenue:
External
Electric	$	3,759		$	4,273		$	-		$	8,032
Other		607			73			565			1,245
Internal		237			-			(237	)		-
Total Revenues		4,603			4,346			328			9,277
Expenses:
Fuel and purchased power		-			3,115			-			3,115
Other operating		1,336			1,132			290			2,758
Provision for depreciation		397			26			21			444
Amortization of regulatory assets		982			-			-			982
Deferral of new regulatory assets		(303	)		-			-			(303	)
General taxes		455			69			17			541
Total Expenses		2,867			4,342			328			7,537
Net interest charges		285			29			175			489
Income taxes		595			(10	)		14			599
Income before discontinued operations		856			(15	)		(189	)		652
Discontinued operations		-			-			18			18
Net Income (Loss)	$	856		$	(15	)	$	(171	)	$	670

				Power
				Supply		Other and
Nine Months ended September 30, 2004	Regulated			Management		Reconciling			FirstEnergy
Financial Results	Services			Services		Adjustments			Consolidated
	(In millions)
Revenue:
External
Electric	$	3,588		$	4,742	$	--		$	8,330
Other		461			86		484			1,031
Internal		239			--		(239	)		--
Total Revenues		4,288			4,828		245			9,361
Expenses:
Fuel and purchased power		--			3,515		--			3,515
Other operating		1,155			1,058		288			2,501
Provision for depreciation		384			26		29			439
Amortization of regulatory assets		905			--		--			905
Deferral of new regulatory assets		(192	)		--		--			(192	)
General taxes		433			65		16			514
Total Expenses		2,685			4,664		333			7,682
Net interest charges		301			30		171			502
Income taxes		541			55		(90	)		506
Income before discontinued operations		761			79		(169	)		671
Discontinued operations		--			--		6			6
Net Income (Loss)	$	761		$	79	$	(163	)	$	677

40

				Power
Change Between Nine Months ended				Supply			Other and
September 30, 2005 vs. 2004	Regulated			Management			Reconciling			FirstEnergy
Financial Results	Services			Services			Adjustments(1)			Consolidated
Increase (Decrease)	(In millions)
Revenue:
External
Electric	$	171		$	(469	)	$	-		$	(298	)
Other		146			(13	)		81			214
Internal		(2	)		-			2			-
Total Revenues		315			(482	)		83			(84	)
Expenses:
Fuel and purchased power		-			(400	)		-			(400	)
Other operating		181			74			2			257
Provision for depreciation		13			-			(8	)		5
Amortization of regulatory assets		77			-			-			77
Deferral of new regulatory assets		(111	)		-			-			(111	)
General taxes		22			4			1			27
Total Expenses		182			(322	)		(5	)		(145	)
Net interest charges		(16	)		(1	)		4			(13	)
Income taxes		54			(65	)		104			93
Income before discontinued operations		95			(94	)		(20	)		(19	)
Discontinued operations		-			-			12			12
Net Income (Loss)	$	95		$	(94	)	$	(8	)	$	(7	)
(1) The impact of the new Ohio tax legislation is included with FirstEnergy's other operating segments and reconciling adjustments.

Regulated Services - Nine Months ended September 30, 2005 compared with Nine Months ended September 30, 2004

Net income increased $95 million to $856 million in the nine months ended September 30, 2005, from $761 million in the same period of 2004, due to increased revenues partially offset by higher expenses and taxes.

Revenues -

The increase in total revenues resulted from the following:

	Nine Months Ended
	September 30,				Increase
Revenues by Type of Service	2005		2004		(Decrease)
	(In millions)
Distribution services	$	3,759	$	3,588	$	171
Transmission services		314		210		104
Lease revenue from affiliates		237		239		(2	)
Other		293		251		42
Total Revenues	$	4,603	$	4,288	$	315

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

Electric Distribution Deliveries	Increase
Residential		7.9	%
Commercial		5.2	%
Industrial		1.8	%
Total Distribution Deliveries		5.0	%

41

Increased customer consumption offset in part by lower prices resulted in higher distribution delivery revenues. The following table summarizes major factors contributing to the $171 million increase in distribution services revenue in the first nine months of 2005:

	Increase
Sources of Change in Distribution Revenues	(Decrease)
	(In millions)
Changes in customer usage	$	210
Changes in prices:
Rate changes -
Ohio shopping credits		(33	)
JCP&L rate settlements		28
Billing component reallocation		(34	)
Net Increase in Distribution Revenues	$	171

Distribution revenues benefited from warmer temperatures in the summer months of 2005 compared to 2004 that increased the air-conditioning load of residential and commercial customers. The effect of higher base rates for JCP&L's stipulated rate settlements in 2005 were more than offset by additional credits provided to customers under the Ohio transition plan and a reallocation of billing components primarily related to special contracts. Shopping credits do not affect current period earnings due to deferral of the incentives for future recovery from customers. While industrial deliveries also increased they were more than offset by lower unit prices.

Transmission revenues increased $104 million in the nine months ended September 30, 2005 compared to the same period last year due in part to the June 2004 amended power supply agreement with FES and increased loads due to warmer summer weather and higher transmission usage prices. Other revenues increased $42 million primarily due to higher gains realized on nuclear decommissioning trust investments.

Expenses-

Total operating expenses, net of interest charges and income taxes increased in aggregate by $220 million in the nine months ended September 30, 2005 compared to the same period in 2004 due to the following:

 · Other operating expenses increased $181 million principally due to higher transmission expenses resulting from an amended power supply agreement with FES, increased loads, and higher transmission system usage charges;

 · Provision for depreciation increased $13 million reflecting the effect of property additions, additional costs for decommissioning the Saxton nuclear unit and increased leasehold improvement amortization, reflecting shorter lives associated with capital additions for leased generating plants of the Ohio Companies to correspond to the remaining lease terms;

 · Additional amortization of regulatory assets of $77 million, principally Ohio transition costs;

 ·    Higher general taxes of $22 million resulting from increased EUOC sales which increased the Ohio KWH    tax and the Pennsylvania gross receipts tax and the absence in 2005 of Pennsylvania property tax    refunds recognized in 2004; and

 · Higher income taxes of $54 million due to increased taxable income.

The following partially offset these higher costs:

 · Additional deferrals of regulatory assets of $111 million, stemming from the deferral of PUCO-approved MISO administrative costs, JCP&L reliability improvements, shopping incentive credits and relat interest on those deferrals (see Note 14 - Regulatory Matters - Transmission, New Jersey); and

 · Lower interest charges of $16 million resulting from debt and preferred stock redemptions and refinancings.  

42

Power Supply Management Services - Nine Months ended September 30, 2005 compared with the Nine Months ended September 30, 2004

The net loss for this segment was $15 million for the nine months ended September 30, 2005 compared to net income of $79 million in the same period last year. A reduction in the gross generation margin, higher nuclear operating costs and amounts recognized for fines, penalties and obligations associated with proceedings involving the W.H. Sammis Plant and the Davis-Besse Nuclear Power Station contributed to the 2005 net loss.

Revenues -

Excluding the effect of the change in recording PJM wholesale transactions on a gross basis in 2004 ($828 million), electric generation revenues increased $359 million in the nine months ended September 30, 2005 compared to the same period of 2004 as a result of a 2.4% increase in KWH sales and higher unit prices.

The change in reported segment revenues resulted from the following:

	Nine Months Ended
	September 30,				Increase
Revenues by Type of Service	2005		2004		(Decrease)
	(In millions)
Electric generation sales:
Retail	$	3,223	$	2,933	$	290
Wholesale(1)		1,050		981		69
Total Electric Generation Sales		4,273		3,914		359
Transmission		41		57		(16	)
Other		32		29		3
Total		4,346		4,000		346
PJM gross transactions		-		828		(828	)
Total Revenues	$	4,346	$	4,828	$	(482	)
(1)Excluding 2004 PJM effect of gross transactions.

Higher electric generation sales resulted from increased unit prices and increased retail customer usage. The following table summarizes the price and volume factors contributing to the increased sales to retail and wholesale customers.

Source of Change in Electric Generation Sales
	(In millions)
Retail:
Effect of 4.5% increase in customer usage	$	140
Change in prices		150
		290
Wholesale:
Effect of 4.4% reduction in customer usage(1)		(48	)
Change in prices		117
		69
Net Increase in Electric Generation Sales	$	359
(1) Decrease of 47.3% including the effect of the PJM revision.

43

Expenses -

Excluding the effect of $828 million of PJM purchased power costs recorded on a gross basis in 2004, total operating expenses, net interest charges and income taxes increased in aggregate by $440 million in the nine months ended September 30, 2005 compared to the same period of 2004. Higher fuel and purchased power costs contributed $428 million of the increase, resulting from higher fuel costs of $245 million and increased purchased power costs of $183 million. Factors contributing to the higher costs are summarized in the following table:

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	(In millions)
Fuel:
Change due to unit costs	$	212
Change due to volume consumed		33
		245
Purchased Power:
Change due to unit costs		255
Change due to volume purchased		(53	)
Increase in deferred costs		(19	)
		183
PJM Gross Transactions		(828	)
Net Decrease in Fuel and Purchased Power Costs	$	(400	)

FirstEnergy’s generation fleet established an output record of 59.5 billion KWH for the nine months ended September 30, 2005. Higher coal costs resulted from increased consumption, market adjustment provisions in coal contracts reflecting higher market prices and increased transportation costs. Emission allowance costs increased primarily from higher prices. To a lesser extent, fuel expense increased due to the mix of fossil versus nuclear generation resulting from the nuclear refueling outages in the first nine months of 2005 following a year with no scheduled nuclear refueling outages and improved performance of fossil generating units. Fossil generation increased 12% in the nine months ended September 30, 2005 while nuclear generation decreased by 8% compared to the same period of 2004.

Other operating costs increased $74 million in the nine months ended September 30, 2005 compared to the same period of 2004. This increase resulted from higher non-fuel nuclear costs. The increase in non-fuel nuclear costs resulted from 2005 refueling outages at Perry Unit 1 (including an unplanned extension) and Beaver Valley Unit 2 and a scheduled 23-day mid-cycle inspection outage at the Davis-Besse nuclear plant. There were no scheduled nuclear refueling outages in the first nine months of 2004. Also included in other operating costs for 2005 were the EPA settlement loss and NRC fine described above. Offsetting the higher other operating costs were reduced non-fuel fossil generation expense of $17 million due to reduced maintenance outages in 2005 and lower transmission costs of $15 million, due to an amended power supply agreement with Met-Ed and Penelec.

Partially offsetting the increase in other operating costs were lower income taxes of $65 million due to lower taxable income.

Other - Nine Months ended September 30, 2005 compared with the Nine Months ended September 30, 2004

FirstEnergy’s financial results from other operating segments and reconciling adjustments, including interest expense on holding company debt and corporate support services revenues and expenses and the impacts of the new Ohio tax legislation (discussed below) resulted in a decrease in FirstEnergy’s net income in the nine months ended September 30, 2005 compared to the same period of 2004. The decrease primarily reflected the effect of the new Ohio tax legislation partially offset by the effect of discontinued operations, which included an after-tax net gain of $17 million in 2005 (see Note 6). The following table summarizes the sources of income from discontinued operations:

	Nine Months Ended
	September 30,				Increase
	2005		2004		(Decrease)
	(In millions)
Discontinued operations (net of tax)
Gain on sale:
Retail gas business	$	5	$	-	$	5
FSG and MYR Subsidiaries		12		-		12
Reclassification of operating income		2		6		(4	)
Total	$	19	$	6	$	13

44

On June 30, 2005, the State of Ohio enacted new tax legislation that created a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and the personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the nine months ended September 30, 2005 was an additional tax expense of approximately $72 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $8 million in the nine months ended September 30, 2005. See Note 12 to the consolidated financial statements.

Postretirement Benefits

Postretirement benefits expense decreased by $17 million in the third quarter of 2005 and $54 million in the nine months ended September 30, 2005 compared to the corresponding periods of 2004. Pension costs represent most of the reduction due to a $500 million voluntary contribution made in 2004 and an increase in the market value of plan assets during 2004. The following table summarizes the net pension and OPEB expense (excluding amounts capitalized) for the three months and nine months ended September 30, 2005 and 2004.

	Three Months Ended							Nine Months Ended
Postretirement	September 30,				Increase			September 30,				Increase
Benefits Expense *	2005		2004		(Decrease)			2005		2004		(Decrease)
	(In millions)
Pension	$	8	$	21	$	(13	)	$	24	$	64	$	(40	)
OPEB		18		22		(4	)		54		68		(14	)
Total	$	26	$	43	$	(17	)	$	78	$	132	$	(54	)
* Excludes the capitalized portion of postretirement benefits costs (see Note 10 for total costs).

The decrease in pension and OPEB expenses are included in various cost categories and have contributed to other cost reductions discussed above.

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy’s cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing FirstEnergy’s net debt and preferred stock outstanding. Borrowing capacity under credit facilities is available to manage working capital requirements.

Changes in Cash Position

The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $2.0 billion of short-term financing under a revolving credit facility, subject to short-term debt limitations under current regulatory approvals of $1.5 billion and to outstanding borrowings by subsidiaries of FirstEnergy who are also parties to such facility. In the third quarter of 2005, FirstEnergy received $306 million of cash dividends from its subsidiaries and paid $141 million in cash dividends to its common shareholders - in the first nine months of 2005, it received and paid $846 million and $412 million, respectively. There are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries.

As of September 30, 2005, FirstEnergy had $140 million of cash and cash equivalents ($3 million restricted as an indemnity reserve) compared with $53 million ($3 million restricted as an indemnity reserve) as of December 31, 2004. The major sources for changes in these balances are summarized below.

45

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its regulated and power supply businesses (see “RESULTS OF OPERATIONS” above). Net cash provided by operating activities was $981 million and $528 million in the third quarter of 2005 and 2004, respectively, and $1.9 billion and $1.5 billion in the first nine months of 2005 and 2004, respectively, summarized as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Cash Flows	2005		2004			2005		2004
	(In millions)
Cash earnings (1)	$	777	$	545		$	1,642	$	1,427
Pension trust contribution(2)		-		(300	)		-		(300	)
Working capital and other		204		283			270		411
Total cash flows from operating activities	$	981	$	528		$	1,912	$	1,538
(1) Cash earnings are a non-GAAP measure (see reconciliation below).
(2) Pension trust contribution net of $200 million of income tax benefits.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	(In millions)
Net income (GAAP)	$	332		$	299		$	670		$	677
Non-cash charges (credits):
Provision for depreciation		153			147			444			439
Amortization of regulatory assets		364			324			982			905
Deferral of new regulatory assets		(124	)		(79	)		(303	)		(191	)
Nuclear fuel and lease amortization		26			27			63			72
Deferred purchased power and other costs		(39	)		(118	)		(231	)		(263	)
Deferred income taxes and investment tax credits(1)		(38	)		(163	)		24			(257	)
Deferred rents and lease market valuation liability		30			28			(71	)		(52	)
Accrued retirement benefit obligations		56			42			104			107
Income from discontinued operations		(1	)		(2	)		(18	)		(6	)
Other non-cash expenses		18			40			(22	)		(4	)
Cash earnings (non-GAAP)	$	777		$	545		$	1,642		$	1,427
(1) Excludes $200 million of deferred tax benefits from pension contribution in 2004.

In the three months and nine months ended September 30, 2005, cash earnings increased $232 million and $215 million, respectively. Both periods benefited from increased generation and distribution revenues aided by warmer summer temperatures that increased air conditioning load. In the third quarter of 2005 compared with the third quarter of 2004, cash provided from working capital decreased by $79 million, primarily due to changes in receivables. The use of cash for receivables resulted in part from the conversion of the CFC accounts receivable financing to an on-balance sheet transaction, which added $35 million of receivables to the balance sheet as of September 30, 2005. In the first nine months of 2005 compared to the first nine months of 2004, working capital changes provided $141 million less cash due in part to changes in receivables, materials and supplies, prepayments and accrued taxes, offset by accounts payable and the funds received as prepayment for electric usage, under the three-year Energy for Education II Program with the Ohio Schools Council.

46

Cash Flows From Financing Activities

In the third quarter and first nine months of 2005, cash used for financing activities was $580 million and $1.0 billion, respectively, compared to $602 million and $1.4 billion in the third quarter and first nine months of 2004, respectively. The following table summarizes security issuances and redemptions.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Securities Issued or Redeemed	2005			2004		2005		2004
	(In millions)
New issues
Pollution control notes	$	89		$	77	$	334	$	261
Secured notes		-			-		-		550
Long-term revolving credit		-			10		-		-
Unsecured notes		-			-		-		150
	$	89		$	87	$	334	$	961
Redemptions
First mortgage bonds	$	-		$	206	$	178	$	588
Pollution control notes		130			80		377		80
Secured notes		25			374		74		447
Long-term revolving credit		-			-		215		300
Unsecured notes		8			112		8		337
Preferred stock		30			1		170		1
	$	193		$	773	$	1,022	$	1,753
Short-term borrowings, net increase (decrease)	$	(308	)	$	228	$	77	$	(219	)

FirstEnergy had approximately $247 million of short-term indebtedness as of September 30, 2005 compared to approximately $170 million as of December 31, 2004. Available bank borrowings as of September 30, 2005 included the following:

Borrowing Capability	FirstEnergy			Penelec			Total
	(In millions)
Short-term credit(1)	$	2,020		$	-		$	2,020
Utilized		-			-			-
Letters of credit		(137	)		-			(137	)
Net		1,883			-			1,883
Short-term bank facilities(2)		-			75			75
Utilized		-			(75	)		(75	)
Net		-			-			-
Total unused borrowing capability	$	1,883		$	-		$	1,883
(1) A $2 billion revolving credit facility is available in various amounts to FirstEnergy and certain of its subsidiaries, including  Penelec. A $20 million uncommitted line of credit facility added in September 2005 is available to FirstEnergy only.
(2) Penelec bank facility terminated on October 7, 2005.

As of October 24, 2005, the Ohio Companies and Penn had the aggregate capability to issue approximately $3.8 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures following the recently completed intra-system transfer of fossil and hydroelectric generating plants (See Note 17). The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $690 million and $582 million, respectively, as of October 24, 2005. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of October 24, 2005, JCP&L had the capability to issue $673 million of additional senior notes upon the basis of FMB collateral. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.9 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil and hydroelectric generating plants will reduce the aggregate capability of OE, Penn, TE and JCP&L to issue preferred stock by approximately 10%. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock.

47

As of September 30, 2005, approximately $1 billion remained unused under an existing shelf registration statement, filed by FirstEnergy with the SEC in 2003, to support future securities issues. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units.

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

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

	Revolving		Regulatory and
	Credit Facility		Other Short-Term
Borrower	Sub-Limit		Debt Limitations1
	(In millions)
FirstEnergy	$	2,000	$	1,500
OE		500		500
Penn		50		51
CEI		250		500
TE		250		500
JCP&L		425		416
Met-Ed		250		300
Penelec		250		300
FES		-2		n/a
ATSI		-2		26

⁽¹⁾         As of September 30, 2005.

⁽²⁾ Borrowing sublimits for FES and ATSI may be increased to up to $250 million and $100 million, respectively, by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility.

The revolving credit facility, combined with an aggregate $550 million ($395 million unused as of September 30, 2005) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet short-term working capital requirements for FirstEnergy and its subsidiaries.

Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under existing credit facilities and accounts receivable financing facilities totaled $2.36 billion as of September 30, 2005.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 0.65 to 1.00. On October 3, 2005, FirstEnergy obtained a senior unsecured debt rating upgrade to BBB- by S&P removing the requirement under the revolving credit facility to maintain a fixed charge ratio of at least 2.00 to 1.00.

As of September 30, 2005, FirstEnergy and subsidiaries’ debt to total capitalization as defined under the revolving credit facility, were as follows:

	Debt
	To Total
Borrower	Capitalization
FirstEnergy		0.54 to 1.00
OE		0.39 to 1.00
Penn		0.32 to 1.00
CEI		0.57 to 1.00
TE		0.43 to 1.00
JCP&L		0.29 to 1.00
Met-Ed		0.38 to 1.00
Penelec		0.34 to 1.00

48

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

FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50% for the regulated companies’ money pool and 3.46% for the unregulated companies' money pool.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy’s and its EUOC’s securities ratings as of October 3, 2005. The ratings outlook from S&P and Fitch on all securities is stable. Moody’s outlook on all securities is Positive.

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

(1)Penn's only senior unsecured debt obligations are notes underlying pollution control revenue refunding bonds issued

     by the Ohio Air Quality Development Authority to which bonds this rating applies.

On July 1, 2005, TE redeemed all of its 1,200,000 outstanding shares of 7.00% Series A preferred stock at $25.00 per share, plus accrued dividends to the date of redemption. TE also repurchased $37 million of pollution control revenue bonds on September 1, 2005, with the intent to remarket them by the end of the first quarter of 2006.

49

Cash Flows From Investing Activities

Net cash flows used for investing activities resulted principally from property additions. Regulated services expenditures for property additions primarily include expenditures supporting the distribution of electricity. Capital expenditures by the power supply management services segment are principally generation-related. The following table summarizes the investment activities for the three months and nine months ended September 30, 2005 and 2004 by FirstEnergy’s regulated services, power supply management services and other segments:

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Three Months Ended September 30, 2005
Regulated services	$	(207	)	$	(17	)	$	2		$	(222	)
Power supply management services		(79	)		1			-			(78	)
Other		(1	)		-			1			-
Reconciling items		(7	)		(9	)		5			(11	)
Total	$	(294	)	$	(25	)	$	8		$	(311	)
Three Months Ended September 30, 2004
Regulated services	$	(157	)	$	242		$	(69	)	$	16
Power supply management services		(46	)		(11	)		-			(57	)
Other		(1	)		-			(2	)		(3	)
Reconciling items		(7	)		10			84			87
Total	$	(211	)	$	241		$	13		$	43

Summary of Cash Flows	Property
Used for Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Nine Months Ended September 30, 2005
Regulated services	$	(506	)	$	(13	)	$	(5	)	$	(524	)
Power supply management services		(226	)		-			-			(226	)
Other		(6	)		19			(18	)		(5	)
Reconciling items		(18	)		(9	)		5			(22	)
Total	$	(756	)	$	(3	)	$	(18	)	$	(777	)
Nine Months Ended September 30, 2004
Regulated services	$	(377	)	$	196		$	(76	)	$	(257	)
Power supply management services		(149	)		(14	)		-			(163	)
Other		(3	)		173			2			172
Reconciling items		(17	)		31			65			79
Total	$	(546	)	$	386		$	(9	)	$	(169	)

Net cash used for investing activities was $311 million in the third quarter of 2005 compared to $43 million of cash provided from investing activities in the same period of 2004. The change was primarily due to an $83 million increase in property additions and the absence in 2005 of $278 million in cash proceeds from certificates of deposit (released collateral) received in the third quarter of 2004. Net cash used for investing activities increased by $608 million in the first nine months of 2005 compared to the same period of 2004. The increase principally resulted from a $210 million increase in property additions, lower proceeds from the sale of assets of $152 million and the absence in 2005 of $278 million of cash proceeds from certificates of deposit (released collateral) received in 2004.

In the last quarter of 2005, capital requirements for property additions and capital leases are expected to be approximately $378 million. FirstEnergy and the Companies have additional requirements of approximately $312 million for maturing long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

FirstEnergy’s capital spending for the period 2005-2007 is expected to be about $3.5 billion (excluding nuclear fuel), of which $1.1 billion applies to 2005. Investments for additional nuclear fuel during the 2005-2007 periods are estimated to be approximately $285 million, of which approximately $59 million applies to 2005. During the same period, FirstEnergy’s nuclear fuel investments are expected to be reduced by approximately $282 million and $86 million respectively, as the nuclear fuel is consumed.

50

GUARANTEES AND OTHER ASSURANCES

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

As of September 30, 2005, the maximum potential future payments under outstanding guarantees and other assurances totaled $2.7 billion as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy guarantees of subsidiaries:
Energy and energy-related contracts (1)	$	785
Other (2)		503
		1,288
Surety bonds		307
Letters of credit (3)(4)		1,055
Total Guarantees and Other Assurances	$	2,650
(1)Issued for a one-year term, with a 10-day termination right by FirstEnergy.
(2)Issued for various terms.
(3)Includes $137 million issued for various terms under LOC capacity available
under FirstEnergy's revolving credit agreement and $299 million outstanding in
support of pollution control revenue bonds issued with various maturities.
(4)Includes approximately $194 million pledged in connection with the sale and
leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection
with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged
in connection with the sale and leaseback of Perry Unit 1 by OE.

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

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. The following table summarizes collateral provisions in effect as of September 30, 2005:

	Total		Collateral Paid				Remaining
Collateral Provisions	Exposure		Cash		LOC		Exposure
	(In millions)
Credit rating downgrade	$	445	$	213	$	18	$	214
Adverse event		77		-		5		72
Total	$	522	$	213	$	23	$	286

As a result of S&P's credit rating upgrade described above, $109 million of cash collateral was returned to FirstEnergy in October 2005.

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

51

FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has provided an LOC ($47 million as of September 30, 2005, which is included in the caption “Other” in the above table of Guarantees and Other Assurances), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $36 million on October 15, 2005.

OFF-BALANCE SHEET ARRANGEMENTS

FirstEnergy has obligations that are not included on its Consolidated Balance Sheet related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.3 billion as of September 30, 2005.

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

MARKET RISK INFORMATION

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

Commodity Price Risk

FirstEnergy is exposed to price risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel, emission allowance prices and energy transmission. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes and, to a much lesser extent, for trading purposes. All derivatives that fall within the scope of SFAS 133 must be recorded at their fair market value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchases and normal sales exception under SFAS 133 and are therefore excluded from the table below. Of those contracts not exempt from such treatment, most are non-trading contracts that do not qualify for hedge accounting treatment. The change in the fair value of commodity derivative contracts related to energy production during the third quarter and first nine months of 2005 is summarized in the following table:

	Three Months Ended									Nine Months Ended
Increase (Decrease) in the Fair Value	September 30, 2005									September 30, 2005
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 asset at beginning of period	$	55		$	(2	)	$	53		$	62		$	2		$	64
New contract when entered		-			-			-			-			-			-
Additions/change in value of existing contracts		(3	)		3			-			(4	)		5			1
Change in techniques/assumptions		-			-			-			-			-			-
Settled contracts		-			-			-			(7	)		-			(7	)
Sale of retail natural gas contracts		-			-			-			1			(6	)		(5	)
Outstanding net asset at end of period (1)	$	52		$	1		$	53		$	52		$	1		$	53
Non-commodity Net Assets at End of Period:
Interest rate swaps (2)		-			(10	)		(10	)		-			(10	)		(10	)
Net Assets - Derivative Contracts at End of Period	$	52		$	(9	)	$	43		$	52		$	(9	)	$	43
Impact of Changes in Commodity Derivative Contracts(3)
Income Statement effects (pre-tax)	$	(4	)	$	-		$	(4	)	$	(4	)	$	-		$	(4	)
Balance Sheet effects:
Other comprehensive income (pre-tax)	$	-		$	3		$	3		$	-		$	(1	)	$	(1	)
Regulatory liability	$	1		$	-		$	1		$	(6	)	$	-		$	(6	)
(1) Includes $55 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.
(2) Interest rate swaps are treated as cash flow or fair value hedges. (See Interest Rate Swap Agreements - Fair Value Hedges and Forward
Starting Swap Agreements - Cash Flow Hedges)
(3) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions.

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Derivatives are included on the Consolidated Balance Sheet as of September 30, 2005 as follows:

Balance Sheet Classification	Non-Hedge			Hedge			Total
	(In millions)
Current -
Other assets	$	-		$	39		$	39
Other liabilities		(1	)		(39	)		(40	)
Non-Current -
Other deferred charges		56			5			61
Other noncurrent liabilities		(3	)		(14	)		(17	)
Net assets	$	52		$	(9	)	$	43

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

Sources of Information -
Fair Value by Contract Year	2005 (1)			2006			2007			2008		2009		Thereafter		Total
	(In millions)
Prices actively quoted (2)	$	(3	)	$	(3	)	$	(2	)	$	-	$	-	$	-	$	(8	)
Other external sources (3)		19			7			10			-		-		-		36
Prices based on models		-			-			-			9		8		8		25
Total (4)	$	16		$	4		$	8		$	9	$	8	$	8	$	53
(1) For the last quarter of 2005.
(2) Exchange traded.
(3) Broker quote sheets.
(4) Includes $55 million in non-hedge commodity derivative contracts which are offset by a regulatory liability.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2005. Based on derivative contracts held as of September 30, 2005, an adverse 10% change in commodity prices would decrease net income by approximately $1 million for the next twelve months.

Interest Rate Swap Agreements - Fair Value Hedges

FirstEnergy utilizes fixed-to-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the third quarter of 2005, FirstEnergy executed no new fixed-for-floating interest rate swaps and unwound swaps with a total notional amount of $350 million (see Note 7). As of September 30, 2005, the debt underlying the $1.05 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.66%, which the swaps have effectively converted to a current weighted average variable interest rate of 5.23%.

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	September 30, 2005							December 31, 2004
	Notional		Maturity		Fair			Notional		Maturity		Fair
Interest Rate Swaps	Amount		Date		Value			Amount		Date		Value
	(Dollars in millions)
Fixed to Floating Rate	$	-		2006	$	-		$	200		2006	$	(1	)
(Fair value hedges)		100		2008		(3	)		100		2008		(1	)
		50		2010		-			100		2010		1
		50		2011		-			100		2011		2
		450		2013		-			400		2013		4
		-		2014		-			100		2014		2
		150		2015		(7	)		150		2015		(7	)
		150		2016		2			200		2016		1
		-		2018		-			150		2018		5
		-		2019		-			50		2019		2
		100		2031		(4	)		100		2031		(4	)
	$	1,050			$	(12	)	$	1,650			$	4

Forward Starting Swap Agreements - Cash Flow Hedges

During the third quarter, FirstEnergy entered into several forward starting swap agreements (forward swap) in order to hedge a portion of the consolidated interest rate risk associated with the planned issuance of fixed-rate, long-term debt securities for one or more of its consolidated entities in the fourth quarter of 2006. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of September 30, 2005, the forward swaps had a fair value of $2 million.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $1.038 billion and $951 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $104 million reduction in fair value as of September 30, 2005.

CREDIT RISK

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

FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of September 30, 2005, the largest credit concentration was with one party, currently rated investment grade that represented 8% of FirstEnergy’s total credit risk. Within its unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of September 30, 2005.

Outlook

State Regulatory Matters

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

· restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies;

· establishing or defining the PLR obligations to customers in the Companies' service areas;

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· providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

· itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges;

· continuing regulation of the Companies' transmission and distribution systems; and

· requiring corporate separation of regulated and unregulated business activities.

The EUOCs recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.

	September 30,		December 31,		Increase
Regulatory Assets*	2005		2004		(Decrease)
	(In millions)
OE	$	845	$	1,116	$	(271	)
CEI		889		959		(70	)
TE		310		375		(65	)
JCP&L		2,311		2,176		135
Met-Ed		572		693		(121	)
Penelec		99		200		(101	)
ATSI		20		13		7
Total	$	5,046	$	5,532	$	(486	)
*Penn had net regulatory liabilities of approximately $48 million and $18 million  included in Noncurrent Liabilities on the Consolidated Balance Sheets as of  September 30, 2005 and December 31, 2004, respectively.

Regulatory assets by source are as follows:

	September 30,			December 31,			Increase
Regulatory Assets by Source	2005			2004			(Decrease)
	(In millions)
Regulatory transition costs	$	4,169		$	4,889		$	(720	)
Customer shopping incentives		826			612			214
Customer receivables for future income taxes		289			246			43
Societal benefits charge		18			51			(33	)
Loss on reacquired debt		83			89			(6	)
Employee postretirement benefit costs		57			65			(8	)
Nuclear decommissioning, decontamination
and spent fuel disposal costs		(172	)		(169	)		(3	)
Asset removal costs		(366	)		(340	)		(26	)
Property losses and unrecovered plant costs		34			50			(16	)
MISO transmission costs		52			-			52
JCP&L reliability costs		26			-			26
Other		30			39			(9	)
Total	$	5,046		$	5,532		$	(486	)

Reliability Initiatives

FirstEnergy is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment. The FERC or other applicable government agencies and reliability coordinators, however, may take a different view as to recommended enhancements or may recommend additional enhancements in the future as the result of adoption of mandatory reliability standards pursuant to the Energy Policy Act of 2005 that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy's filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

 

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As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

The Energy Policy Act of 2005 provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On September 1, 2005, the FERC issued a Notice of Proposed Rulemaking to establish certification requirements for the ERO, as well as regional entities envisioned to assume monitoring and compliance responsibility for the new reliability standards. The FERC expects to adopt a final rule on or before February 2006 regarding certification requirements for the ERO and regional entities.

The NERC is expected to reorganize its structure to meet the FERC’s certification requirements for the ERO. Following adoption of the final rule, the NERC will be required to make a filing with the FERC to obtain certification as the ERO. The proposed rule also provides for regional reliability organizations designed to replace the current regional councils. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. The ECAR, Mid-Atlantic Area Council, and Mid-American Interconnected Network reliability councils have signed an MOU designed to consolidate their regions into a new regional reliability organization known as ReliabilityFirst Corporation. Their intent is to file and obtain certification under the final rule as a “regional entity”. All of FirstEnergy’s facilities would be located within the ReliabilityFirst region.

On a parallel path, the NERC is establishing working groups to develop reliability standards to be filed for approval with the FERC following the NERC’s certification as an ERO. These reliability standards are expected to build on the current NERC Version 0 reliability standards. It is expected that the proposed reliability standards will be filed with the FERC in early 2006.

The impact of this effort on FirstEnergy is unclear. FirstEnergy believes that it is in compliance with all current NERC reliability standards. However, it is expected that the FERC will adopt stricter reliability standards than those contained in the current NERC Version 0 standards. The financial impact of complying with the new standards cannot be determined at this time. However, the Energy Policy Act of 2005 requires that all prudent costs incurred to comply with the new reliability standards be recovered in rates.

See Note 14 to the consolidated financial statements for a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and Penn.

Ohio

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, the Ohio Companies filed an application with the PUCO to establish a GCAF rider under the RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to the Ohio Companies' retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.

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On September 9, 2005, the Ohio Companies filed an application with the PUCO that, if approved, would supplement their existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

· Maintain the existing level of base distribution rates through December 31, 2008 for OE and TE, and

 April 30, 2009 for CEI;

· Defer and capitalize certain distribution costs to be incurred during the period January 1, 2006

  through December 31, 2008, not to exceed $150 million in each of the three years;

· Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized

 costs will occur as of December 31, 2008 for OE and TE, and as of December 31, 2010 for CEI;

· Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $75 million for OE,

 $45 million for TE, and $85 million for CEI by accelerating the application of each respective

 company's accumulated cost of removal regulatory liability; and

· Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and

 2008, respectively, from all OE and TE distribution and transmission customers through a fuel

 recovery mechanism and OE, TE, and CEI may defer and capitalize increased fuel costs above the

 amount collected through the fuel recovery mechanism.

Under provisions of the RSP, the PUCO may require the Ohio Companies to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for the Ohio Companies in 2004 which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Pennsylvania

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to defer differences between NUG contract costs and current market prices. On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and neither company has yet implemented deferral accounting for these costs.

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On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania.

New Jersey

The 2003 NJBPU decision on JCP&L's base electric rate proceeding (Phase I order) disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The Phase I Order also provided for a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the Phase I Order, respectively. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the 2003 NJBPU order Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

· An annual increase in distribution revenues of $23 million, effective June 1, 2005, associated with the

 Phase I Order reconsideration;

· An annual increase in distribution revenues of $36 million, effective June 1, 2005, related to JCP&L's

 Phase II Petition;

· An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in

 anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred

 cost balance;

· An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

· A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in

 JCP&L's authorized return on common equity from 9.75% to 9.5% if the target is not met for two

 consecutive quarters. The authorized return on common equity would then be restored to 9.75% if the

 target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenue increase also reflects a three-year amortization of JCP&L's one-time service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with accelerated tree trimming and other reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of FirstEnergy common stock) in the second quarter of 2005.

JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order for the period June 1, 2005 through May 31, 2006. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On July 1, 2005, JCP&L filed its BGS procurement proposals for post transition year four. The auction is scheduled to take place in February 2006 for the annual supply period beginning June 1, 2006.

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

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Transmission

On December 30, 2004, the Ohio Companies filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $30 million per year; however, the Ohio Companies anticipate that this amount will increase. The Ohio Companies requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. The Ohio Companies reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by the Ohio Companies, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $61.2 million. This value includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, the Ohio Companies will file a modification to the rider which will determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for the Ohio Companies to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 31, 2004 was denied. The PUCO also authorized the Ohio Companies to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in a PUCO order issued on August 31, 2005 approving the stipulation referred to above. The OCC, OPAE and the Ohio Companies each filed applications for rehearing. The Ohio Companies sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied the Ohio Companies' and OCC’s applications and, at the request of the Ohio Companies, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On September 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

Environmental Matters

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

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FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulation 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) in all cases from the 2003 levels. The Companies’ Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be subject to the caps on SO₂ and NO_x emissions, whereas their New Jersey fossil-fired generation facilities will be subject to a cap on NO_x emissions only. 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 the Companies operate affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the "Clean Air Mercury Rule," which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of 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 Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. FirstEnergy's future cost of compliance with these regulations may be substantial.

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 is owned by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, was approved by the Court on July 11, 2005, requires OE and Penn to reduce NOx and SO₂ emission at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). As disclosed in FirstEnergy's Form 8-K dated August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $64 million (JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed - $0.1 million and other - $14.6 million) have been accrued through September 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name or as subrogees in the name of their insured. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. FirstEnergy accrued $2.0 million for a potential fine prior to 2005 and accrued the remaining liability for the proposed fine during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.

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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. FENOC operates the Perry Nuclear Power Plant, which currently is owned and/or leased by OE, CEI, TE and Penn (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant). On April 4, 2005, the NRC held a public forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" and met all cornerstone objectives although it remained under heightened NRC oversight since August 2004. During the public forum and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry 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. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

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

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005, hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of this award by filing a motion to vacate in Federal court in New Jersey on October 18, 2005. JCP&L recognized a liability for the potential $16.1 million award during the three months ended September 30, 2005.

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

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

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

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NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FSP No. FAS 13-1, "Accounting for Rental Costs Incurred during the Construction Period"

Issued in October 2005, FSP No. FAS 13-1 requires rental costs associated with ground or building operating leases that are incurred during a construction period to be recognized as rental expense. The effective date of the FSP guidance is the first reporting period beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP, and its impact on the financial statements.

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

In September 2005, the EITF reached a final consensus on Issue 04-13 concluding that two or more legally separate exchange transactions with the same counterparty should be combined and considered as a single arrangement for purposes of applying APB 29, when the transactions were entered into "in contemplation" of one another. If two transactions are combined and considered a single arrangement, the EITF reached a consensus that an exchange of inventory should be accounted for at fair value. Although electric power is not capable of being held in inventory, there is no substantive conceptual distinction between exchanges involving power and other storable inventory. Therefore, FirstEnergy will adopt this EITF effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. See Note 2 for an example of FirstEnergy's application of this Issue.

EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with FirstEnergy's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for FirstEnergy in the fourth quarter of 2005. FirstEnergy and the Companies are currently evaluating the effect this Interpretation will have on their financial statements.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. FirstEnergy and the Companies will adopt this Statement effective January 1, 2006.

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SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for FirstEnergy. This FSP is not expected to have a material impact on FirstEnergy's financial statements.

SFAS 123(R), “Share-Based Payment”

In December 2004, the FASB issued SFAS 123(R), a revision to SFAS 123, which requires expensing stock options in the financial statements. Important to applying the new standard is understanding how to (1) measure the fair value of stock-based compensation awards and (2) recognize the related compensation cost for those awards. For an award to qualify for equity classification, it must meet certain criteria in SFAS 123(R). An award that does not meet those criteria will be classified as a liability and remeasured each period. SFAS 123(R) retains SFAS 123's requirements on accounting for income tax effects of stock-based compensation. In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule results in a six-month deferral for companies with a fiscal year beginning January 1. Therefore, FirstEnergy will adopt this Statement effective January 1, 2006. FirstEnergy expects to adopt modified prospective application, without restatement of prior interim periods. Potential cumulative adjustments, if any, have not yet been determined. FirstEnergy uses the Black-Scholes option-pricing model to value options for disclosure purposes only and expects to apply this pricing model upon adoption of SFAS 123(R).

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by FirstEnergy beginning January 1, 2006. FirstEnergy is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. FirstEnergy is currently evaluating this FSP and any impact on its investments.

FSP 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction and Qualified Production Activities Provided by the American Jobs Creation Act of 2004”

Issued in December 2004, FSP 109-1 provides guidance related to the provision within the American Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified production activities. The Act includes a tax deduction of up to nine percent (when fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS 109, “Accounting for Income Taxes", which is consistent with FirstEnergy's accounting.

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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
STATEMENTS OF INCOME
OPERATING REVENUES	$	825,790		$	766,336		$	2,268,760		$	2,227,978
OPERATING EXPENSES AND TAXES:
Fuel		15,158			15,244			39,080			44,158
Purchased power		229,561			242,835			703,658			730,542
Nuclear operating costs		76,254			81,244			264,514			235,277
Other operating costs		114,762			99,132			293,530			276,289
Provision for depreciation		30,169			30,702			87,875			90,846
Amortization of regulatory assets		126,439			103,211			347,880			317,030
Deferral of new regulatory assets		(43,929	)		(25,728	)		(107,750	)		(69,790	)
General taxes		51,945			47,634			146,066			135,688
Income taxes		99,778			76,502			245,942			203,863
Total operating expenses and taxes		700,137			670,776			2,020,795			1,963,903
OPERATING INCOME		125,653			95,560			247,965			264,075
OTHER INCOME (net of income taxes)		20,069			17,141			37,352			50,285
NET INTEREST CHARGES:
Interest on long-term debt		12,989			10,657			44,330			43,641
Allowance for borrowed funds used during construction
and capitalized interest		(3,014	)		(1,950	)		(8,255	)		(4,924	)
Other interest expense		4,193			640			12,457			7,576
Subsidiary's preferred stock dividend requirements		156			639			1,534			1,919
Net interest charges		14,324			9,986			50,066			48,212
NET INCOME		131,398			102,715			235,251			266,148
PREFERRED STOCK DIVIDEND REQUIREMENTS		659			623			1,976			1,843
EARNINGS ON COMMON STOCK	$	130,739		$	102,092		$	233,275		$	264,305
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	131,398		$	102,715		$	235,251		$	266,148
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized loss on available for sale securities		(3,402	)		(6,913	)		(19,079	)		(2,767	)
Income tax benefit related to other comprehensive income		2,043			2,850			7,713			1,141
Other comprehensive loss, net of tax		(1,359	)		(4,063	)		(11,366	)		(1,626	)
TOTAL COMPREHENSIVE INCOME	$	130,039		$	98,652		$	223,885		$	264,522
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

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OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2005			2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	5,573,996		$	5,440,374
Less - Accumulated provision for depreciation		2,793,343			2,716,851
		2,780,653			2,723,523
Construction work in progress -
Electric plant		246,325			203,167
Nuclear fuel		17,972			21,694
		264,297			224,861
		3,044,950			2,948,384
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds		341,335			354,707
Nuclear plant decommissioning trusts		462,439			436,134
Long-term notes receivable from associated companies		207,089			208,170
Other		44,623			48,579
		1,055,486			1,047,590
CURRENT ASSETS:
Cash and cash equivalents		900			1,230
Receivables -
Customers (less accumulated provisions of $7,312,000 and $6,302,000, respectively,
for uncollectible accounts)		285,462			274,304
Associated companies		121,262			245,148
Other (less accumulated provisions of $14,000 and $64,000, respectively,
for uncollectible accounts)		20,653			18,385
Notes receivable from associated companies		798,513			538,871
Materials and supplies, at average cost		92,610			90,072
Prepayments and other		17,336			13,104
		1,336,736			1,181,114
DEFERRED CHARGES:
Regulatory assets		844,590			1,115,627
Property taxes		61,419			61,419
Unamortized sale and leaseback costs		56,477			60,242
Other		67,093			68,275
		1,029,579			1,305,563
	$	6,466,751		$	6,482,651
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding	$	2,099,099		$	2,098,729
Accumulated other comprehensive loss		(58,484	)		(47,118	)
Retained earnings		434,473			442,198
Total common stockholder's equity		2,475,088			2,493,809
Preferred stock		60,965			60,965
Preferred stock of consolidated subsidiary		14,105			39,105
Long-term debt and other long-term obligations		1,099,147			1,114,914
		3,649,305			3,708,793
CURRENT LIABILITIES:
Currently payable long-term debt		273,656			398,263
Short-term borrowings -
Associated companies		120,971			11,852
Other		123,584			167,007
Accounts payable -
Associated companies		81,980			187,921
Other		11,289			10,582
Accrued taxes		213,843			153,400
Other		117,268			74,663
		942,591			1,003,688
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		688,702			766,276
Accumulated deferred investment tax credits		52,108			62,471
Asset retirement obligation		364,525			339,134
Retirement benefits		320,044			307,880
Other		449,476			294,409
		1,874,855			1,770,170
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	6,466,751		$	6,482,651
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these balance sheets.

67

OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	131,398		$	102,715		$	235,251		$	266,148
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		30,169			30,702			87,875			90,846
Amortization of regulatory assets		126,439			103,211			347,880			317,030
Deferral of new regulatory assets		(43,929	)		(25,728	)		(107,750	)		(69,790	)
Nuclear fuel and lease amortization		11,867			11,914			30,530			33,766
Amortization of lease costs		32,963			33,037			30,011			30,585
Amortization of electric service obligation		(4,565	)		-			(8,556	)		-
Deferred income taxes and investment tax credits, net		(17,787	)		(11,374	)		(22,929	)		(61,961	)
Accrued retirement benefit obligations		5,503			7,253			12,164			24,482
Accrued compensation, net		1,254			1,106			(1,903	)		5,138
Pension trust contribution		-			(72,763	)		-			(72,763	)
Decrease (increase) in operating assets -
Receivables		32,715			(86,506	)		110,460			(10,734	)
Materials and supplies		15,611			(2,930	)		(2,538	)		(8,796	)
Prepayments and other current assets		2,988			4,878			(4,232	)		(1,636	)
Increase (decrease) in operating liabilities -
Accounts payable		(20,007	)		115,690			(105,234	)		21,905
Accrued taxes		41,365			(4,464	)		60,443			(346,918	)
Accrued interest		2,458			3,028			1,667			2,918
Prepayment for electric service - education programs		-			-			136,142			-
Other		(11,504	)		2,572			1,372			(8,624	)
Net cash provided from operating activities		336,938			212,341			800,653			211,596
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		-			-			146,450			30,000
Short-term borrowings, net		18,254			91,072			65,696			13,258
Redemptions and Repayments -
Preferred stock		-			-			(37,750	)		-
Long-term debt		(17,819	)		(36,090	)		(278,327	)		(152,900	)
Dividend Payments -
Common stock		(64,000	)		(68,000	)		(241,000	)		(239,000	)
Preferred stock		(659	)		(623	)		(1,976	)		(1,843	)
Net cash used for financing activities		(64,224	)		(13,641	)		(346,907	)		(350,485	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(69,346	)		(61,682	)		(190,804	)		(146,645	)
Contributions to nuclear decommissioning trusts		(7,885	)		(7,885	)		(23,655	)		(23,655	)
Loan repayments from (loans to) associated companies, net		(200,021	)		(378,081	)		(258,561	)		30,709
Proceeds from certificates of deposit		-			277,763			-			277,763
Other		4,155			(29,200	)		18,944			113
Net cash provided from (used for) investing activities		(273,097	)		(199,085	)		(454,076	)		138,285
Net decrease in cash and cash equivalents		(383	)		(385	)		(330	)		(604	)
Cash and cash equivalents at beginning of period		1,283			1,664			1,230			1,883
Cash and cash equivalents at end of period	$	900		$	1,279		$	900		$	1,279
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these
statements.

68

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Ohio Edison Company:

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 1, 2005

69

OHIO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. The OE Companies also provide generation services to those customers electing to retain the OE Companies as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to some alternative energy suppliers under OE’s transition plan. The OE Companies have unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES -- an affiliated company.

Results of Operations

Earnings on common stock in the third quarter of 2005 increased to $131 million from $102 million in the third quarter of 2004. The increase in earnings resulted primarily from higher operating revenues and lower purchased power and nuclear operating costs, partially offset by increases in regulatory asset amortization, other operating costs and income taxes. During the first nine months of 2005, earnings on common stock decreased to $233 million from $264 million in the same period of 2004. The decrease in earnings for the first nine months of 2005 primarily resulted from increases in nuclear operating costs, regulatory asset amortization and a one-time income tax charge that occurred in the second quarter of 2005, as well as a decrease in other income. These reductions to earnings were partially offset by higher operating revenues and lower fuel and purchased power costs.

Operating revenues increased by $59 million or 7.8% in the third quarter of 2005 compared with the same period in 2004. Higher revenues for the quarter primarily resulted from increased retail generation and distribution revenues of $23 million and $33 million, respectively. During the first nine months of 2005 compared to the same period in 2004, operating revenues increased by $41 million or 1.8%. Higher revenues for the first nine months of 2005 were due to increases in retail generation and distribution revenues of $36 million and $40 million, respectively, partially offset by a $37 million decrease in wholesale sales.

Lower wholesale revenues for the first nine months of 2005 reflected decreased sales to FES of $57 million (12.1% KWH sales decrease), due to reduced nuclear generation available for sale. The decreased sales to FES were partially offset by increased sales of $21 million to non-affiliated customers (including MSG sales). Under its Ohio transition plan, OE is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters).

Increased retail generation revenues for the third quarter of 2005 resulted from higher sales to residential, commercial and industrial customers of $10 million, $2 million and $11 million, respectively. The increased generation KWH sales to residential (14.0%) and commercial (6.1%) customers were due to warmer than normal temperatures in the third quarter of 2005. Increased industrial revenues reflected a 6.5% increase in generation KWH sales. Partially offsetting the increase in residential KWH sales was an increase in customer shopping. Generation services provided to residential customers by alternative suppliers as a percent of total residential sales delivered in OE’s service area increased by 1.2 percentage points compared with the third quarter of 2004. Commercial and industrial customer shopping remained relatively unchanged.

Retail generation revenues increased for the first nine months of 2005 compared to the same period of 2004 in all customer sectors (residential - $15 million, commercial - $7 million and industrial - $14 million). The higher revenues were due to increased generation KWH sales (residential - 6.8%, commercial - 4.2% and industrial - 1.0%). Residential and industrial KWH sales increases were partially offset by increases in customer shopping by 1.1 and 1.7 percentage points, respectively, while commercial shopping remained relatively unchanged.

Revenues from distribution throughput increased $33 million in the third quarter of 2005 compared with the same period in 2004. Distribution deliveries to residential, commercial and industrial customers increased by $26 million, $4 million and $3 million, respectively, due to increased KWH deliveries. The increases from distribution deliveries were partially offset by lower composite unit prices in all sectors.

Revenues from distribution throughput increased $40 million in the first nine months of 2005 compared with the same period in 2004 due to higher revenues from residential and commercial customers, partially offset by lower industrial sector revenues. Residential and commercial distribution revenues increased $40 million and $3 million, respectively, reflecting higher KWH deliveries partially offset by lower composite prices. Industrial distribution revenues decreased by $3 million due to lower composite unit prices, partially offset by an increase in KWH distribution deliveries.

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Under the Ohio transition plan, OE provides incentives to customers to encourage switching to alternative energy providers. OE’s revenues were reduced by $3 million from additional credits in the third quarter and $7 million in the first nine months of 2005 compared to the same periods in 2004. These revenue reductions are deferred for future recovery from customers under OE’s transition plan and do not affect current period earnings (See Regulatory Matters below).

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:

	Three			Nine
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		9.1	%	3.9	%
Wholesale		(1.2	)%	(9.4	)%
Total Electric Generation Sales		4.0	%	(2.6	)%
Distribution Deliveries:
Residential		15.9	%	8.3	%
Commercial		6.3	%	4.2	%
Industrial		6.9	%	3.4	%
Total Distribution Deliveries		9.8	%	5.3	%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $29 million in the third quarter and $57 million in the first nine months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes	Three Months			Nine Months
Increase (Decrease)	(In millions)
Fuel costs	$	--		$	(5	)
Purchased power costs		(13	)		(27	)
Nuclear operating costs		(5	)		29
Other operating costs		16			17
Provision for depreciation		(1	)		(3	)
Amortization of regulatory assets		23			31
Deferral of new regulatory assets		(18	)		(38	)
General taxes		4			11
Income taxes		23			42
Net increase in operating expenses and taxes	$	29		$	57

Lower fuel costs in the first nine months of 2005, compared with the same periods of 2004, resulted from decreased nuclear generation - down 12.1%. Purchased power costs were lower in both periods of 2005, reflecting lower unit costs partially offset by higher KWH purchases in the third quarter of 2005. KWH purchases were relatively unchanged in the first nine months of 2005. Nuclear operating costs decreased in the third quarter of 2005 compared to the same quarter in 2004 primarily due to a decrease in non-fuel nuclear operating costs at Perry Unit 1 and Beaver Valley Unit 2. Nuclear operating costs increased during the first nine months of 2005 primarily due to the costs from the Beaver Valley Unit 2 refueling outage (started April 4, 2005) and to a lesser extent from the Perry Unit 1 outage initiated in the first quarter of 2005 that was completed on May 6, 2005. There were no nuclear refueling outages in the same periods last year. The increases in other operating costs in the third quarter and first nine months of 2005, compared to the same periods of 2004, resulted primarily from increased MISO transmission expenses, partially offset by lower employee benefits expenses.

The decrease in depreciation expense in the first nine months of 2005 compared with the same period of 2004 was attributable to revised estimated service life assumptions for fossil generating plants (see Note 3). Higher regulatory asset amortization in the three-month and nine-month periods was primarily due to increased amortization of transition costs being recovered under the RSP. Increases in regulatory asset deferrals for both periods resulted from higher shopping incentive deferrals and related interest ($4 million and $11 million, respectively), and the PUCO-approved MISO administrative cost deferrals and related interest ($14 million and $27 million, respectively, see Outlook - Regulatory Matters).

71

General taxes increased in the third quarter and first nine months of 2005 compared to the same periods of 2004 due to the effect of higher KWH sales which increased Ohio KWH excise taxes in both periods. The increase in the first nine months of 2005 also reflected the absence of a $6 million Pennsylvania property tax refund recognized in the second quarter of 2004.

Income taxes increased in the first nine months of 2005 compared to the same periods of 2004, primarily due to the effects of new tax legislation in Ohio. On June 30, 2005, the State of Ohio enacted new tax legislation that created a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25% annually, beginning with the year ended 2005. During the phase-out period the Ohio income tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period.

As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the nine months ended September 30, 2005 was an additional tax expense of approximately $36 million, which was partially offset by the initial phase-out of the Ohio income-based franchise tax, which reduced income taxes by approximately $7 million in the nine months ended September 30, 2005. See Note 12 to the consolidated financial statements.

Other Income

Other income decreased $13 million in the first nine months of 2005 compared with the same period of 2004, primarily due to an $8.5 million civil penalty payable to the Department of Justice and a $10 million liability for environmental projects recognized in connection with the W.H. Sammis Plant settlement (see Outlook - Environmental Matters), partially offset by higher nuclear decommissioning trust realized gains.

Net Interest Charges

Net interest charges increased by $4 million in the third quarter and $2 million in the first nine months of 2005 compared with the same periods of 2004, reflecting increased short-term borrowings from associated companies at a higher rate of interest.

Capital Resources and Liquidity

OE’s cash requirements for the remainder of 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing OE’s net debt and preferred stock outstanding. Borrowing capacity under credit facilities is available to manage working capital requirements. Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of September 30, 2005, OE's cash and cash equivalents of approximately $1 million remained unchanged from December 31, 2004.

 

72

Cash Flows From Operating Activities

Cash provided from operating activities during the third quarter and first nine months of 2005, compared with the corresponding periods in 2004 were as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Cash Flows	2005		2004			2005		2004
	(In millions)
Cash earnings (1)	$	273	$	224		$	603	$	607
Pension trust contribution (2)		--		(44	)		--		(44	)
Working capital and other		64		32			198		(351	)
Total cash flows from operating activities	$	337	$	212		$	801	$	212
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
(2) Pension trust contribution net of $29 million of income tax benefits.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	(In millions)
Net income (GAAP)	$	131		$	103		$	235		$	266
Non-cash charges (credits):
Provision for depreciation		30			31			88			91
Amortization of regulatory assets		126			103			348			317
Amortization of lease costs		33			33			30			31
Nuclear fuel and capital lease amortization		12			12			31			34
Deferral of new regulatory assets		(44	)		(26	)		(108	)		(70	)
Deferred income taxes and investment tax credits, net		(18	)		(40	)		(23	)		(91	)
Other non-cash items		3			8			2			29
Cash earnings (Non-GAAP)	$	273		$	224		$	603		$	607

Net cash provided from operating activities increased $125 million in the third quarter of 2005, compared with the third quarter of 2004, due to a $32 million increase from changes in working capital, the absence of a $44 million after-tax voluntary pension trust contribution made in the third quarter of 2004 and a $49 million increase in cash earnings as described above and under “Results from Operations”. The increase in working capital primarily reflects changes in accrued taxes of $46 million (including a $249 million reallocation of tax liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing agreement), partially offset by changes in accounts payable and accounts receivable of $16 million.

Net cash provided from operating activities increased $589 million in the first nine months of 2005, compared with the same period in 2004, due to a $549 million increase from changes in working capital, the absence of a $44 million after-tax voluntary pension trust contribution made in the third quarter of 2004, partially offset by a $4 million decrease in cash earnings as described above and under “Results from Operations”. The increase in working capital primarily reflects changes in accrued taxes of $407 million (including a $249 million reallocation of tax liabilities among the FirstEnergy subsidiaries pursuant to the tax sharing agreement) and $136 million of funds received for the Energy for Education program in the second quarter of 2005.

Cash Flows From Financing Activities

Net cash used for financing activities increased to $64 million in the third quarter of 2005 from $14 million in the third quarter of 2004. The increase primarily resulted from a $72 million decrease in new short-term borrowings, partially offset by an $18 million decrease in redemptions and repayments. Net cash used for financing activities decreased to $347 million in the first nine months of 2005 from $350 million in the same period of 2004. The decrease was due to a $169 million increase in new debt and short term borrowings partially offset by a $163 million increase in net debt and preferred stock redemptions.

73

On May 16, 2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, including accrued dividends to the date of redemption.

OE had approximately $799 million of cash and temporary cash investments (which include short-term notes receivable from associated companies) and $245 million of short-term indebtedness as of September 30, 2005. OE has authorization from the PUCO to incur short-term debt of up to $500 million (including bank facilities and the utility money pool described below). Penn has authorization from the SEC to incur short-term debt up to its charter limit of $51 million (including the utility money pool).

OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing arrangement. As a separate legal entity with separate creditors, OES Capital would have to satisfy its obligations to creditors before any of its remaining assets could be made available to OE. As of September 30, 2005, the facility was drawn for $120 million.

Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. As of September 30, 2005, the facility was not drawn. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

As of October 24, 2005, OE and Penn had the aggregate capability to issue approximately $1.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures following the recently completed intra-system transfer of fossil generating plants (see Note 17). The issuance of FMB by OE is also subject to provisions of its senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE to incur additional secured debt not otherwise permitted by a specified exception of up to $690 million as of October 24, 2005. Based upon applicable earnings coverage tests in their respective charters, OE and Penn could issue a total of $2.8 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil generating plants will reduce the aggregate capability of OE and Penn to issue preferred stock by approximately 17%.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. OE's and Penn’s borrowing limits under the facility are $550 million.

OE and Penn have the ability to borrow from their regulated affiliates and FirstEnergy to meet their short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50%.

OE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

74

Cash Flows From Investing Activities

Net cash used for investing activities increased by $74 million in the third quarter of 2005 and $592 million in the first nine months of 2005, from the same periods of 2004. These increases resulted primarily from $278 million in cash proceeds from certificates of deposit during the third quarter 2004. Loans to associated companies decreased $178 million in the third quarter of 2005, partially offsetting the proceeds from certificates of deposit, and increased $289 million in the first nine months of 2005.

In the last quarter of 2005, capital requirements for property additions and capital leases are expected to be approximately $82 million. OE has additional requirements of approximately $8 million to meet sinking fund requirements for preferred stock and maturing long-term debt (excluding Penn’s optional redemptions disclosed above) during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. OE’s capital spending for the period 2005-2007 is expected to be about $667 million of which approximately $233 million applies to 2005.

FirstEnergy Intra-System Generation Asset Transfers

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

On October 24, 2005, the OE Companies completed the transfer of non-nuclear generation assets to FGCO. The OE Companies currently expect to complete the transfer of nuclear generation assets to NGC through a spin-off by way of dividend before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with the Ohio Companies’ and Penn’s restructuring plans that were approved by the PUCO and the PPUC, respectively, under applicable Ohio and Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies and Penn were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

See Note 17 to the consolidated financial statements for OE's and Penn’s disclosure of the assets held for sale as of September 30, 2005.

Off-Balance Sheet Arrangements

Obligations not included on OE’s Consolidated Balance Sheets primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. The present value of these operating lease commitments, net of trust investments, was $678 million as of September 30, 2005.

Equity Price Risk

Included in OE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $262 million and $248 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $26 million reduction in fair value as of September 30, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of a sale or recognized as regulatory assets or liabilities.

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Outlook

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

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. OE has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised RSP.

As part of OE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provide 560 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in OE's franchise area.

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, OE filed an application with the PUCO to establish a GCAF rider under the RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to OE’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006 for all of the Ohio Companies). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.

On September 9, 2005, OE filed an application with the PUCO that, if approved, would supplement its existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period, and to provide OE with financial results generally comparable to those attained under the RSP. Major provisions of the RCP include:

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

· Defer and capitalize certain distribution costs to be incurred by all of the Ohio Companies during

 the period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the

 three years;

· Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of

 authorized costs will occur as of December 31, 2008 for OE;

· Reduce the deferred shopping incentive balance as of January 1, 2006 by up to $75 million for OE

 by accelerating the application of its accumulated cost of removal regulatory liability; and

· Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and

 2008, respectively, from all OE and TE distribution and transmission customers through a fuel

 recovery mechanism. OE may defer and capitalize increased fuel costs above the amount

 collected through the fuel recovery mechanism.

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Under provisions of the RSP, the PUCO may require OE to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for OE in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

On December 30, 2004, OE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $14 million per year; however, OE anticipates that this amount will increase. OE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. OE reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by OE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $30.6 million. This value includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, OE will file a modification to the rider which will determine revenues from July 2006 through June 2007.

The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for OE to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 31, 2004 was denied. The PUCO also authorized OE to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in a PUCO order issued on August 31, 2005 approving the stipulation referred to above. The OCC, OPAE and OE each filed applications for rehearing. OE sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied OE's and OCC’s applications and, at the request of OE, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies’ brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

OE and Penn record as regulatory assets costs which have been authorized by the PUCO, the PPUC and the FERC for recovery from customers in future periods and, without such authorization, the costs would have been charged to income when incurred. OE’s regulatory assets as of September 30, 2005 and December 31, 2004, were $0.8 billion and $1.1 billion, respectively. OE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $302 million as of September 30, 2005 and, under the RSP, will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the estimated net amortization of regulatory transition costs and deferred shopping incentive balances under the proposed RCP and current RSP. Penn's net regulatory asset components aggregate as net regulatory liabilities of approximately $48 million and $18 million, and are included in Other Noncurrent Liabilities on the Consolidated Balance Sheet as of September 30, 2005 and December 31, 2004, respectively.

On October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio and Pennsylvania and a detailed discussion of reliability initiatives, including actions by the PPUC, that impact Penn.

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Environmental Matters

OE 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 OE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulation 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) in all cases from the 2003 levels. The OE Companies’ Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the 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 the OE Companies operate affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of 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 Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, was approved by the Court on July 11, 2005, requires OE and Penn to reduce NO_x and SO₂ emissions at the W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results for the first quarter of 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million, respectively, for probable future cash contributions toward environmentally beneficial projects during the first quarter of 2005.

 

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Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (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 Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

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

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.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

 

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FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

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 effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which the OE Companies have a 35.24% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry 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. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and OE, and the Davis-Besse extended outage (OE has no interest in Davis-Besse), have become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. On August 24, 2005 additional information was requested regarding Davis-Besse. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

 

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

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

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

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

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

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

EITF Issue No. 05-6, “Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination”

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with the OE current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the second period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005. Therefore, OE will adopt this Interpretation in the fourth quarter of 2005. OE is currently evaluating the effect this standard will have on its financial statements.

 

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SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in an income statement. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. OE will adopt this Statement effective January 1, 2006.

SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. As a result, OE will adopt this Statement effective January 1, 2006, and does not expect it to have a material impact on its financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by OE beginning January 1, 2006. OE is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments”

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. OE is currently evaluating this FSP and any impact on its investments.

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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended							Nine Months Ended
	September 30,							September 30,
	2005			2004				2005			2004
	(In thousands)
STATEMENTS OF INCOME
OPERATING REVENUES	$	526,421		$	504,848		$	1,408,341		$	1,372,259
OPERATING EXPENSES AND TAXES:
Fuel		24,701			21,011			64,138			57,583
Purchased power		129,640			140,988			411,366			412,170
Nuclear operating costs		26,252			28,766			121,765			80,002
Other operating costs		89,475			76,196			227,759			219,857
Provision for depreciation		36,100			33,096			100,602			98,060
Amortization of regulatory assets		68,455			53,732			177,497			151,822
Deferral of new regulatory assets		(60,519	)		(40,596	)		(126,508	)		(92,032	)
General taxes		40,054			37,348			115,546			110,646
Income taxes		55,286			51,883			94,897			81,057
Total operating expenses and taxes		409,444			402,424			1,187,062			1,119,165
OPERATING INCOME		116,977			102,424			221,279			253,094
OTHER INCOME (net of income taxes)		24,117			8,264			37,691			29,485
NET INTEREST CHARGES:
Interest on long-term debt		27,090			24,061			83,452			92,967
Allowance for borrowed funds used during construction		(1,129	)		(1,056	)		(2,012	)		(3,782	)
Other interest expense		4,696			5,239			12,952			12,750
Net interest charges		30,657			28,244			94,392			101,935
NET INCOME		110,437			82,444			164,578			180,644
PREFERRED STOCK DIVIDEND REQUIREMENTS		-			1,754			2,918			5,253
EARNINGS ON COMMON STOCK	$	110,437		$	80,690		$	161,660		$	175,391
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	110,437		$	82,444		$	164,578		$	180,644
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on available for sale securities		(6,574	)		991			(9,144	)		(1,332	)
Income tax expense (benefit) related to other comprehensive income		(2,510	)		406			(3,433	)		(546	)
Other comprehensive income (loss), net of tax		(4,064	)		585			(5,711	)		(786	)
TOTAL COMPREHENSIVE INCOME	$	106,373		$	83,029		$	158,867		$	179,858
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

83

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2005		2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	4,498,876	$	4,418,313
Less - Accumulated provision for depreciation		2,020,868		1,961,737
		2,478,008		2,456,576
Construction work in progress -
Electric plant		90,911		85,258
Nuclear fuel		8,632		30,827
		99,543		116,085
		2,577,551		2,572,661
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		564,169		596,645
Nuclear plant decommissioning trusts		427,920		383,875
Long-term notes receivable from associated companies		8,774		97,489
Other		16,028		17,001
		1,016,891		1,095,010
CURRENT ASSETS:
Cash and cash equivalents		207		197
Receivables-
Customers (less accumulated provision of $5,309,000 for uncollectible accounts in 2005)		255,769		11,537
Associated companies		19,883		33,414
Other (less accumulated provisions of $6,000 and $293,000, respectively,		9,651		152,785
for uncollectible accounts)
Notes receivable from associated companies		-		521
Materials and supplies, at average cost		72,506		58,922
Prepayments and other		2,769		2,136
		360,785		259,512
DEFERRED CHARGES:
Goodwill		1,688,966		1,693,629
Regulatory assets		889,127		958,986
Property taxes		77,792		77,792
Other		29,995		32,875
		2,685,880		2,763,282
	$	6,641,107	$	6,690,465
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 105,000,000 shares -
79,590,689 shares outstanding	$	1,356,998	$	1,281,962
Accumulated other comprehensive income		12,148		17,859
Retained earnings		574,394		553,740
Total common stockholder's equity		1,943,540		1,853,561
Preferred stock		-		96,404
Long-term debt and other long-term obligations		1,939,730		1,970,117
		3,883,270		3,920,082
CURRENT LIABILITIES:
Currently payable long-term debt		75,706		76,701
Short-term borrowings-
Associated companies		518,784		488,633
Other		35,000		-
Accounts payable-
Associated companies		33,802		150,141
Other		6,702		9,271
Accrued taxes		156,630		129,454
Accrued interest		27,242		22,102
Lease market valuation liability		60,200		60,200
Other		39,094		61,131
		953,160		997,633
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		552,072		540,211
Accumulated deferred investment tax credits		58,736		60,901
Lease market valuation liability		623,100		668,200
Asset retirement obligation		280,765		272,123
Retirement benefits		86,597		82,306
Other		203,407		149,009
		1,804,677		1,772,750
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	6,641,107	$	6,690,465
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are
an integral part of these balance sheets.

84

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	110,437		$	82,444		$	164,578		$	180,644
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		36,100			33,096			100,602			98,060
Amortization of regulatory assets		68,455			53,732			177,497			151,822
Deferral of new regulatory assets		(60,519	)		(40,596	)		(126,508	)		(92,032	)
Nuclear fuel and capital lease amortization		8,236			7,804			19,017			20,420
Amortization of electric service obligation		(2,155	)		(3,336	)		(12,278	)		(12,877	)
Deferred rents and lease market valuation liability		(13,439	)		(14,324	)		(67,130	)		(56,182	)
Deferred income taxes and investment tax credits, net		10,484			13,019			14,934			11,392
Accrued retirement benefit obligations		2,169			2,854			4,291			10,900
Accrued compensation, net		1,201			1,303			(1,294	)		3,232
Pension trust contribution		-			(31,718	)		-			(31,718	)
Decrease (increase) in operating assets-
Receivables		10,507			(3,422	)		(87,567	)		106,421
Materials and supplies		15,207			(2,238	)		(13,584	)		(7,711	)
Prepayments and other current assets		(821	)		1,512			(633	)		3,409
Increase (decrease) in operating liabilities-
Accounts payable		(157,188	)		60,237			(118,908	)		1,889
Accrued taxes		33,955			(15,630	)		27,176			(52,495	)
Accrued interest		5,460			(3,218	)		5,140			(2,371	)
Prepayment for electric service - education programs		-			-			67,589			-
Other		(18,457	)		(3,335	)		(26,328	)		(40,193	)
Net cash provided from operating activities		49,632			138,184			126,594			292,610
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		87,772			44,330			141,056			125,238
Short-term borrowings, net		-			213,682			53,369			132,770
Equity contributions from parent		-			-			75,000			-
Redemptions and Repayments-
Preferred stock		-			(1,000	)		(101,900	)		(1,000	)
Long-term debt		(90,859	)		(327,171	)		(147,789	)		(335,272	)
Short-term borrowings, net		(5,505	)		-			-			-
Dividend Payments-
Common stock		(17,000	)		-			(141,000	)		(145,000	)
Preferred stock		-			(1,755	)		(2,260	)		(5,253	)
Net cash used for financing activities		(25,592	)		(71,914	)		(123,524	)		(228,517	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(37,809	)		(32,238	)		(98,053	)		(70,967	)
Loan repayments from (loans to) associated companies, net		22,309			(850	)		89,236			9,964
Investments in lessor notes		3			(11,699	)		32,476			9,266
Contributions to nuclear decommissioning trusts		(7,256	)		(7,256	)		(21,768	)		(21,768	)
Other		(1,287	)		(14,227	)		(4,951	)		(15,170	)
Net cash used for investing activities		(24,040	)		(66,270	)		(3,060	)		(88,675	)
Net change in cash and cash equivalents		-			-			10			(24,582	)
Cash and cash equivalents at beginning of period		207			200			197			24,782
Cash and cash equivalents at end of period	$	207		$	200		$	207		$	200
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an
integral part of these statements.

85

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of The Cleveland Electric Illuminating Company:

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 1, 2005

86

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI provides power directly to alternative energy suppliers under CEI’s transition plan. CEI has unbundled the price of electricity into its component elements -- including generation, transmission, distribution and transition charges. Power supply requirements of CEI are provided by FES -- an affiliated company.

Results of Operations

Earnings on common stock in the third quarter of 2005 increased to $110 million from $81 million in the third quarter of 2005. Increased earnings in the third quarter of 2005 resulted primarily from higher operating revenues and lower purchased power costs, which were partially offset by higher regulatory asset amortization and higher other operating costs. For the first nine months of 2005, earnings on common stock decreased to $162 million from $175 million in the same period of 2004. Lower earnings for the first nine months of 2005 resulted primarily from higher nuclear operating costs, higher regulatory asset amortization and other operating costs and a one-time income tax charge; those effects were partially offset by increased operating revenues and lower net interest charges.

Operating revenues increased by $22 million or 4.3% in the third quarter of 2005 from the same period in 2004. Higher revenues resulted primarily from increases in retail generation and distribution revenues of $3 million and $19 million, respectively, and a $5 million increase in revenues from wholesale sales. During the first nine months of 2005, operating revenues increased by $36 million or 2.6%, compared to the same period in 2004. Higher revenues were due to increases in retail generation and distribution revenues of $13 million and $23 million, respectively, and a $2 million increase in revenues from wholesale sales.

Increased retail generation revenues for the third quarter of 2005 resulted from higher industrial unit prices and higher residential KWH sales, partially offset by lower unit prices and KWH sales for commercial customers. An 18.7% increase in residential KWH sales during the third quarter was primarily due to warmer weather in CEI's service area, as compared to last year. An increase in residential customer shopping by 1.7 percentage points in the third quarter of 2005 partially offset the higher generation KWH sales as compared to 2004. Increased retail generation revenues for the first nine months of 2005 resulted from higher industrial unit prices and higher residential KWH sales, partially offset by lower commercial and industrial KWH sales. The decrease in residential customer shopping by 0.7 percentage points in the first nine months of 2005 contributed slightly to the higher generation KWH sales for the period as compared to last year.

Revenue from wholesale sales increased by $5 million during the third quarter of 2005, reflecting the effect of a 2.5% increase in KWH sales. The increase in wholesale sales was primarily due to a 13.6% KWH increase in MSG sales to non-affiliated wholesale customers ($3.5 million). Under its Ohio transition plan, CEI is required to provide MSG to non-affiliated alternative suppliers (see Outlook - Regulatory Matters). Increased sales to FES of $1.5 million (1.3% KWH increase) also contributed to the third quarter results. In the first nine months of 2005, wholesale sales revenue increased by $2 million. A $20 million increase (23.0% KWH increase) in MSG sales to non-affiliated wholesale customers was partially offset by an $18 million decrease in sales (6.7% KWH decrease) to FES.

Revenues from distribution throughput increased $19 million in the third quarter of 2005 compared with the same quarter of 2004. The increase was due to higher residential and industrial revenues ($18 million and $5 million, respectively), reflecting increased distribution deliveries in the third quarter of 2005, in part due to warmer weather. These increases were partially offset by lower commercial revenues of $4 million as a result of lower unit prices.

Revenues from distribution throughput increased $23 million in the first nine months of 2005 compared with the same period in 2004 due to higher revenues in the residential sector ($28 million), partially offset by lower industrial revenues ($4 million). Higher distribution deliveries in the residential sector were partially offset by lower unit prices and decreased KWH deliveries to industrial customers. Revenues in the commercial sector increased slightly ($0.4 million) as higher distribution deliveries were almost totally offset by lower unit prices.

87

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:

	Three			Nine
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		0.6	%		(0.3	)%
Wholesale		2.5	%		(4.0	)%
Total Electric Generation Sales		1.7	%		(2.5	)%
Distribution Deliveries:
Residential		18.7	%		9.7	%
Commercial		1.5	%		3.3	%
Industrial		2.8	%		(1.0	)%
Total Distribution Deliveries		6.6	%		2.9	%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $7 million in the third quarter and $68 million in the first nine months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

	Three			Nine
Operating Expenses and Taxes - Changes	Months			Months
Increase (Decrease)	(In millions)
Fuel costs	$	3		$	6
Purchased power costs		(11	)		(1	)
Nuclear operating costs		(2	)		42
Other operating costs		13			8
Provision for depreciation		3			3
Amortization of regulatory assets		15			26
Deferral of new regulatory assets		(20	)		(35	)
General taxes		3			5
Income taxes		3			14
Net increase in operating expenses and taxes	$	7		$	68

Higher fuel costs in the third quarter and first nine months of 2005, compared to the same periods last year, were primarily due to increased fossil fuel expenses associated with higher fossil generation levels in 2005. Lower purchased power costs in the third quarter of 2005, compared with the third quarter of 2004, reflected both lower unit costs and lower KWH purchased. The increase in nuclear operating costs in the first nine months of 2005, compared to the same period last year, was primarily due to a refueling outage (including an unplanned extension) at the Perry Plant in 2005 and a refueling outage at Beaver Valley Unit 2. A mid-cycle inspection outage at the Davis-Besse Plant in the first quarter of 2005 also contributed to higher nuclear operating costs in the first nine months of 2005. There were no scheduled outages in the first nine months of 2004. Higher other operating costs in the third quarter and first nine months of 2005, compared to the same periods last year, were primarily due to transmission expenses related to MISO Day 2 transactions that began on April 1, 2005.

Higher regulatory asset amortization in the third quarter and first nine months of 2005, compared to the same periods last year, was primarily due to increased amortization of transition costs being recovered under the RSP. Increases in regulatory asset deferrals for both the third quarter and first nine months in 2005, compared to the same periods in 2004, resulted from higher shopping incentive deferrals and related interest, and the PUCO-approved MISO administrative cost deferrals, including interest, that began in the second quarter of 2005 (see Outlook - Regulatory Matters).

On June 30, 2005, the State of Ohio enacted new tax legislation that created a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax was effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of 25% annually, beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the new tax legislation for the first nine months of 2005 was additional tax expense of approximately $8 million to adjust net deferred taxes and $2 million associated with the phase-out of the Ohio income-based franchise tax. See Note 12 to the consolidated financial statements.

88

Other Income

Other income increased by $16 million in the third quarter of 2005 compared with the same period of 2004, primarily due to higher nuclear decommissioning trust realized gains.

Net Interest Charges

Net interest charges in the first nine months of 2005 decreased by $8 million compared with the same period last year, reflecting the effects of net redemptions and refinancings since October 1, 2004.

Capital Resources and Liquidity

CEI’s cash requirements for the remainder of 2005 for operating expenses and construction expenditures are expected to be met without increasing net debt. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets.

 Changes in Cash Position

As of September 30, 2005, CEI had $207,000 of cash and cash equivalents, compared with $197,000 as of December 31, 2004. The major sources of changes in these balances are summarized below.

Cash Flows from Operating Activities

Cash provided by operating activities during the third quarter and first nine months of 2005, compared with the corresponding periods in 2004, were as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Operating Cash Flows	2005			2004			2005			2004
	(In millions)
Cash earnings (1)	$	161		$	123		$	274		$	302
Pension trust contribution (2)		--			(19	)		--			(19	)
Working capital and other		(111	)		35			(147	)		10
Total cash flows from operating activities	$	50		$	139		$	127		$	293
(1) Cash earnings is a non-GAAP measure (see reconciliation below). (2) Pension contribution net of $13 million of income tax benefits

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

89

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	(In millions)
Net income (GAAP)	$	110		$	83		$	164		$	181
Non-cash charges (credits):
Provision for depreciation		36			33			101			98
Amortization of regulatory assets		68			54			177			152
Deferral of new regulatory assets		(60	)		(41	)		(126	)		(92	)
Nuclear fuel and capital lease amortization		8			7			19			20
Amortization of electric service obligation		(2	)		(3	)		(12	)		(13	)
Deferred rents and lease market valuation liability		(13	)		(14	)		(67	)		(56	)
Deferred income taxes and investment tax credits, net		10			--			15			(2	)
Accrued retirement benefit obligations		2			3			4			11
Accrued compensation, net		2			1			(1	)		3
Cash earnings (Non-GAAP)	$	161		$	123		$	274		$	302

The increase in cash earnings of $38 million for the third quarter and the decrease of $28 million for the first nine months of 2005, as compared to the respective periods of 2004, are described above under "Results of Operations". The primary factors contributing to the changes in working capital and other for the third quarter of 2005 are changes in accounts payable of $217 million, partially offset by changes in accrued taxes of $50 million. The primary factors contributing to the changes in working capital and other for the first nine months of 2005 are changes in accounts receivable of $194 million and accounts payable of $121 million, partially offset by changes in accrued taxes of $80 million and the $68 million received in the second quarter of 2005 for prepaid electric service under the Ohio Schools Council’s Energy for Education Program.

Cash Flows from Financing Activities

Net cash used for financing activities decreased $46 million in the third quarter of 2005 from the third quarter of 2004. The decrease resulted from a $62 million decrease in net debt redemptions, partially offset by higher common stock dividends to FirstEnergy of $17 million. Net cash used for financing activities decreased $105 million in the first nine months of 2005 from the same period last year. The decrease resulted primarily from lower net debt redemptions and common stock dividends to FirstEnergy and a $75 million equity contribution from FirstEnergy in the second quarter of 2005, partially offset by an increase in preferred stock redemptions.

CEI had $207,000 of cash and temporary investments and approximately $554 million of short-term indebtedness as of September 30, 2005. CEI has obtained authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). As of October 24, 2005, CEI had the capability to issue $1.6 billion of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture following the recently completed intra-system transfer of fossil and hydroelectric generating plants (See Note 17). The issuance of FMB by CEI is subject to a provision of its senior note indenture generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, this provision would permit CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $582 million as of September 30, 2005. CEI has no restrictions on the issuance of preferred stock.

CFC is a wholly owned subsidiary of CEI whose borrowings are secured by customer accounts receivable purchased from CEI and TE. CFC can borrow up to $200 million under a receivables financing arrangement. As a separate legal entity with separate creditors, CFC would have to satisfy its obligations to creditors before any of its remaining assets could be made available to CEI. As of September 30, 2005, the facility was drawn for $35 million.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date, as the same may be extended. CEI’s borrowing limit under the facility is $250 million.

90

CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50%.

CEI’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows from Investing Activities

In the third quarter and first nine months of 2005, net cash used for investing activities decreased $42 million and $86 million, respectively, from the corresponding periods of 2004. The decrease in funds used for investing activities for both periods primarily reflected increases in loan payments received from associated companies, partially offset by increased property additions.

In the last quarter of 2005, capital requirements for property additions are expected to be about $37 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. CEI has no additional requirements for sinking fund requirements for preferred stock and debt during the remainder of 2005. CEI’s capital spending for the period 2005-2007 is expected to be about $368 million of which approximately $124 million applies to 2005.

FirstEnergy Intra-System Generation Asset Transfers

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

On October 24, 2005, CEI completed the transfer of non-nuclear generation assets to FGCO. CEI currently expects to complete the transfer of nuclear generation assets to NGC at book value before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with the Ohio Companies’ restructuring plans that were approved by the PUCO under applicable Ohio electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

See Note 17 to the consolidated financial statements for CEI’s disclosure of the assets held for sale as of September 30, 2005.

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Off-Balance Sheet Arrangements

Obligations not included on CEI’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of September 30, 2005, the present value of these operating lease commitments, net of trust investments, total $103 million.

CEI sells substantially all of its retail customer receivables to CFC, its wholly owned subsidiary. As of June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.

Equity Price Risk

Included in CEI’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $277 million and $242 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28 million reduction in fair value as of September 30, 2005.

Outlook

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

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of CEI's customers elects to obtain power from an alternative supplier, CEI reduces the customer's bill with a "generation shopping credit," based on the generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. CEI has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised RSP.

As part of CEI's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in CEI's franchise area.

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, CEI filed an application with the PUCO to establish a GCAF rider under the RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to CEI’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006 for all of the Ohio Companies). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.

On September 9, 2005, CEI filed an application with the PUCO that, if approved, would supplement its existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

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· Maintain the existing level of base distribution rates through April 30, 2009 for CEI;

· Defer and capitalize certain distribution costs to be incurred by all of the Ohio Companies during the

 period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three

 years;

· Adjust the RTC and extended RTC recovery periods and rate levels so that full recovery of authorized

 costs will occur as of December 31, 2010 for CEI;

· Reduce the deferred shopping incentive balances as of January 1, 2006 by up to $85 million for CEI

 by accelerating the application of its accumulated cost of removal regulatory liability; and

· Defer and capitalize all of CEI's allowable fuel cost increases until January 1, 2009.

Under provisions of the RSP, the PUCO may require CEI to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for CEI in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies' filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

On December 30, 2004, CEI filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $16 million per year; however, CEI anticipates that this amount will increase. CEI requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. CEI reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by CEI, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $23.9million. This value includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, CEI will file a modification to the rider which will determine revenues from July 2006 through June 2007.

The second application sought authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for CEI to defer incremental transmission and ancillary service-related charges incurred as a participant in MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 30, 2004 was denied. The PUCO also authorized CEI to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in a PUCO order issued on August 31, 2005, approving the stipulation referred to above. The OCC, OPAE and CEI each filed applications for rehearing. CEI sought authority to defer the transmission and ancillary service-related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied CEI’s and OCC’s applications and, at the request of CEI, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

CEI records as regulatory assets costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, the costs would have been charged to income when incurred. CEI's regulatory assets as of September 30, 2005 and December 2004 were $0.9 billion and $1.0 billion, respectively. CEI is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $402 million as of September 30, 2005 and under the RSP, will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the estimated net amortization of regulatory transition costs and deferred shopping incentive balances under the proposed RCP and current RSP.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

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Environmental Matters

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

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulation 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) in all cases from the 2003 levels. CEI's Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the 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 CEI operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of 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 Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (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 Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

CEI cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by CEI is lower than many regional competitors due to CEI's diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

 

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Regulation of Hazardous Waste

CEI has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $2.3 million as of September 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name or as subrogees in the name of their insureds. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

 

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One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station, in which CEI has a 51.38% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. CEI accrued $1.0 million for a potential fine prior to 2005 and accrued the remaining liability for its share of the proposed fine of $1.8 million during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability based on the events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to emergency sirens.

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 effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which CEI has a 44.85% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

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On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry 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. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

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

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

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

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

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

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

EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with CEI’s current accounting.

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FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for CEI in the fourth quarter of 2005. CEI is currently evaluating the effect this Interpretation will have on its financial statements.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. CEI will adopt this Statement effective January 1, 2006.

SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for CEI. This FSP is not expected to have a material impact on CEI’s financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by CEI beginning January 1, 2006. CEI is currently evaluating this Standard and does not expect it to have a material impact on its financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. CEI is currently evaluating this FSP and any impact on its investments.

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THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
STATEMENTS OF INCOME
OPERATING REVENUES	$	286,960		$	276,342		$	787,824		$	755,106
OPERATING EXPENSES AND TAXES:
Fuel		16,501			13,908			43,474			37,195
Purchased power		73,144			79,774			225,600			236,869
Nuclear operating costs		39,207			43,827			145,059			122,685
Other operating costs		48,164			43,865			123,823			121,228
Provision for depreciation		18,835			14,588			48,724			43,021
Amortization of regulatory assets		39,576			41,037			107,672			102,065
Deferral of new regulatory assets		(19,379	)		(12,442	)		(41,473	)		(29,664	)
General taxes		14,159			14,924			41,960			41,252
Income taxes		20,311			11,963			44,160			18,465
Total operating expenses and taxes		250,518			251,444			738,999			693,116
OPERATING INCOME		36,442			24,898			48,825			61,990
OTHER INCOME (net of income taxes)		12,283			4,172			18,173			14,724
NET INTEREST CHARGES:
Interest on long-term debt		3,912			4,015			12,655			23,057
Allowance for borrowed funds used during construction		(372	)		(741	)		(117	)		(2,843	)
Other interest expense		2,958			1,350			4,192			2,945
Net interest charges		6,498			4,624			16,730			23,159
NET INCOME		42,227			24,446			50,268			53,555
PREFERRED STOCK DIVIDEND REQUIREMENTS		1,687			2,211			6,109			6,633
EARNINGS ON COMMON STOCK	$	40,540		$	22,235		$	44,159		$	46,922
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	42,227		$	24,446		$	50,268		$	53,555
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on available for sale securities		(4,511	)		913			(6,695	)		(379	)
Income tax expense (benefit) related to other comprehensive income		(1,743	)		375			(2,534	)		(155	)
Other comprehensive income (loss), net of tax		(2,768	)		538			(4,161	)		(224	)
TOTAL COMPREHENSIVE INCOME	$	39,459		$	24,984		$	46,107		$	53,331
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of  these statements.

99

THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2005		2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	1,906,941	$	1,856,478
Less - Accumulated provision for depreciation		820,562		778,864
		1,086,379		1,077,614
Construction work in progress -
Electric plant		55,376		58,535
Nuclear fuel		7,370		15,998
		62,746		74,533
		1,149,125		1,152,147
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		178,765		190,692
Nuclear plant decommissioning trusts		335,553		297,803
Long-term notes receivable from associated companies		39,964		39,975
Other		1,741		2,031
		556,023		530,501
CURRENT ASSETS:
Cash and cash equivalents		15		15
Receivables -
Customers (less accumulated provision of $2,000 for
uncollectible accounts in 2004)		2,412		4,858
Associated companies		10,168		36,570
Other		8,658		3,842
Notes receivable from associated companies		52,639		135,683
Materials and supplies, at average cost		42,404		40,280
Prepayments and other		1,712		1,150
		118,008		222,398
DEFERRED CHARGES:
Goodwill		501,022		504,522
Regulatory assets		309,835		374,814
Property taxes		24,100		24,100
Other		26,520		25,424
		861,477		928,860
	$	2,684,633	$	2,833,906
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, $5 par value, authorized 60,000,000 shares -
39,133,887 shares outstanding	$	195,670	$	195,670
Other paid-in capital		428,572		428,559
Accumulated other comprehensive income		15,878		20,039
Retained earnings		225,218		191,059
Total common stockholder's equity		865,338		835,327
Preferred stock		96,000		126,000
Long-term debt		296,373		300,299
		1,257,711		1,261,626
CURRENT LIABILITIES:
Currently payable long-term debt		53,650		90,950
Accounts payable -
Associated companies		28,456		110,047
Other		3,252		2,247
Notes payable to associated companies		378,190		429,517
Accrued taxes		72,214		46,957
Lease market valuation liability		24,600		24,600
Other		28,735		53,055
		589,097		757,373
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		222,985		221,950
Accumulated deferred investment tax credits		24,697		25,102
Lease market valuation liability		249,550		268,000
Retirement benefits		42,998		39,227
Asset retirement obligation		200,078		194,315
Other		97,517		66,313
		837,825		814,907
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	2,684,633	$	2,833,906
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these blance sheets.

100

THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	42,227		$	24,446		$	50,268		$	53,555
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		18,835			14,588			48,724			43,021
Amortization of regulatory assets		39,576			41,037			107,672			102,065
Deferral of new regulatory assets		(19,379	)		(12,442	)		(41,473	)		(29,664	)
Nuclear fuel and capital lease amortization		5,682			7,058			13,816			17,596
Amortization of electric service obligation		(1,910	)		-			(3,301	)		-
Deferred rents and lease market valuation liability		10,310			9,689			(34,156	)		(26,585	)
Deferred income taxes and investment tax credits, net		(12,798	)		(4,608	)		(4,605	)		(9,290	)
Accrued retirement benefit obligations		1,534			1,324			3,771			4,733
Accrued compensation, net		404			516			(333	)		1,477
Pension trust contribution		-			(12,572	)		-			(12,572	)
Decrease (increase) in operating assets -
Receivables		3,423			69,908			15,962			95,383
Materials and supplies		3,788			(725	)		(2,124	)		(4,376	)
Prepayments and other current assets		(970	)		677			(562	)		5,971
Increase (decrease) in operating liabilities -
Accounts payable		(6,215	)		6,202			(80,586	)		(9,568	)
Accrued taxes		14,748			(3,508	)		25,257			227
Accrued interest		(369	)		(7,169	)		(565	)		(7,540	)
Prepayment for electric service -- education programs		-			-			37,954			-
Other		(14,392	)		(10,020	)		(22,999	)		(9,679	)
Net cash provided from operating activities		84,494			124,401			112,720			214,754
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		-			30,500			45,000			103,500
Short-term borrowings, net		45,054			146,370			-			29,310
Redemptions and Repayments -
Preferred stock		(30,000	)		-			(30,000	)		-
Long-term debt		(36,821	)		(246,591	)		(83,754	)		(261,591	)
Short-term borrowings, net		-			-			(51,327	)		-
Dividend Payments -
Common stock		-			-			(10,000	)		-
Preferred stock		(1,687	)		(2,211	)		(6,109	)		(6,633	)
Net cash used for financing activities		(23,454	)		(71,932	)		(136,190	)		(135,414	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(17,951	)		(16,950	)		(50,119	)		(36,377	)
Loan repayments from (loans to) associated companies, net		(36,490	)		(20,389	)		83,055			(21,046	)
Investments in lessor notes		32			-			11,927			10,280
Contributions to nuclear decommissioning trusts		(7,135	)		(7,135	)		(21,406	)		(21,406	)
Other		504			(7,995	)		13			(13,013	)
Net cash provided from (used for) investing activities		(61,040	)		(52,469	)		23,470			(81,562	)
Net change in cash and cash equivalents		-			-			-			(2,222	)
Cash and cash equivalents at beginning of period		15			15			15			2,237
Cash and cash equivalents at end of period	$	15		$	15		$	15		$	15
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of these statements.

101

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of The Toledo Edison Company:

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 1, 2005

102

THE TOLEDO EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE provides power directly to some alternative energy suppliers under TE’s transition plan. TE has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. TE’s power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the third quarter of 2005 increased to $41 million from $22 million in the third quarter of 2004. The increase in earnings resulted primarily from higher operating revenues and other income, partially offset by increased financing costs. Earnings on common stock in the first nine months of 2005 decreased to $44 million from $47 million in the first nine months of 2004. The decrease in earnings resulted primarily from higher nuclear operating costs and a one-time income tax charge, partially offset by higher operating revenues and lower financing costs.

Operating revenues increased by $11 million, or 3.8%, in the third quarter of 2005 compared to the third quarter of 2004. Higher revenues in the third quarter of 2005 resulted from increased retail generation revenues of $13 million and distribution revenues of $2 million, partially offset by a decrease in wholesales sales (primarily to FES) of $4 million and an increase in shopping incentive credits of $1 million. Retail generation revenues increased as a result of increased KWH sales (residential - $1 million, commercial - $1 million and industrial - $11 million). Higher residential and commercial revenues reflected increased KWH sales (8.0% and 9.2%, respectively) and higher unit prices. KWH sales to residential and commercial customers increased primarily due to warmer weather which increased air-conditioning loads. Additionally, generation services provided to commercial customers by alternative suppliers as a percent of total commercial sales delivered in TE’s service area decreased by 2.1 percentage points compared with the third quarter of 2004. Industrial revenues increased as a result of higher unit prices and a 4.2% increase in KWH sales.

Revenues from distribution throughput increased by $2 million in the third quarter of 2005 from the corresponding quarter of 2004. The increase was due to higher residential and commercial revenues ($8 million and $0.2 million, respectively), partially offset by a decrease in industrial revenues ($7 million). The impact of higher residential and commercial KWH sales contributed to the increase; lower industrial unit prices more than offset an increase in KWH sales to industrial customers.

Operating revenues increased by $33 million, or 4.3%, in the first nine months of 2005 compared to the same period of 2004. The higher revenues resulted from increased retail generation revenues of $35 million and wholesales sales of $2 million, partially offset by an increase in shopping incentive credits of $3 million. Retail generation revenues increased as a result of higher KWH sales (residential - $2 million, commercial - $4 million, industrial - $29 million). Higher residential and commercial revenues reflected increased KWH sales (6.9% and 12.2%, respectively) and higher unit prices. Residential and commercial sales volumes increased primarily due to warmer weather. The increase in commercial revenues also reflects a reduction by 2.5 percentage points in customer shopping compared with the same period of 2004. Industrial revenues increased as a result of higher unit prices and a 0.6% increase in KWH sales.

Revenues from distribution throughput decreased by $0.4 million in the first nine months of 2005 from the same period in 2004. The decrease was due to lower industrial revenues ($22 million), partially offset by increases in residential and commercial revenues ($15 million and $6 million, respectively). The impact from lower industrial unit prices more than offset the higher KWH sales in all customer classes.

Under the Ohio transition plan, TE provides incentives to customers to encourage switching to alternative energy providers. TE’s revenues were reduced by $1 million from additional credits in the third quarter and $3 million in the first nine months of 2005 compared with the same periods of 2004. These revenue reductions are deferred for future recovery under TE’s transition plan and do not affect current period earnings (see Regulatory Matters below).

 

103

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004, are summarized in the following table:

	Three			Nine
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		6.0	%		3.9	%
Wholesale		3.5	%		3.4	%
Total Electric Generation Sales		4.6	%		3.7	%
Distribution Deliveries:
Residential		16.7	%		12.0	%
Commercial		4.7	%		6.8	%
Industrial		4.8	%		1.2	%
Total Distribution Deliveries		7.7	%		5.3	%

Operating Expenses and Taxes

Total operating expenses and taxes decreased $1 million in the third quarter and increased $46 million in the first nine months of 2005 from the same periods in 2004. The following table presents changes from the prior year by expense category.

	Three			Nine
Operating Expenses and Taxes - Changes	Months			Months
Increase (Decrease)	(In millions)
Fuel costs	$	3		$	6
Purchased power costs		(7	)		(11	)
Nuclear operating costs		(4	)		22
Other operating costs		4			3
Provision for depreciation		4			6
Amortization of regulatory assets		(1	)		6
Deferral of new regulatory assets		(7	)		(12	)
General taxes		(1	)		1
Income taxes		8			25
Net increase (decrease) in operating expenses and taxes	$	(1	)	$	46

Higher fuel costs in the third quarter and first nine months of 2005, compared with the same periods of 2004, resulted primarily from increased fossil-fired generation from the Mansfield Plant, up 5.7% and 7.1% during the respective periods. Purchased power costs decreased in both periods due to lower unit costs and reduced KWH purchases. Nuclear operating costs decreased in the third quarter of 2005 primarily from lower employee benefit costs and operating expenses for the nuclear generating units. Nuclear operating costs increased in the nine-month period due to a scheduled refueling outage (including an unplanned extension) at the Perry Plant, a mid-cycle inspection outage at the Davis-Besse Plant during the first quarter of 2005, and the Beaver Valley Unit 2 refueling outage in the second quarter of 2005, compared to no scheduled outages in the first nine months of 2004. Other operating costs increased in both periods of 2005 compared to the same periods of 2004 primarily because of MISO Day 2 expenses that began on April 1, 2005, partially offset by lower Beaver Valley Unit 2 letter of credit fees, insurance settlements and lower employee benefits costs.

Depreciation charges increased by $4 million in the third quarter and $6 million in first nine months of 2005 compared to the same periods of 2004 primarily due to property additions and reduced amortization periods for expenditures on leased generating plants to conform to the lease terms. These increases were partially offset by the effect of revised service life assumptions for fossil generating plants (See Note 3). Regulatory asset amortization increased in the first nine months of 2005 due to the increased amortization of transition costs being recovered under the RSP. Deferrals of new regulatory assets increased in the third quarter and first nine months of 2005 compared to the same periods of 2004, primarily due to higher shopping incentives and related interest ($2 million and $5 million, respectively) and the deferral of the PUCO-approved MISO administrative expenses and related interest ($5 million and $6 million, respectively).

On June 30, 2005, the State of Ohio enacted new tax legislation that created a new CAT tax, which is based on qualifying “taxable gross receipts” and will not consider any expenses or costs incurred to generate such receipts, except for items such as cash discounts, returns and allowances, and bad debts. The CAT tax is effective July 1, 2005, and replaces the Ohio income-based franchise tax and the Ohio personal property tax. The CAT tax is phased-in while the current income-based franchise tax is phased-out over a five-year period at a rate of 20% annually, beginning with the year ended 2005, and personal property tax is phased-out over a four-year period at a rate of approximately 25%, annually beginning with the year ended 2005. For example, during the phase-out period the Ohio income-based franchise tax will be computed consistently with the prior tax law, except that the tax liability as computed will be multiplied by 4/5 in 2005; 3/5 in 2006; 2/5 in 2007 and 1/5 in 2008, therefore eliminating the current income-based franchise tax over a five-year period. As a result of the new tax structure, all net deferred tax benefits that are not expected to reverse during the five-year phase-in period were written-off as of June 30, 2005. The impact on income taxes associated with the required adjustment to net deferred taxes for the nine months ended September 30, 2005 was additional tax expense of $17.5 million, which was partially offset by the phase-out of the Ohio income tax which reduced income taxes by $0.7 million in the third quarter of 2005 and $1.2 million for the nine months ended September 30, 2005. See Note 12 to the consolidated financial statements.

104

Other Income

Other income increased by $8 million in the third quarter of 2005 and $3 million in the first nine months of 2005 compared with the same periods of 2004, primarily due to higher nuclear decommissioning trust realized gains, partially offset by lower interest income earned on associated company notes receivable that were repaid in May 2005. Additionally, the recognition of a $1.6 million NRC fine related to the Davis-Besse Plant (see Outlook - Other Legal Proceedings) during the first quarter of 2005 partially offset the increase in other income during the first nine months of 2005.

Net Interest Charges

Net interest charges increased by $2 million in the third quarter of 2005 compared with the same period in 2004, primarily related to higher interest rates charged for money pool borrowings from associated companies in 2005. The average interest rate for borrowings in the third quarter of 2005 was 3.50% versus 1.28% in the same period in 2004. However, net interest charges decreased by $6 million in the first nine months of 2005 compared with the same period of 2004, reflecting redemptions and refinancings since October 1, 2004.

Capital Resources and Liquidity

TE’s cash requirements for the remainder of 2005 for operating expenses and construction expenditures are expected to be met without increasing its net debt and preferred stock outstanding. Thereafter, TE expects to meet its contractual obligations with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of September 30, 2005, TE's cash and cash equivalents of $15,000 remained unchanged from December 31, 2004.

Cash Flows From Operating Activities

Cash provided from operating activities during the third quarter and first nine months of 2005, compared with the corresponding period of 2004 were as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Cash Flows	2005		2004			2005			2004
	(In millions)
Cash earnings(1)	$	84	$	77		$	140		$	152
Pension trust contribution(2)		--		(8	)		--			(8	)
Working capital and other		--		55			(27	)		71
Total cash flows from operating activities	$	84	$	124		$	113		$	215
(1) Cash earnings are a non-GAAP measure (see reconciliation below).
(2) Pension trust contribution net of $5 million of income tax benefits.

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

105

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	(In millions)
Net income (GAAP)	$	42		$	24		$	50		$	54
Non-cash charges (credits):
Provision for depreciation		19			15			49			43
Amortization of regulatory assets		40			41			108			102
Deferral of new regulatory assets		(20	)		(12	)		(42	)		(30	)
Nuclear fuel and capital lease amortization		6			7			14			18
Amortization of electric service obligation		(2	)		--			(3	)		-
Deferred rents and above-market lease liability		10			10			(34	)		(27	)
Deferred income taxes and investment tax credits, net		(13	)		(8	)		(5	)		(14	)
Accrued retirement benefits obligations		2			1			4			5
Accrued compensation, net		-			(1	)		(1	)		1
Cash earnings (Non-GAAP)	$	84		$	77		$	140		$	152

Net cash provided from operating activities decreased by $40 million in the third quarter of 2005 from the third quarter of 2004 as a result of a $55 million decrease from working capital, partially offset by a $7 million increase in cash earnings as described above and under “Results of Operations” and the absence of an $8 million after-tax voluntary pension trust contribution made in the third quarter of 2004. Net cash provided from operating activities decreased by $102 million in the first nine months of 2005 compared to the same period last year as a result of a $98 million change in working capital and a $12 million decrease in cash earnings as described above and under “Results of Operations,” partially offset by the absence of an $8 million after-tax voluntary pension trust contribution made in 2004. The change in working capital for both periods was primarily due to changes in accounts payable, accrued taxes and receivables, partially offset in the nine-month period of 2005 by funds received for prepaid electric service under the Ohio Schools Council’s Energy for Education Program that began in the second quarter of 2005.

Cash Flows From Financing Activities

Net cash used for financing activities decreased by $48 million and increased by $1 million in the third quarter and first nine months of 2005, respectively, as compared to the same periods of 2004. The activities in both periods reflect an increase in net debt redemptions and preferred stock redemptions. The increase in the nine-month period of 2005 also included a $10 million increase in common stock dividends to FirstEnergy.

On July 1, 2005, TE redeemed all of its 1,200,000 outstanding shares of 7.00% Series A preferred stock at $25.00 per share, plus accrued dividends to the date of redemption. TE also repurchased $37 million of pollution control revenue bonds on September 1, 2005, with the intent to remarket them by the end of the first quarter of 2006.

TE had $53 million of cash and temporary investments (which included short-term notes receivable from associated companies) and $378 million of short-term indebtedness as of September 30, 2005. TE has authorization from the PUCO to incur short-term debt of up to $500 million (including the utility money pool described below). As of October 24, 2005, TE had the capability to issue $1.0 billion of additional FMB on the basis of property additions and retired bonds under the terms of its mortgage indenture following the recently completed intra-system transfer of fossil generating plants (See Note 17). Based upon applicable earnings coverage tests, TE could issue up to $1.15 billion of preferred stock (assuming no additional debt was issued) as of September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil generating plants will reduce the capability of TE to issue preferred stock by approximately $16 million.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date, as the same may be extended. TE's borrowing limit under the facility is $250 million.

TE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the third quarter of 2005 was 3.50%.

106

TE’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows From Investing Activities

Net cash used for investing activities increased by $9 million in the third quarter of 2005 compared with from the same period of 2004. Net cash provided from investing activities increased by $105 million in the first nine months of 2005, from the same period of 2004. These increases were primarily due to changes from loan activity with associated companies during the periods, partially offset by increased property additions in the nine-month period.

In the last quarter of 2005, TE’s capital spending is expected to be about $25 million. These cash requirements are expected to be satisfied from internal cash and short-term borrowings. TE’s capital spending for the period 2005-2007 is expected to be about $192 million, of which approximately $64 million applies to 2005.

FirstEnergy Intra-System Generation Asset Transfers

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

On October 24, 2005, TE completed the transfer of non-nuclear generation assets to FGCO. TE currently expects to complete the transfer of nuclear generation assets to NGC at book value before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with the Ohio Companies’ restructuring plans that were approved by the PUCO under applicable Ohio electric utility restructuring legislation. Consistent with the restructuring plans, generation assets that had been owned by the Ohio Companies were required to be separated from the regulated delivery business of those companies through transfer to a separate corporate entity. FENOC currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by the restructuring plans by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

See Note 17 to the consolidated financial statements for TE’s disclosure of the assets held for sale as of September 30, 2005.

Off-Balance Sheet Arrangements

Obligations not included on TE’s Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of September 30, 2005, the present value of these operating lease commitments, net of trust investments, totaled $541 million.

TE sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. As of June 16, 2005, the CFC receivables financing structure was renewed and restructured from an off-balance sheet transaction to an on-balance sheet transaction. Under the new structure, any borrowings under the facility appear on the balance sheet as short-term debt.

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Equity Price Risk

Included in TE’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $217 million and $188 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $22 million reduction in fair value as of September 30, 2005. Changes in the fair value of these investments are recorded in OCI unless recognized as a result of sales.

Outlook

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

Regulatory Matters

In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE's customers elects to obtain power from an alternative supplier, TE reduces the customer's bill with a "generation shopping credit," based on the generation component plus an incentive, and the customer receives a generation charge from the alternative supplier. TE has continuing PLR responsibility to its franchise customers through December 31, 2008 unless the PUCO accepts future competitive bid results prior to the end of that period under the revised RSP.

As part of TE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. TE is also required to provide 160 MW of low cost supply (MSG) to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in TE's franchise area.

On August 5, 2004, the Ohio Companies accepted the RSP as modified and approved by the PUCO in an August 4, 2004 Entry on Rehearing, subject to a competitive bid process. The RSP was filed by the Ohio Companies to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. In October 2004, the OCC and NOAC filed appeals with the Supreme Court of Ohio to overturn the original June 9, 2004 PUCO order in this proceeding as well as the associated entries on rehearing. On September 28, 2005, the Ohio Supreme Court heard oral argument on the appeals.

On May 27, 2005, TE filed an application with the PUCO to establish a GCAF rider under its RSP. The application seeks to implement recovery of increased fuel costs from 2006 through 2008 applicable to TE’s retail customers through a tariff rider to be implemented January 1, 2006. The application reflects projected increases in fuel costs in 2006 compared to 2002 baseline costs. The new rider, after adjustments made in testimony, is seeking to recover all costs above the baseline (approximately $88 million in 2006 for all the Ohio Companies). Various parties including the OCC have intervened in this case and the case has been consolidated with the RCP application discussed below.

On September 9, 2005, TE filed an application with the PUCO that, if approved, would supplement its existing RSP with an RCP. On September 27, 2005, the PUCO granted FirstEnergy's motion to consolidate the GCAF rider application with the RCP proceedings and set hearings for the consolidated cases to begin November 29, 2005. The RCP is designed to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. Major provisions of the RCP include:

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

·    Defer and capitalize certain distribution costs to be incurred by all of the Ohio Companies during the  period January 1, 2006 through December 31, 2008, not to exceed $150 million in each of the three  years;

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

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

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·    Recover increased fuel costs of up to $75 million, $77 million, and $79 million, in 2006, 2007, and  2008, respectively, from all OE and TE distribution and transmission customers through a fuel  recovery mechanism. TE may defer and capitalize increased fuel costs above the amount collected  through the fuel recovery mechanism.

Under provisions of the RSP, the PUCO may require TE to undertake, no more often than annually, a competitive bid process to secure generation for the years 2007 and 2008. On July 22, 2005, FirstEnergy filed a competitive bid process for the period beginning in 2007 that is similar to the competitive bid process approved by the PUCO for TE in 2004, which resulted in the PUCO accepting no bids. Any acceptance of future competitive bid results would terminate the RSP pricing, with no accounting impacts to the RSP, and not until twelve months after the PUCO authorizes such termination. On September 28, 2005, the PUCO issued an Entry that essentially approved the Ohio Companies’ filing but delayed the proposed timing of the competitive bid process by four months, calling for the auction to be held on March 21, 2006.

On December 30, 2004, TE filed with the PUCO two applications related to the recovery of transmission and ancillary service related costs. The first application seeks recovery of these costs beginning January 1, 2006. At the time of filing the application, these costs were estimated to be approximately $0.1 million per year; however, TE anticipates that this amount will increase. TE requested that these costs be recovered through a rider that would be effective on January 1, 2006 and adjusted each July 1 thereafter. TE reached a settlement with OCC, PUCO staff, Industrial Energy Users - Ohio and OPAE. The only other party in this proceeding, Dominion Retail, Inc., agreed not to oppose the settlement. This settlement, which was filed with the PUCO on July 22, 2005, provides for the rider recovery requested by TE, with carrying charges applied in the subsequent year’s rider for any over or under collection while the then-current rider is in effect. The PUCO approved the settlement stipulation on August 31, 2005. The incremental Transmission and Ancillary service revenues expected to be recovered from January through June 2006 are approximately $6.7 million. This value includes the recovery of the 2005 deferred MISO expenses as described below. In May 2006, TE will file a modification to the rider which will determine revenues from July 2006 through June 2007.

The second application seeks authority to defer costs associated with transmission and ancillary service related costs incurred during the period from October 1, 2003 through December 31, 2005. On May 18, 2005, the PUCO granted the accounting authority for TE to defer incremental transmission and ancillary service-related charges incurred as a participant in the MISO, but only for those costs incurred during the period December 30, 2004 through December 31, 2005. Permission to defer costs incurred prior to December 31, 2004 was denied. The PUCO also authorized TE to accrue carrying charges on the deferred balances. An application filed with the PUCO to recover these deferred charges over a five-year period through the rider, beginning in 2006, was approved in a PUCO order issued on August 31, 2005. The OCC, OPAE and TE each filed applications for rehearing. TE sought authority to defer the transmission and ancillary service related costs incurred during the period October 1, 2003 through December 29, 2004, while both OCC and OPAE sought to have the PUCO deny deferral of all costs. On July 6, 2005, the PUCO denied TE's and OCC’s applications and, at the request of TE, struck as untimely OPAE’s application. The OCC filed a notice of appeal with the Ohio Supreme Court on August 31, 2005. On September 30, 2005, in accordance with appellate procedure, the PUCO filed with the Ohio Supreme Court the record in this case. The Companies' brief will be due thirty days after the OCC files its brief, which, absent any time extensions, must be filed no later than November 9, 2005.

TE records as regulatory assets costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, the costs would have been charged to income when incurred. TE's regulatory assets as of September 30, 2005 and December 31, 2004, were $310 million and $375 million, respectively. TE is deferring customer shopping incentives and interest costs as new regulatory assets in accordance with its transition and rate stabilization plans. These regulatory assets total $122 million as of September 30, 2005 and, under the RSP, will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. See Note 14 “Regulatory Matters - Ohio” for the estimated net amortization of regulatory transition costs and deferred shopping incentive balances under the proposed RCP and current RSP.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Ohio.

Environmental Matters

TE 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 TE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

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National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulation 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) in all cases from the 2003 levels. TE's Ohio and Pennsylvania fossil-fired generation facilities will be subject to the 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 TE operates affected facilities.

Mercury Emissions

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On March 14, 2005, the EPA finalized the “Clean Air Mercury Rule,” which provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially, mercury emissions will be capped nationally at 38 tons by 2010 as a "co-benefit" from implementation of 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 Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (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 Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

TE cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by TE is lower than many regional competitors due to TE's diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

Regulation of Hazardous Waste

TE has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $0.2 million as of September 30, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

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Other Legal Proceedings

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

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

FirstEnergy companies also are defending six separate complaint cases before the PUCO relating to the August 14, 2003 power outage. Two such cases were originally filed in Ohio State courts but subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In both such cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Of the four other pending PUCO complaint cases, three were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each such case, the carriers seek reimbursement against various FirstEnergy companies (and, in one case, against PJM, MISO and American Electric Power Co. as well) for claims they paid to their insureds allegedly due to the loss of power on August 14, 2003. The listed insureds in these cases, in many instances, are not customers of any FirstEnergy company. The fourth case involves the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003. In addition to these six cases, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages. No estimate of potential liability has been undertaken for any of these cases.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

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FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station, in which TE has a 48.62% interest. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. On May 11, 2005, FENOC received a subpoena for documents related to outside meetings attended by Davis-Besse personnel on corrosion and cracking of control rod drive mechanisms and additional root cause evaluations.

On April 21, 2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to the degradation of the Davis-Besse reactor vessel head issue described above. TE accrued $1.0 million for a potential fine prior to 2005 and accrued the remaining liability for its share of the proposed fine of $1.65 million during the first quarter of 2005. On September 14, 2005, FENOC filed its response to the NOV with the NRC. FENOC accepted full responsibility for the past failure to properly implement its boric acid corrosion control and corrective action programs. The NRC NOV indicated that the violations do not represent current licensee performance. FirstEnergy paid the penalty in the third quarter of 2005.

If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability based on events surrounding Davis-Besse, it could have a material adverse effect on FirstEnergy's or any of its subsidiaries' financial condition, results of operations and cash flows.

Effective July 1, 2005 the NRC oversight panel for Davis-Besse was terminated and Davis-Besse returned to the standard NRC reactor oversight process. At that time, NRC inspections were augmented to include inspections to support the NRC's Confirmatory Order dated March 8, 2004 that was issued at the time of startup and to address an NRC White Finding related to the performance of the emergency sirens.

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 effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which TE has a 19.91% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry 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. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

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

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

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

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

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

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

EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with TE’s current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for TE in the fourth quarter of 2005. TE is currently evaluating the effect this Interpretation will have on its financial statements.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. TE will adopt this Statement effective January 1, 2006.

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SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for TE. This FSP is not expected to have a material impact on TE’s financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by TE beginning January 1, 2006. TE is currently evaluating this Standard and does not expect it to have a material impact on its financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. TE is currently evaluating this FSP and any impact on its investments.

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PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
STATEMENTS OF INCOME
OPERATING REVENUES	$	145,540		$	143,340		$	414,306		$	420,578
OPERATING EXPENSES AND TAXES:
Fuel		6,205			6,347			17,351			18,408
Purchased power		42,242			44,096			131,948			136,699
Nuclear operating costs		16,997			19,934			56,710			55,737
Other operating costs		19,030			16,212			48,541			45,371
Provision for depreciation		3,847			3,556			11,351			10,390
Amortization of regulatory assets		9,784			9,979			29,499			30,082
General taxes		6,836			6,416			19,752			17,538
Income taxes		17,402			16,541			43,055			46,425
Total operating expenses and taxes		122,343			123,081			358,207			360,650
OPERATING INCOME		23,197			20,259			56,099			59,928
OTHER INCOME (net of income taxes)		549			745			623			2,287
NET INTEREST CHARGES:
Interest expense		2,371			1,911			7,477			7,434
Allowance for borrowed funds used during construction		(1,665	)		(1,271	)		(4,508	)		(3,197	)
Net interest charges		706			640			2,969			4,237
NET INCOME		23,040			20,364			53,753			57,978
PREFERRED STOCK DIVIDEND REQUIREMENTS		156			639			1,534			1,919
EARNINGS ON COMMON STOCK	$	22,884		$	19,725		$	52,219		$	56,059
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	23,040		$	20,364		$	53,753		$	57,978
OTHER COMPREHENSIVE INCOME		-			-			-			-
TOTAL COMPREHENSIVE INCOME	$	23,040		$	20,364		$	53,753		$	57,978
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.

115

PENNSYLVANIA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2005			2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	907,382		$	866,303
Less - Accumulated provision for depreciation		378,707			356,020
		528,675			510,283
Construction work in progress -
Electric plant		133,790			104,366
Nuclear fuel		10,428			3,362
		144,218			107,728
		672,893			618,011
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		146,706			143,062
Long-term notes receivable from associated companies		32,864			32,985
Other		502			722
		180,072			176,769
CURRENT ASSETS:
Cash and cash equivalents		24			38
Notes receivable from associated companies		566			431
Receivables -
Customers (less accumulated provisions of $1,066,000 and $888,000,
respectively, for uncollectible accounts)		44,990			44,282
Associated companies		6,206			23,016
Other		2,617			1,656
Materials and supplies, at average cost		37,974			37,923
Prepayments and other		12,110			8,924
		104,487			116,270
DEFERRED CHARGES		10,721			10,106
	$	968,173		$	921,156
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, $30 par value, authorized 6,500,000 shares -
6,290,000 shares outstanding	$	188,700		$	188,700
Other paid-in capital		65,035			64,690
Accumulated other comprehensive loss		(13,706	)		(13,706	)
Retained earnings		131,914			87,695
Total common stockholder's equity		371,943			327,379
Preferred stock		14,105			39,105
Long-term debt and other long-term obligations		121,170			133,887
		507,218			500,371
CURRENT LIABILITIES:
Currently payable long-term debt		25,774			26,524
Short-term borrowings -
Associated companies		34,821			11,852
Accounts payable -
Associated companies		16,864			46,368
Other		1,884			1,436
Accrued taxes		26,163			14,055
Accrued interest		1,635			1,872
Other		8,491			8,802
		115,632			110,909
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		79,801			93,418
Asset retirement obligation		155,959			138,284
Retirement benefits		51,389			49,834
Regulatory liabilities		47,809			18,454
Other		10,365			9,886
		345,323			309,876
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	968,173		$	921,156
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these balance sheets.

116

PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	23,040		$	20,364		$	53,753		$	57,978
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		3,847			3,556			11,351			10,390
Amortization of regulatory assets		9,784			9,979			29,499			30,082
Nuclear fuel and other amortization		4,634			4,550			12,912			13,546
Deferred income taxes and investment tax credits, net		(2,612	)		(501	)		(7,567	)		(2,852	)
Pension trust contribution		-			(12,934	)		-			(12,934	)
Decrease (increase) in operating assets -
Receivables		4,303			(30,285	)		15,141			(10,551	)
Materials and supplies		755			(1,078	)		(51	)		(3,374	)
Prepayments and other current assets		5,074			4,164			(3,186	)		(3,977	)
Increase (decrease) in operating liabilities -
Accounts payable		(9,161	)		40,306			(29,056	)		21,678
Accrued taxes		5			(2,485	)		12,108			2,301
Accrued interest		(353	)		(986	)		(237	)		(2,415	)
Other		564			1,353			1,027			5,294
Net cash provided from operating activities		39,880			36,003			95,694			105,166
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Short-term borrowings, net		-			-			22,969			10,789
Equity contribution from parent		-			25,000			-			25,000
Redemptions and Repayments -
Preferred stock		-			-			(37,750	)		-
Long-term debt		(39	)		(20,508	)		(849	)		(63,297	)
Short-term borrowings, net		(10,776	)		(11,414	)		-			-
Dividend Payments -
Common stock		-			-			(8,000	)		(23,000	)
Preferred stock		(156	)		(639	)		(1,534	)		(1,919	)
Net cash used for financing activities		(10,971	)		(7,561	)		(25,164	)		(52,427	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(28,537	)		(24,670	)		(69,630	)		(56,080	)
Contributions to nuclear decommissioning trusts		(399	)		(399	)		(1,196	)		(1,196	)
Loan repayments from (loans to) associated companies		(187	)		(36	)		(14	)		5,975
Other		214			(3,337	)		296			(1,440	)
Net cash used for investing activities		(28,909	)		(28,442	)		(70,544	)		(52,741	)
Net change in cash and cash equivalents		-			-			(14	)		(2	)
Cash and cash equivalents at beginning of period		24			38			38			40
Cash and cash equivalents at end of period	$	24		$	38		$	24		$	38
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an integral part of these statements.

117

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Pennsylvania Power Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Power Company and its subsidiary as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 1, 2005

118

PENNSYLVANIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Penn is a wholly owned, electric utility subsidiary of OE. Penn conducts business in western Pennsylvania, providing regulated electric distribution services. Penn also provides generation services to those customers electing to retain Penn as their power supplier. Penn provides power directly to wholesale customers under previously negotiated contracts. Penn has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Its power supply requirements are provided by FES - an affiliated company.

Results of Operations

Earnings on common stock in the third quarter of 2005 increased to $23 million from $20 million in the third quarter of 2004. The increased earnings resulted primarily from higher operating revenues and lower operating expenses and taxes. Earnings on common stock for the first nine months of 2005 decreased to $52 million from $56 million for the same period of 2004. The lower earnings resulted primarily from a decrease in operating revenues and other income, partially offset by lower operating expenses and taxes and lower net interest charges.

Operating revenues increased by $2 million, or 1.5%, in the third quarter of 2005 compared with the third quarter of 2004. Higher revenues in the third quarter of 2005 primarily resulted from increased retail generation sales revenues of $6 million and a $2 million increase in rental revenues, partially offset by a $6 million decrease in wholesale sales to FES. Retail generation sales increased as a result of increased KWH sales to residential (7.6%) and commercial (4.0%) customers, due to warmer weather in Penn's service area, and a 19.8% KWH sales increase to industrial customers, primarily within the steel sector.

Revenues from distribution deliveries in the third quarter of 2005 increased slightly from the third quarter of 2004, as lower unit prices partially offset a 10.2% increase in KWH sales. The lower unit prices were primarily attributable to changes in Penn's CTC rate schedules in April 2005 as a result of the annual CTC reconciliation. Increased revenues from distribution deliveries to residential ($0.3 million) and industrial ($0.8 million) customers were offset by a $1 million decrease in revenues from commercial customers.

Operating revenues decreased by $6 million in the first nine months of 2005 compared with the same period of 2004. The lower operating revenues reflected a $24 million decrease in wholesale sales to FES, partially offset by higher retail sales of $14 million. Higher retail electric generation revenues of $14 million resulted from increased KWH sales to all sectors (Residential - 8.0%, Commercial - 5.6% and Industrial - 1.5%) and higher unit prices for commercial and industrial customers.

In the first nine months of 2005, revenues from distribution deliveries increased by $0.3 million compared to the same period of 2004. An increase in total KWH deliveries of 5.0% was offset by lower unit prices, reflecting the changes in Penn's CTC rates discussed above. Increased revenues from distribution deliveries to residential customers of $4 million were partially offset by lower revenues from commercial ($1 million) and industrial ($2 million) customers.

Changes in kilowatt-hour sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:

	Three			Nine
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		10.2	%		5.0	%
Wholesale		(1.4	)%		(5.5	)%
Total Electric Generation Sales		3.1	%		(1.4	)%
Distribution Deliveries:
Residential		7.6	%		8.0	%
Commercial		4.0	%		5.6	%
Industrial		19.8	%		1.5	%
Total Distribution Deliveries		10.2	%		5.0	%

119

Operating Expenses and Taxes

Total operating expenses and taxes decreased by $1 million in the third quarter and $2 million in the first nine months of 2005 from the same periods of 2004. The following table presents changes from the prior year by expense category.

	Three			Nine
Operating Expenses and Taxes - Changes	Months			Months
	(In millions)
Increase (Decrease)
Fuel costs	$	-		$	(1	)
Purchased power costs		(2	)		(4	)
Nuclear operating costs		(3	)		1
Other operating costs		3			3
General taxes		-			2
Income taxes		1			(3	)
Net decrease in operating expenses and taxes	$	(1	)	$	(2	)

The decrease in purchased power costs in the three months and nine months ended September 30, 2005 resulted from lower unit prices for power. Nuclear operating costs were lower in the third quarter of 2005, reflecting a decrease in labor and postretirement benefit expenses from the third quarter of 2004. Other operating costs were higher in the three months and nine months ended September 30, 2005 as the result of increased transmission related expenses associated with MISO's energy market that began on April 1, 2005.

Other Income

Other income (net of income taxes) decreased slightly in the third quarter and by $2 million in the first nine months of 2005, compared with the same periods in 2004. The decrease in the nine month period reflects liabilities recognized in the first quarter of 2005 related to the W. H. Sammis Plant settlement (see Outlook - Environmental Matters).

Net Interest Charges

Net interest charges decreased by $1 million in the nine months ended September 30, 2005 from the corresponding period last year, reflecting redemptions of $40 million principal amount of debt securities since October 1, 2004.

Capital Resources and Liquidity

Penn’s cash requirements for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met with a combination of cash from operations and funds from the capital markets. Borrowing capacity under credit facilities is available to manage working capital requirements.

Changes in Cash Position

As of September 30, 2005, Penn had $24,000 of cash and cash equivalents, compared with $38,000 as of December 31, 2004. The major changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities in the three months and nine months ended September 30, 2005, compared with the corresponding 2004 periods, was as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Cash Flows	2005		2004			2005			2004
	(In millions)
Cash earnings (1)	$	40	$	34		$	101		$	108
Pension trust contribution(2)		-		(8	)		-			(8	)
Working capital and other		-		10			(5	)		5
Total cash flows from operating activities	$	40	$	36		$	96		$	105
(1) Cash earnings is a non-GAAP measure (see reconciliation below). (2) Pension trust contribution net of $5 million of income tax benefits.

120

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	(In millions)
Net income (GAAP)	$	23		$	20		$	54		$	58
Non-cash charges (credits):
Provision for depreciation		4			4			11			10
Amortization of regulatory assets		10			10			29			30
Nuclear fuel and other amortization		5			4			13			14
Deferred income taxes and investment tax credits, net		(3	)		(5	)		(8	)		(8	)
Other non-cash items		1			1			2			4
Cash earnings (Non-GAAP)	$	40		$	34		$	101		$	108

The $6 million increase in cash earnings in the third quarter of 2005 and the $7 million decrease in cash earnings for the first nine months of 2005, as compared to the corresponding periods of 2004, are described under “Results of Operations.” The $10 million change in working capital and other in the three-month period was primarily due to a $49 million change in accounts payable, partially offset by changes of $35 million in receivables, $2 million in materials and supplies, and $2 million in accrued taxes. The $10 million change in working capital and other in the nine-month period was primarily due to a $51 million change in accounts payable, partially offset by changes of $26 million in receivables, $3 million in materials and supplies, and $10 million in accrued taxes.

Cash Flows From Financing Activities

Net cash used for financing activities totaled $11 million in the third quarter of 2005, compared with $8 million in the same period last year. The $3 million increase resulted primarily from the absence of a $25 million equity contribution from OE in the third quarter of 2004, partially offset by a $21 million decrease in debt redemptions and repayments in the third quarter of 2005.

Net cash used for financing activities totaled $25 million in the nine months ended September 30, 2005, compared with $52 million in the same period last year. The $27 million decrease resulted primarily from reduced long-term debt redemptions and common stock dividend payments in the first nine months of 2005, offset by reduced short-term borrowings and OE's $25 million equity contribution in 2004.

On May 16, 2005, Penn redeemed all 127,500 outstanding shares of 7.625% preferred stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred stock at $100 per share, both plus accrued dividends to the date of redemption. The total par value of the preferred stock redeemed was $37.8 million.

Penn had $590,000 of cash and temporary investments (which included short-term notes receivable from associated companies) and $35 million of short-term indebtedness as of September 30, 2005. Penn has authorization from the SEC to incur short-term debt up to its charter limit of $51 million. As of October 24, 2005, Penn had the capability to issue approximately $520 million of additional FMB on the basis of property additions and retired bonds following the recently completed intra-system transfer of fossil generating plants (See Note 17) . Based upon applicable earnings coverage tests, Penn could issue up to $383 million of preferred stock (assuming no additional debt was issued) as of September 30, 2005. It is estimated that the annualized impact of the intra-system transfer of fossil generating plants will reduce the capability of Penn to issue preferred stock by approximately 14%. The above financing capabilities do not take into consideration changes related to the intercompany transfer of generating assets (see Note 17).

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing and the commitment termination date, as the same may be extended. Penn's borrowing limit under the facility is $51 million.

Penn has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings under these arrangements in the third quarter of 2005 was 3.50%.

121

Penn Power Funding LLC (Penn Funding), a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. Penn Funding can borrow up to $25 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penn. The facility was not drawn as of September 30, 2005. On July 15, 2005, the facility was renewed until June 29, 2006. The annual facility fee is 0.25% on the entire finance limit.

Penn’s access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of OE and FirstEnergy.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows From Investing Activities

Net cash used in investing activities totaled $29 million in the third quarter of 2005, compared with $28 million in the third quarter of 2004. For the nine months ended September 30, 2005, net cash used in investing activities totaled $71 million, compared with $53 million in the same period last year. The $18 million increase was primarily the result of higher expenditures for property additions in 2005 and reduced loan repayments from associated companies.

In the last quarter of 2005, capital requirements for property additions are expected to be about $32 million. Penn also expects to contribute up to $63 million (unfunded liability recognized as of September 30, 2005) for nuclear decommissioning in connection with the generation asset transfers described below, and has additional requirements of $0.5 million to meet sinking fund requirements for long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Penn's capital spending for the period 2005-2007 is expected to be about $227 million, of which approximately $87 million applies to 2005. Penn had no other material obligations as of September 30, 2005 that have not been recognized on its Consolidated Balance Sheet.

On July 22, 2005, the Philadelphia Stock Exchange (Exchange) filed an application with the SEC for termination of the listing of the following three series of Penn’s cumulative preferred stock, $100 par value, as such series no longer met the Exchange’s technical listing requirements regarding the number of outstanding shares and the number of holders: 4.24% Series, 4.25% Series and 4.64% Series. On August 17, 2005, the SEC granted the Exchange's application for delisting effective August 18, 2005.

Equity Price Risk

Included in Penn’s nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $60 million and $57 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of September 30, 2005.

FirstEnergy Intra-System Generation Asset Transfers

On May 13, 2005, Penn entered into an agreement to transfer its ownership interests in its nuclear and fossil generating facilities to NGC and FGCO, respectively.

122

On October 24, 2005, Penn completed the transfer of fossil generation assets to FGCO. Penn currently expects to complete the transfer of nuclear generation assets to NGC through a spin-off by way of dividend before the end of 2005. Consummation of the nuclear transfer remains subject to necessary regulatory approvals.

These transactions are being undertaken in connection with Penn’s restructuring plan that was approved by the PPUC under applicable Pennsylvania electric utility restructuring legislation. Consistent with the restructuring plan, Penn’s generation assets were required to be separated from the regulated delivery business through transfers to a separate corporate entity. FENOC currently operates and maintains the nuclear generation assets to be transferred. FGCO, as lessee under a Master Facility Lease, leased, operated and maintained the non-nuclear generation assets that it now owns. The transactions will essentially complete the divestitures contemplated by the restructuring plan by transferring the ownership interests to NGC and FGCO, respectively, without impacting the operation of the plants.

See Note 17 to the consolidated financial statements for disclosure of Penn's assets held for sale as of September 30, 2005.

Regulatory Matters

Regulatory assets and liabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Penn's net regulatory liabilities were approximately $48 million and $18 million as of September 30, 2005 and December 31, 2004, respectively, and are included in Noncurrent Liabilities on the Consolidated Balance Sheets.

In October 11, 2005, Penn filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. Penn is recommending that the Request for Proposal process cover the period of January 1, 2007 through May 31, 2008. Under Pennsylvania's electric competition law, Penn is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability initiatives.

Environmental Matters

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

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

National Ambient Air Quality Standards

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On March 10, 2005, the EPA finalized the "Clean Air Interstate Rule" covering a total of 28 states (including 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 nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR provides each affected state until 2006 to develop implementing regulations to achieve additional reductions of NO_x and SO₂ emissions in two phases (Phase I in 2009 for NO_x, 2010 for SO₂ and Phase II in 2015 for both NO_x and SO₂), in all cases from the 2003 levels. Penn's Ohio and Pennsylvania fossil-fired generation facilities will be subject to the 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 Penn 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. On March 14, 2005, the EPA finalized the "Clean Air Mercury Rule," 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 Clean Air Mercury rule have been challenged in the United States Court of Appeals for the District of Columbia. Future cost of compliance with these regulations may be substantial.

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement, which is in the form of a Consent Decree, was approved by the Court on July 11, 2005, requires OE and Penn to reduce NO_x and SO₂ emission at W. H. Sammis Plant and other coal-fired plants through the installation of pollution control devices. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million, of which Penn's share was $0.7 million. Results for the first quarter of 2005 included the $0.7 million penalty payable by Penn and a $0.8 million liability for probable future cash contributions toward environmentally beneficial projects.

Climate Change

In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18 percent through 2012. The Energy Policy Act of 2005 established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.

Penn cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per KWH of electricity generated by Penn is lower than many regional competitors due to Penn's diversified generation sources which include low or non-CO₂ emitting gas-fired and nuclear generators.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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

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On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

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 effective corrective action. FENOC operates the Perry Nuclear Power Plant, in which Penn currently has a 5.24% interest (however, see Note 17 regarding FirstEnergy’s pending intra-system generation asset transfers, which will include owned portions of the plant).

On April 4, 2005, the NRC held a public meeting to discuss FENOC’s performance at the Perry Nuclear Power Plant as identified in the NRC's annual assessment letter to FENOC. Similar public meetings are held with all nuclear power plant licensees following issuance by the NRC of their annual assessments. According to the NRC, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. During the public meeting and in the annual assessment, the NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix.

125

On May 26, 2005, the NRC held a public meeting to discuss its oversight of the Perry Plant. While the NRC stated that the plant continued to operate safely, the NRC also stated that the overall performance had not substantially improved since the heightened inspection was initiated. The NRC reiterated this conclusion in its mid-year assessment letter dated August 30, 2005. On September 28, 2005, the NRC sent a CAL to FENOC describing commitments that FENOC had made to improve the performance of Perry 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. If performance does not improve, the NRC has a range of options under the Reactor Oversight Process, from increased oversight to possible impact to the plant’s operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

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

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

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for Penn in the fourth quarter of 2005. Penn is currently evaluating the effect this Interpretation will have on its financial statements.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Penn will adopt this Statement effective January 1, 2006.

SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for Penn. This FSP is not expected to have a material impact on Penn's financial statements.

126

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by Penn beginning January 1, 2006. Penn is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. Penn is currently evaluating this FSP and any impact on its investments.

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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
STATEMENTS OF INCOME
OPERATING REVENUES	$	900,247		$	706,613		$	2,024,630		$	1,754,402
OPERATING EXPENSES AND TAXES:
Purchased power		517,212			387,282			1,115,737			943,757
Other operating costs		112,690			91,516			293,996			259,176
Provision for depreciation		19,659			18,435			59,721			56,603
Amortization of regulatory assets		84,388			84,271			223,012			216,705
Deferral of new regulatory assets		-			-			(27,765	)		-
General taxes		19,538			17,901			49,802			48,571
Income taxes		55,729			35,099			110,578			70,555
Total operating expenses and taxes		809,216			634,504			1,825,081			1,595,367
OPERATING INCOME		91,031			72,109			199,549			159,035
OTHER INCOME (net of income taxes)		3,014			1,996			3,331			4,603
NET INTEREST CHARGES:
Interest on long-term debt		18,162			21,709			56,843			62,240
Allowance for borrowed funds used during construction		(497	)		(169	)		(1,337	)		(440	)
Deferred interest		(1,069	)		(871	)		(2,896	)		(2,685	)
Other interest expense		2,283			1,105			5,262			1,958
Net interest charges		18,879			21,774			57,872			61,073
NET INCOME		75,166			52,331			145,008			102,565
PREFERRED STOCK DIVIDEND REQUIREMENTS		125			125			375			375
EARNINGS ON COMMON STOCK	$	75,041		$	52,206		$	144,633		$	102,190
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	75,166		$	52,331		$	145,008		$	102,565
OTHER COMPREHENSIVE INCOME:
Unrealized gain on derivative hedges		102			173			208			217
Unrealized loss on available for sale securities		-			-			-			(8	)
Other comprehensive income		102			173			208			209
Income tax expense (benefit) related to other comprehensive income		42			(1,542	)		85			(1,546	)
Other comprehensive income, net of tax		60			1,715			123			1,755
TOTAL COMPREHENSIVE INCOME	$	75,226		$	54,046		$	145,131		$	104,320
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral part of these statements.

128

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2005			2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	3,840,213		$	3,730,767
Less - Accumulated provision for depreciation		1,424,801			1,380,775
		2,415,412			2,349,992
Construction work in progress		85,335			75,012
		2,500,747			2,425,004
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		143,937			138,205
Nuclear fuel disposal trust		164,070			159,696
Long-term notes receivable from associated companies		19,751			20,436
Other		16,597			19,379
		344,355			337,716
CURRENT ASSETS:
Cash and cash equivalents		571			162
Receivables -
Customers (less accumulated provisions of $4,264,000 and $3,881,000,
respectively, for uncollectible accounts)		313,730			201,415
Associated companies		1,171			86,531
Other (less accumulated provisions of $239,000 and $162,000,
respectively, for uncollectible accounts)		38,569			39,898
Materials and supplies, at average cost		1,863			2,435
Prepayments and other		33,254			31,489
		389,158			361,930
DEFERRED CHARGES:
Regulatory assets		2,310,532			2,176,520
Goodwill		1,983,699			1,985,036
Other		2,850			4,978
		4,297,081			4,166,534
	$	7,531,341		$	7,291,184
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, $10 par value, authorized 16,000,000 shares -
15,371,270 shares outstanding	$	153,713		$	153,713
Other paid-in capital		3,014,600			3,013,912
Accumulated other comprehensive loss		(55,411	)		(55,534	)
Retained earnings		104,904			43,271
Total common stockholder's equity		3,217,806			3,155,362
Preferred stock		12,649			12,649
Long-term debt and other long-term obligations		1,017,478			1,238,984
		4,247,933			4,406,995
CURRENT LIABILITIES:
Currently payable long-term debt		167,045			16,866
Notes payable -
Associated companies		114,932			248,532
Accounts payable -
Associated companies		8,968			20,605
Other		162,583			124,733
Accrued taxes		78,342			2,626
Accrued interest		23,535			10,359
Other		152,638			65,130
		708,043			488,851
NONCURRENT LIABILITIES:
Power purchase contract loss liability		1,410,659			1,268,478
Accumulated deferred income taxes		670,514			645,741
Nuclear fuel disposal costs		173,591			169,884
Asset retirement obligation		76,002			72,655
Retirement benefits		100,567			103,036
Other		144,032			135,544
		2,575,365			2,395,338
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	7,531,341		$	7,291,184
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are anintegral part of these blance sheets.

129

JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	75,166		$	52,331		$	145,008		$	102,565
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		19,659			18,436			59,721			56,603
Amortization of regulatory assets		84,388			84,269			223,012			216,704
Deferral of new regulatory assets		-			-			(27,765	)		-
Deferred purchased power and other costs		(42,381	)		(77,162	)		(168,646	)		(155,552	)
Deferred income taxes and investment tax credits, net		(11,222	)		6,165			5,204			(13,582	)
Accrued retirement benefit obligation		813			2,888			(2,468	)		(5,880	)
Accrued compensation, net		671			1,547			(4,077	)		731
NUG power contract restructuring		-			-			-			52,800
Cash collateral from suppliers		76,978			-			76,978			-
Pension trust contribution		-			(62,499	)		-			(62,499	)
Decrease (increase) in operating assets -
Receivables		(39,897	)		(34,749	)		(25,626	)		(26,906	)
Materials and supplies		395			64			572			411
Prepayments and other current assets		64,761			34,664			(1,764	)		(5,040	)
Increase (decrease) in operating liabilities -
Accounts payable		(5,873	)		57,485			26,214			58,430
Accrued taxes		18,498			(27,924	)		75,716			35,844
Accrued interest		13,765			16,709			13,176			11,481
Other		6,928			27,603			23,982			8,539
Net cash provided from operating activities		262,649			99,827			419,237			274,649
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			-			-			300,000
Redemptions and Repayments-
Long-term debt		(4,321	)		(7,082	)		(67,648	)		(304,150	)
Short-term borrowings, net		(164,172	)		(456	)		(133,600	)		(72,648	)
Dividend Payments-
Common stock		(43,000	)		(40,000	)		(83,000	)		(60,000	)
Preferred stock		(125	)		(125	)		(375	)		(375	)
Net cash used for financing activities		(211,618	)		(47,663	)		(284,623	)		(137,173	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(50,837	)		(52,507	)		(133,498	)		(135,932	)
Loan repayments from (loans to) associated companies, net		15			(711	)		685			(1,122	)
Other		(50	)		1,049			(1,392	)		(416	)
Net cash used for investing activities		(50,872	)		(52,169	)		(134,205	)		(137,470	)
Net increase (decrease) in cash and cash equivalents		159			(5	)		409			6
Cash and cash equivalents at beginning of period		412			282			162			271
Cash and cash equivalents at end of period	$	571		$	277		$	571		$	277
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral  part of these statements.

130

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Jersey Central

Power & Light Company:

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 9 to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 1, 2005

131

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier. JCP&L has restructured its electric rates into unbundled service charges and transition cost recovery charges. JCP&L continues to deliver power to homes and businesses through its existing distribution system.

Results of Operations

Earnings on common stock in the third quarter of 2005 increased to $75 million from $52 million in the third quarter of 2004. During the first nine months of 2005, earnings on common stock increased to $145 million compared to $102 million for the same period of 2004. The increase in earnings for both periods was primarily due to higher operating revenues partially offset by increases in purchased power costs, other operating costs and income taxes. Other operating costs in both periods of 2005 included a charge of $16 million for potential awards related to a labor arbitration decision (see note 13 - Other Legal Matters).

Operating revenues increased $194 million or 27.4% in the third quarter and $270 million or 15.4% in the first nine months of 2005 compared with the same periods in 2004. Increases in both periods were due to higher retail electric generation, distribution and wholesale revenues.

Retail generation revenues increased by $82 million in the third quarter and $134 million in the first nine months of 2005 as compared to the previous year. Higher KWH sales to residential and commercial customers increased generation revenues by $45 million in the third quarter and $81 million in the first nine months of 2005. Commercial generation revenue increased for the same periods of 2005 by $33 million and $54 million, respectively. The increases were attributable to higher KWH sales (residential - 14.9% and commercial - 20.3% in the third quarter of 2005; residential - 15.3% and commercial - 13.4% for the first nine months of 2005) primarily due to warmer weather and reduced customer shopping. Generation provided by alternative suppliers to residential and commercial customers as a percent of total sales delivered in JCP&L’s service area decreased by 6.9 and 4.6 percentage points, respectively, in the first nine months of 2005. Industrial generation revenue increased by $4 million in the third quarter, but declined $2 million in the first nine months of 2005 reflecting the effect of a 25.6% KWH sales increase in the third quarter and a 9.3% decline in the first nine months of 2005.

Revenues from wholesale sales increased by $49 million in the third quarter and $42 in the first nine months of 2005 as compared to the previous year, principally due to increased prices in 2005. KWH sales to the wholesale sector increased in the quarter (5.5%) but declined for the first nine months (8.5%).

Distribution revenues increased by $62 million in the third quarter and $96 million in the first nine months of 2005, as compared to the same periods of 2004, due to increased KWH deliveries to all customer sectors and higher composite unit prices, caused in part by the June 1, 2005 rate increase.

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 compared to the same periods of 2004 are summarized in the following table:

	Three			Nine
Changes in KWH Sales	Months			Months
Increase (Decrease)
Electric Generation:
Retail		17.2	%		13.4	%
Wholesale		5.5	%		(8.5	)%
Total Electric Generation Sales		14.8	%		8.2	%
Distribution Deliveries:
Residential		15.6	%		7.4	%
Commercial		13.4	%		6.7	%
Industrial		5.4	%		0.4	%
Total Distribution Deliveries		13.4	%		6.2	%

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Operating Expenses and Taxes

Total operating expenses and taxes increased by $175 million in the third quarter and $230 million in the first nine months of 2005 compared with the same periods of 2004. The following table presents changes from the prior year by expense category.

	Three		Nine
Operating Expenses and Taxes - Changes	Months		Months
	(In millions)
Increase (Decrease)
Purchased power costs	$	130	$	172
Other operating costs		21		35
Provision for depreciation		1		3
Amortization of regulatory assets		-		7
Deferral of new regulatory assets		-		(28	)
General taxes		2		1
Income taxes		21		40
Net increase in operating expenses and taxes	$	175	$	230

Purchased power costs increased by $130 million in the third quarter and $172 million in the first nine months of 2005 as compared to the same periods in 2004 due to higher KWH purchases to meet increased retail generation sales and, to a lesser extent, higher unit costs. Other operating costs increased $21 million in the third quarter of 2005 and $35 million in the first nine months of 2005 compared to the same periods of 2004, reflecting $16 million of expenses resulting from a JCP&L arbitration decision.

Deferral of new regulatory assets decreased expenses by $28 million in the first nine months of 2005, reflecting the NJBPU’s (see Regulatory Matters) approval for JCP&L to defer $28 million of previously incurred reliability expenses. Amortization of regulatory assets increased $7 million in the first nine months of 2005 due to an increase in the level of MTC revenue recovery.

Capital Resources and Liquidity

JCP&L’s cash requirements for the remainder of 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with cash from operations.

Changes in Cash Position

As of September 30, 2005, JCP&L had $571,000 of cash and cash equivalents compared with $162,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Cash provided from operating activities in the third quarter and in the first nine months of 2005 compared with the corresponding periods of 2004, were as follows:

 

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Cash Flows	2005		2004			2005		2004
	(In millions)
Cash earnings (1)	$	204	$	64		$	307	$	177
Pension trust contribution (2)		-		(37	)		-		(37	)
Working capital and other		58		73			112		135
Total cash flows from operating activities	$	262	$	100		$	419	$	275
(1) Cash earnings is a non-GAAP measure (see reconciliation below). (2) Pension trust contribution net of $25 million of income tax benefits.

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

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	(In millions)
Net income (GAAP)	$	75		$	52		$	145		$	103
Non-cash charges (credits):
Provision for depreciation		20			18			60			57
Amortization of regulatory assets		84			84			223			217
Deferral of new regulatory assets		-			-			(28	)		-
Deferred purchased power and other costs		(42	)		(77	)		(169	)		(156	)
Deferred income taxes & investment tax credits, net		(11	)		(19	)		5			(39	)
Other non-cash items		78			6			71			(5	)
Cash earnings (Non-GAAP)	$	204		$	64		$	307		$	177

The $140 million and $130 million increases in cash earnings for the third quarter and the first nine months of 2005, respectively, are described above under “Results of Operations”. The $15 million and $23 million decrease for the third quarter and the first nine months of 2005 from working capital primarily resulted from a reduction in accounts payables partially offset by an increase in accrued taxes. In the first nine months of 2004, JCP&L received $52.8 million in connection with restructuring a NUG power contract.

Cash Flows From Financing Activities

Net cash used for financing activities was $212 million in the third quarter of 2005 compared to $48 million in the third quarter of 2004. The increase resulted from redemptions of short-term debt in the third quarter of 2005. Net cash used for financing activities was $285 million for the first nine months of 2005 and $137 million for the same period of 2004. The $148 million increase resulted from a $124 million increase in net debt redemptions and a $23 million increase in common stock dividends to FirstEnergy.

JCP&L had approximately $571,000 of cash and temporary investments and $115 million of short-term indebtedness as of September 30, 2005. JCP&L has authorization from the SEC to incur short-term debt up to its charter limit of $1.8 billion (including the utility money pool). JCP&L will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) JCP&L from issuing any debt which is senior to the senior notes. As of September 30, 2005, JCP&L had the capability to issue $673 million of additional senior notes based upon FMB collateral. Based upon applicable earnings coverage tests and its charter, JCP&L could issue $976 million of preferred stock (assuming no additional debt was issued) as of September 30, 2005.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. JCP&L’s borrowing limit under the facility is $425 million.

JCP&L has the ability to borrow from FirstEnergy and its regulated affiliates to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings was 3.50% in the third quarter of 2005 and 3.03% in the first nine months of 2005.

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

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

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On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows From Investing Activities

Net cash used for investing activities was $51 million in the third quarter and $134 million for the first nine months of 2005 compared to $52 million and $137 million for the same periods of 2004. JCP&L’s capital spending for the period 2005-2007 is expected to be about $511 million of which approximately $185 million applies to 2005. In the last quarter of 2005, capital requirements for property additions and improvements are expected to be about $52 million.

Market Risk Information

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

Commodity Price Risk

JCP&L is exposed to price risk primarily due to fluctuating electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options and futures contracts. The derivatives are used for hedging purposes. Most of its non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of September 30, 2005, JCP&L had commodity derivative contracts with a fair value of $14 million. A decrease of $1 million in the value of this asset was recorded in the first nine months of 2005 as a decrease in a regulatory liability, and therefore, had no impact on net income.

The valuation of derivative commodity contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for valuation of derivative contracts as of September 30, 2005 are summarized by year in the following table:

Sources of Information -
Fair Value by Contract Year	2005(1)		2006		2007		2008		2009		Thereafter		Total
Prices based on external sources(2)	$	3	$	2	$	3	$	-	$	-	$	-	$	8
Prices based on models		-		-		-		2		2		2		6
Total	$	3	$	2	$	3	$	2	$	2	$	2	$	14
(1) For the last quarter of 2005. (2) Broker quote sheets.

JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2005.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current market value of approximately $82 million and $80 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of September 30, 2005.

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Regulatory Matters

Regulatory assets are costs which have been authorized by the NJBPU and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. JCP&L's regulatory assets as of September 30, 2005 and December 31, 2004 were $2.3 billion and $2.2 billion, respectively.

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of September 30, 2005, the accumulated deferred cost balance totaled approximately $508 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the July 31, 2003 deferred balance. JCP&L is in discussions with the NJBPU staff as a result of the stipulated settlement agreements (as further discussed below) which recommended that the NJBPU issue an order regarding JCP&L's application. On July 20, 2005, JCP&L requested the NJBPU to set a procedural schedule for this matter and is awaiting NJBPU action.

The 2003 NJBPU decision on JCP&L's base electric rate proceeding (the Phase I Order) disallowed certain regulatory assets and provided for an interim return on equity of 9.5% on JCP&L's rate base. The Phase I Order also provided for a Phase II proceeding in which the NJBPU would review whether JCP&L is in compliance with current service reliability and quality standards and determine whether the expenditures and projects undertaken by JCP&L to increase its system reliability are prudent and reasonable for rate recovery. Depending on its assessment of JCP&L's service reliability, the NJBPU could have increased JCP&L’s return on equity to 9.75% or decreased it to 9.25%. On August 15, 2003 and June 1, 2004, JCP&L filed with the NJBPU an interim motion and a supplemental and amended motion for rehearing and reconsideration of the Phase I Order, respectively. On July 7, 2004, the NJPBU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances; (2) the capital structure including the rate of return; (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs.

On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requested an increase to the MTC deferred balance recovery of approximately $20 million annually.

On May 25, 2005, the NJBPU approved two stipulated settlement agreements. The first stipulation between JCP&L and the NJBPU staff resolves all of the issues associated with JCP&L's motion for reconsideration of the Phase I Order. The second stipulation between JCP&L, the NJBPU staff and the Ratepayer Advocate resolves all of the issues associated with JCP&L's Phase II proceeding. The stipulated settlements provide for, among other things, the following:

· An annual increase in distribution revenues of $23 million effective June 1, 2005, associated with the

 Phase I Order reconsideration;

· An annual increase in distribution revenues of $36 million effective June 1, 2005, related to JCP&L's

 Phase II Petition;

· An annual reduction in both rates and amortization expense of $8 million, effective June 1, 2005, in

 anticipation of an NJBPU order regarding JCP&L's request to securitize up to $277 million of its deferred

 cost balance;

· An increase in JCP&L's authorized return on common equity from 9.5% to 9.75%; and

· A commitment by JCP&L to maintain a target level of customer service reliability with a reduction in

 JCP&L's authorized return on common equity from 9.75% to 9.5% if the target is not met for two

 consecutive quarters. The authorized return on common equity would then be restored to 9.75% if the

 target is met for two consecutive quarters.

The Phase II stipulation included an agreement that the distribution revenue increase also reflects a three-year amortization of JCP&L's one-time service reliability improvement costs incurred in 2003-2005. This resulted in the creation of a regulatory asset associated with accelerated tree trimming and other reliability costs which were expensed in 2003 and 2004. The establishment of the new regulatory asset of approximately $28 million resulted in an increase to net income of approximately $16 million ($0.05 per share of FirstEnergy common stock) in the second quarter of 2005.

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JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order for the period June 1, 2005 through May 31, 2006. New BGS tariffs reflecting the results of a February 2005 auction for the BGS supply became effective June 1, 2005. On July 1, 2005, JCP&L filed its BGS procurement proposals for post transition year four. The auction is scheduled to take place in February 2006 for the annual supply period beginning June 1, 2006.

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

As a result of outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had implemented reviews into JCP&L's service reliability. On March 29, 2004, the NJBPU adopted an MOU that set out specific tasks related to service reliability to be performed by JCP&L and a timetable for completion and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of a Special Reliability Master who made recommendations on appropriate courses of action necessary to ensure system-wide reliability. The Stipulation also incorporates the Executive Summary and Recommendation portions of the final report of a focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). A final order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer Advocate to discuss reliability improvements. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On September 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in New Jersey.

Environmental Matters

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

JCP&L has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, JCP&L's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Included in Other Noncurrent Liabilities are accrued liabilities aggregating approximately $46.8 million as of September 30, 2005.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

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See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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

Power Outages and Related Litigation

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

In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision on July 8, 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Division. JCP&L has filed a motion for summary judgment. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 2005.

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

Other Legal Matters

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties’ collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the Arbitrator decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the Arbitrator issued an opinion to award approximately $16.1 million to the bargaining unit employees. JCP&L initiated an appeal of this award by filing a motion to vacate in Federal Court in New Jersey on October 18, 2005. JCP&L recognized a liability for the potential $16.1 million award during the three months ended September 30, 2005.

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

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

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

EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with JCP&L's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for JCP&L in the fourth quarter of 2005. JCP&L is currently evaluating the effect this Interpretation will have on its financial statements.

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SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. JCP&L will adopt this Statement effective January 1, 2006.

SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for FirstEnergy. This FSP is not expected to have a material impact on JCP&L's financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by JCP&L beginning January 1, 2006. JCP&L is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application for reporting periods beginning after December 15, 2005. JCP&L is currently evaluating this FSP and any impact on its investments.

140

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
OPERATING REVENUES	$	333,180		$	285,419		$	892,097		$	788,361
OPERATING EXPENSES AND TAXES:
Purchased power		186,148			146,938			467,911			421,660
Other operating costs		81,774			50,141			192,892			130,210
Provision for depreciation		9,323			10,648			32,221			30,370
Amortization of regulatory assets		32,853			30,291			86,760			78,737
General taxes		19,906			18,680			56,201			53,103
Income taxes		(2,111	)		8,448			9,754			17,179
Total operating expenses and taxes		327,893			265,146			845,739			731,259
OPERATING INCOME		5,287			20,273			46,358			57,102
OTHER INCOME (net of income taxes)		6,459			6,888			19,897			18,530
NET INTEREST CHARGES:
Interest on long-term debt		8,941			8,823			27,886			31,208
Allowance for borrowed funds used during construction		(150	)		(65	)		(401	)		(208	)
Other interest expense		1,950			1,326			5,626			2,846
Net interest charges		10,741			10,084			33,111			33,846
NET INCOME		1,005			17,077			33,144			41,786
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on derivative hedges		84			84			252			(3,182	)
Unrealized gain (loss) on available for sale securities		67			-			67			(53	)
Other comprehensive income (loss)		151			84			319			(3,235	)
Income tax expense (benefit) related to other comprehensive income		62			(1,314	)		132			(1,342	)
Other comprehensive income (loss), net of tax		89			1,398			187			(1,893	)
TOTAL COMPREHENSIVE INCOME	$	1,094		$	18,475		$	33,331		$	39,893
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.

141

METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2005			2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	1,841,450		$	1,800,569
Less - Accumulated provision for depreciation		712,549			709,895
		1,128,901			1,090,674
Construction work in progress		7,458			21,735
		1,136,359			1,112,409
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		229,437			216,951
Long-term notes receivable from associated companies		11,162			10,453
Other		29,355			34,767
		269,954			262,171
CURRENT ASSETS:
Cash and cash equivalents		120			120
Notes receivable from associated companies		15,793			18,769
Receivables -
Customers (less accumulated provisions of $4,320,000 and $4,578,000,
respectively, for uncollectible accounts)		131,213			119,858
Associated companies		1,401			118,245
Other		7,684			15,493
Prepayments and other		13,285			11,057
		169,496			283,542
DEFERRED CHARGES:
Goodwill		867,649			869,585
Regulatory assets		571,745			693,133
Other		24,055			24,438
		1,463,449			1,587,156
	$	3,039,258		$	3,245,278
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 900,000 shares -
859,500 shares outstanding	$	1,290,296		$	1,289,943
Accumulated other comprehensive loss		(43,303	)		(43,490	)
Retained earnings		28,110			38,966
Total common stockholder's equity		1,275,103			1,285,419
Long-term debt and other long-term obligations		594,116			701,736
		1,869,219			1,987,155
CURRENT LIABILITIES:
Currently payable long-term debt		100,000			30,435
Short-term borrowings -
Associated companies		76,755			80,090
Other		-			-
Accounts payable -
Associated companies		39,505			88,879
Other		30,966			26,097
Accrued taxes		2,247			11,957
Accrued interest		9,462			11,618
Other		20,008			23,076
		278,943			272,152
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		309,979			305,389
Accumulated deferred investment tax credits		10,250			10,868
Power purchase contract loss liability		250,024			349,980
Asset retirement obligation		139,216			132,887
Retirement benefits		77,501			82,218
Nuclear fuel disposal costs		39,213			38,408
Other		64,913			66,221
		891,096			985,971
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	3,039,258		$	3,245,278
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these balance sheets.

142

METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,005		$	17,077		$	33,144		$	41,786
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		9,323			10,648			32,221			30,370
Amortization of regulatory assets		32,853			30,291			86,760			78,737
Deferred costs recoverable as regulatory assets		8,521			(15,629	)		(21,491	)		(45,616	)
Deferred income taxes and investment tax credits, net		(8,438	)		666			(10,336	)		(4,853	)
Accrued retirement benefit obligation		(1,514	)		(273	)		(4,717	)		492
Accrued compensation, net		1,527			649			211			201
Pension trust contribution		-			(38,823	)		-			(38,823	)
Decrease (increase) in operating assets -
Receivables		3,088			(2,599	)		113,298			29,943
Materials and supplies		(1	)		5			(19	)		41
Prepayments and other current assets		18,978			14,298			(2,209	)		(15,027	)
Increase (decrease) in operating liabilities -
Accounts payable		6,088			(12,536	)		(44,505	)		(17,857	)
Accrued taxes		(4,526	)		(145	)		(9,710	)		(6,255	)
Accrued interest		(1,269	)		(3,006	)		(2,156	)		(127	)
Other		(7,701	)		(7,356	)		(24,063	)		(9,581	)
Net cash provided from (used for) operating activities		57,934			(6,733	)		146,428			43,431
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		-			-			-			247,607
Short-term borrowings, net		-			70,000			-			4,665
Redemptions and Repayments-
Long-term debt		-			(45,936	)		(37,830	)		(196,371	)
Short-term borrowings, net		(24,266	)		-			(3,335	)		-
Dividend Payments-
Common stock		(10,000	)		(10,000	)		(44,000	)		(35,000	)
Net cash provided from (used for) financing activities		(34,266	)		14,064			(85,165	)		20,901
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(21,680	)		(12,390	)		(56,075	)		(33,733	)
Contributions to nuclear decommissioning trusts		(2,370	)		(2,371	)		(7,112	)		(7,113	)
Loan repayments from (loans to) associated companies, net		(1,072	)		17,989			2,267			(13,046	)
Other		1,454			(10,559	)		(343	)		(10,441	)
Net cash provided used for investing activities		(23,668	)		(7,331	)		(61,263	)		(64,333	)
Net change in cash and cash equivalents		-			-			-			(1	)
Cash and cash equivalents at beginning of period		120			120			120			121
Cash and cash equivalents at end of period	$	120		$	120		$	120		$	120
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of these statements.

143

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Metropolitan Edison Company:

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 1, 2005

144

METROPOLITAN EDISON COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier. Met-Ed has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Met-Ed continues to deliver power to homes and businesses through its existing distribution system.

Results of Operations

Net income decreased to $1 million for the third quarter of 2005 from $17 million in the third quarter of 2004. The decrease in net income primarily resulted from higher purchased power costs, transmission expenses, and amortization of regulatory assets, partially offset by higher operating revenues and lower depreciation and income taxes. For the first nine months of 2005, net income decreased to $33 million from $42 million in the same period of 2004. The decrease in net income primarily resulted from higher purchased power costs, transmission expenses, and amortization of regulatory assets, partially offset by higher operating revenues and other income and lower income taxes as discussed below.

Operating revenues increased by $48 million, or 16.7%, in the third quarter of 2005 and $104 million, or 13.2%, in the first nine months of 2005, compared with the same periods of 2004. Increases in both periods were due, in part, to higher retail generation electric revenues from all customer sectors ($17 million for the third quarter and $41 million for the first nine months of 2005). The increases in retail generation KWH sales for both periods of 2005 were mainly attributable to warmer weather and reduced customer shopping - primarily in the industrial sector. Industrial customer shopping decreased by 4.9% and 11.2% percentage points in the third quarter and first nine months of 2005, respectively. While higher generation sales in the third quarter of 2005 were offset by slightly lower composite unit prices, overall higher composite unit prices during the nine-month period also contributed to the increase in generation revenues.

Revenues from distribution throughput increased by $13 million in the third quarter and by $23 million in the first nine months of 2005 compared with the same periods of 2004. Increases in both periods of 2005 were primarily due to higher KWH deliveries and slightly higher unit prices. Increased transmission revenues of $17 million in the third quarter and $32 million in the first nine months of 2005 also contributed to higher operating revenues. These increases were due to a change in the power supply agreement with FES in the second quarter of 2004. This change also resulted in higher transmission expenses as discussed further below. In the first nine months of 2005, operating revenues also included a $4 million payment received under a contract provision associated with the prior sale of TMI Unit 1. Under the contract, additional payments are received if subsequent energy prices rise above specific levels and are credited to Met-Ed’s customers, resulting in no net impact to earnings.

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 compared to the same periods of 2004 are summarized in the following table:

	Three			Nine
Changes in KWH Sales	Months			Months
Increase (Decrease)
Retail Electric Generation:
Residential		15.5	%		7.6	%
Commercial		10.1	%		7.6	%
Industrial		9.1	%		17.0	%
Total Retail Electric Generation Sales		11.9	%		9.9	%
Distribution Deliveries:
Residential		15.5	%		7.5	%
Commercial		10.0	%		6.7	%
Industrial		3.2	%		1.9	%
Total Distribution Deliveries		10.0	%		5.6	%

145

Operating Expenses and Taxes

Total operating expenses and taxes increased by $63 million in the third quarter and by $114 million in the first nine months of 2005 compared with the same periods of 2004. The following table presents changes from the prior year by expense category:

	Three			Nine
Operating Expenses and Taxes - Changes	Months			Months
	(In millions)
Increase (Decrease)
Purchased power costs	$	39		$	46
Other operating costs		32			62
Provision for depreciation		(1	)		2
Amortization of regulatory assets		3			8
General taxes		1			3
Income taxes		(11	)		(7	)
Net increase in operating expenses and taxes	$	63		$	114

Purchased power costs increased by $39 million in the third quarter and $46 million in the first nine months of 2005 compared with the same periods of 2004. The increases in both periods were primarily due to increased third party power purchases ($47 million in the third quarter and $92 million in the first nine months of 2005) and NUG contract purchases ($21 million in the third quarter and $29 million in the first nine months of 2005) partially offset by reduced purchased power from FES ($30 million in the third quarter and $77 million in the first nine months of 2005). These changes, for both periods, were due to increased KWH purchased to meet increased retail generation sales requirements offset by slightly lower unit costs.

Other operating costs increased by $32 million in the third quarter and by $62 million in first nine months of 2005 compared with the same periods of 2004. The increases in both periods were primarily caused by higher PJM congestion charges and transmission expenses as a result of the change in the power supply agreement with FES discussed above.

In the first nine months of 2005, depreciation expense increased due to additions to the asset base and higher costs to decommission the Saxton nuclear plant as compared to the same period of 2004. For both periods of 2005, regulatory asset amortization reflected increases associated with the level of CTC revenue recovery, partially offset by lower amortization related to above market NUG costs as compared to the prior year periods.

General taxes increased in both periods primarily as a result of higher gross receipt taxes associated with the increase in KWH sales. Income taxes decreased in the third quarter and first nine months of 2005 due to lower taxable income.

Capital Resources and Liquidity

Met-Ed’s cash requirements for the remainder of 2005, for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with cash from operations.

Changes in Cash Position

As of September 30, 2005, Met-Ed’s cash and cash equivalents of $120,000 remained unchanged from December 31, 2004.

146

 Cash Flows From Operating Activities

Cash provided from (used for) operating activities during the third quarter and first nine months of 2005, compared with the corresponding periods of 2004 were as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Cash Flows	2005		2004			2005		2004
	(In millions)
Cash earnings (1)	$	43	$	27		$	116	$	85
Pension trust contribution (2)		-		(23	)		-		(23	)
Working capital and other		15		(11	)		30		(19	)
Total cash flows from operating activities	$	58	$	(7	)	$	146	$	43
(1) Cash earnings is a non-GAAP measure (see reconciliation below).
(2) Pension trust contribution net of $16 million of income tax benefits.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	(In millions)
Net income (GAAP)	$	1		$	17		$	33		$	42
Non-cash charges (credits):
Provision for depreciation		9			11			32			30
Amortization of regulatory assets		33			30			87			79
Deferred costs recoverable as regulatory assets		8			(16	)		(22	)		(46	)
Deferred income taxes and investment tax credits, net		(8	)		(16	)		(10	)		(21	)
Other non-cash charges		-			1			(4	)		1
Cash earnings (Non-GAAP)	$	43		$	27		$	116		$	85

The $16 million and $31 million increases in cash earnings for the third quarter and first nine months of 2005, respectively, are described above under “Results of Operations”. Net cash from operating activities increased in the third quarter and the first nine months due to the absence of a $23 million after-tax voluntary pension contribution made in the third quarter of 2004. The $26 million change in working capital in the third quarter of 2005 primarily resulted from changes of $6 million in accounts receivable, $19 million in accounts payable and $5 million in prepayments, offset by a change of $4 million in accrued taxes. The $49 million change in working capital for the first nine months of 2005 primarily resulted from net changes in accounts receivable and accounts payable from associated companies of $52 million and $13 million in prepayments, partially offset by changes of $11 million in customer deposits, $3 million in accrued taxes and $2 million in accrued interest.

Cash Flows From Financing Activities

For the third quarter of 2005, net cash used for financing activities was $34 million compared to $14 million of cash provided from financing activities in the third quarter of 2004. The $48 million decrease resulted primarily from a $70 million reduction in new debt financing compared to the third quarter of 2004 offset in part by a $22 million reduction in debt redemptions. For the first nine months of 2005, net cash used for financing activities was $85 million compared to $21 million of net cash provided from financing activities in the same period of 2004. The $106 million change reflected a $252 million reduction in new debt financing and a $9 million increase in common stock dividends to FirstEnergy, partially offset by a $155 million decrease in debt redemptions compared to the same period of 2004.

As of September 30, 2005, Met-Ed had approximately $16 million of cash and temporary investments (including short-term notes receivable from associated companies) and $77 million of short-term borrowings outstanding. Met-Ed has authorization from the SEC to incur short-term debt up to $250 million (including the utility money pool). Under the terms of Met-Ed’s senior note indenture, no more first mortgage bonds can be issued as long as the senior bonds are outstanding. Met-Ed had no restrictions on the issuance of preferred stock.

147

Met-Ed Funding LLC (Met-Ed Funding), a wholly owned subsidiary of Met-Ed, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Met-Ed. Met-Ed Funding can borrow up to $80 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Met-Ed Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Met-Ed. On July 15, 2005, the facility was renewed until June 29, 2006. As of September 30, 2005, the facility was undrawn. The annual facility fee is 0.25% on the entire finance limit.

Met-Ed has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pools and tracks surplus funds of FirstEnergy and the respective regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of 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 third quarter of 2005 was 3.50%.

On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Met-Ed’s borrowing limit under the facility is $250 million.

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

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

Cash Flows From Investing Activities

In the third quarter of 2005, net cash used for investing activities totaled $24 million, compared to $7 million in the third quarter of 2004. The change in the third quarter of 2005 primarily resulted from a $19 million increase in loan repayments to associated companies and a $9 million increase in property additions, partially offset by a $9 million capital transfer from FESC in the third quarter of 2004. In the first nine months of 2005, net cash used for investing activities totaled $61 million compared to $64 million in the same period of 2004. The change resulted from a $15 million increase in loan repayments from associated companies and the previously mentioned capital transfer, partially offset by a $22 million increase in property additions. Expenditures for property additions primarily support Met-Ed’s energy delivery operations.

Met-Ed's capital spending for the period 2005 through 2007 is expected to be about $205 million, of which approximately $68 million applies to 2005. In the last quarter of 2005, capital requirements for property additions are expected to be about $14 million. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Met-Ed has no additional requirements for maturing long-term debt during the remainder of 2005.

Market Risk Information

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

148

Commodity Price Risk

Met-Ed is exposed to price risk primarily resulting from fluctuating electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Most of Met-Ed's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of September 30, 2005, Met-Ed’s commodity derivative contract was an embedded option with a fair value of $28 million. A $4 million net decrease in the value of this asset was recorded as a decrease in regulatory liabilities, and therefore, had no impact on net income.

The valuation of derivative commodity contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts as of September 30, 2005 are summarized by year in the following table:

Sources of Information -
Fair Value by Contract Year	2005(1)		2006		2007		2008		2009		Thereafter		Total
Prices based on external sources(2)	$	5	$	5	$	5	$	-	$	-	$	-	$	15
Prices based on models		-		-		-		5		4		4		13
Total	$	5	$	5	$	5	$	5	$	4	$	4	$	28
(1) For the last quarter of 2005. (2) Broker quote sheets.

Met-Ed 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 derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2005.

Equity Price Risk

Included in Met-Ed's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $138 million as of September 30, 2005 and $134 million as of December 31, 2004. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $14 million reduction in fair value as of September 30, 2005.

Regulatory Matters

Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Met-Ed's regulatory assets as of September 30, 2005 and December 31, 2004 were $572 million and $693 million, respectively.

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

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

149

Met-Ed purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed is authorized to defer differences between NUG contract costs and current market prices. On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

On January 12, 2005, Met-Ed filed a request with the PPUC for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and Met-Ed has not yet implemented deferral accounting for these costs.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania including a more detailed discussion of reliability initiatives, including actions by the PPUC, that impact Met-Ed.

Environmental Matters

Met-Ed accrues environmental liabilities 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 Met-Ed’s determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

Met-Ed has been named as a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2005, based on estimates of the total costs of cleanup, Met-Ed’s proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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

150

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

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

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

151

EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with Met-Ed's current accounting.

FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for Met-Ed in the fourth quarter of 2005. Met-Ed is currently evaluating the effect this Interpretation will have on its financial statements.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Met-Ed will adopt this Statement effective January 1, 2006.

SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for Met-Ed. This FSP is not expected to have a material impact on Met-Ed's financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by Met-Ed beginning January 1, 2006. Met-Ed is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

152

FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. Met-Ed is currently evaluating this FSP and any impact on its investments.

153

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
OPERATING REVENUES	$	290,451		$	254,339		$	846,477		$	752,986
OPERATING EXPENSES AND TAXES:
Purchased power		178,090			137,146			467,639			432,974
Other operating costs		66,417			37,100			183,024			122,988
Provision for depreciation		12,736			12,281			37,721			35,229
Amortization of regulatory assets		12,627			11,759			38,930			39,130
General taxes		17,552			16,913			51,892			50,795
Income taxes		(3,101	)		11,693			14,991			16,000
Total operating expenses and taxes		284,321			226,892			794,197			697,116
OPERATING INCOME		6,130			27,447			52,280			55,870
OTHER INCOME (net of income taxes)		1,057			1,300			1,477			1,663
NET INTEREST CHARGES:
Interest on long-term debt		7,305			7,513			22,187			22,528
Allowance for borrowed funds used during construction		(285	)		(60	)		(674	)		(192	)
Deferred interest		-			-			-			190
Other interest expense		2,536			3,058			7,392			8,063
Net interest charges		9,556			10,511			28,905			30,589
NET INCOME (LOSS)		(2,369	)		18,236			24,852			26,944
OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized gain (loss) on derivative hedges		17			17			49			(618	)
Unrealized gain (loss) on available for sale securities		18			7			(3	)		(3	)
Other comprehensive income (loss)		35			24			46			(621	)
Income tax expense (benefit) related to other comprehensive income		20			(256	)		20			(258	)
Other comprehensive income (loss), net of tax		15			280			26			(363	)
TOTAL COMPREHENSIVE INCOME (LOSS)	$	(2,354	)	$	18,516		$	24,878		$	26,581
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

154

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,			December 31,
	2005			2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	2,004,891		$	1,981,846
Less - Accumulated provision for depreciation		772,818			776,904
		1,232,073			1,204,942
Construction work in progress		23,622			22,816
		1,255,695			1,227,758
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		111,826			109,620
Non-utility generation trusts		97,473			95,991
Long-term notes receivable from associated companies		15,629			14,001
Other		14,855			18,746
		239,783			238,358
CURRENT ASSETS:
Cash and cash equivalents		35			36
Notes receivable from associated companies		-			7,352
Receivables -
Customers (less accumulated provisions of $4,095,000 and $4,712,000,
respectively, for uncollectible accounts)		120,580			121,112
Associated companies		6,339			97,528
Other		7,369			12,778
Prepayments and other		15,818			7,198
		150,141			246,004
DEFERRED CHARGES:
Goodwill		886,559			888,011
Regulatory assets		99,491			200,173
Other		13,234			13,448
		999,284			1,101,632
	$	2,644,903		$	2,813,752
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares -
5,290,596 shares outstanding	$	105,812		$	105,812
Other paid-in capital		1,206,358			1,205,948
Accumulated other comprehensive loss		(52,787	)		(52,813	)
Retained earnings		38,920			46,068
Total common stockholder's equity		1,298,303			1,305,015
Long-term debt and other long-term obligations		478,954			481,871
		1,777,257			1,786,886
CURRENT LIABILITIES:
Currently payable long-term debt		4			8,248
Short-term borrowings -
Associated companies		114,749			241,496
Other		75,000			-
Accounts payable -
Associated companies		30,456			56,154
Other		35,987			25,960
Accrued taxes		19,234			7,999
Accrued interest		15,289			9,695
Other		19,264			23,750
		309,983			373,302
NONCURRENT LIABILITIES:
Power purchase contract loss liability		259,675			382,548
Retirement benefits		121,251			118,247
Asset retirement obligation		69,608			66,443
Accumulated deferred income taxes		56,029			37,318
Other		51,100			49,008
		557,663			653,564
COMMITMENTS AND CONTINGENCIES (Note 13)
	$	2,644,903		$	2,813,752
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these balance sheets.

155

PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(2,369	)	$	18,236		$	24,852		$	26,944
Adjustments to reconcile net income (loss) to net cash from
operating activities -
Provision for depreciation		12,736			12,281			37,721			35,229
Amortization of regulatory assets		12,627			11,759			38,930			39,130
Deferred costs recoverable as regulatory assets		(5,355	)		(25,618	)		(41,301	)		(62,122	)
Deferred income taxes and investment tax credits, net		(5,412	)		28,574			(2,765	)		30,308
Accrued retirement benefit obligations		1,100			1,164			3,005			4,805
Accrued compensation, net		691			894			(1,695	)		2,271
Pension trust contribution		-			(50,281	)		-			(50,281	)
Decrease (increase) in operating assets -
Receivables		17,528			(17,689	)		97,130			35,806
Prepayments and other current assets		13,487			9,703			(8,620	)		(25,247	)
Increase (decrease) in operating liabilities -
Accounts payable		4,662			(23,255	)		(15,671	)		(38,015	)
Accrued taxes		507			2			11,235			(7,572	)
Accrued interest		5,628			5,605			5,594			2,856
Other		(1,460	)		562			2,905			24,851
Net cash provided from (used for) operating activities		54,370			(28,063	)		151,320			18,963
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		-			-			-			150,000
Short-term borrowings, net		-			158,282			-			165,918
Redemptions and Repayments -
Long-term debt		(8,013	)		(103,241	)		(11,534	)		(228,453	)
Short-term borrowings, net		(15,139	)		-			(51,747	)		-
Dividend Payments -
Common stock		(2,000	)		(3,000	)		(32,000	)		(8,000	)
Net cash provided from (used for) financing activities		(25,152	)		52,041			(95,281	)		79,465
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(27,997	)		(10,192	)		(61,680	)		(33,428	)
Non-utility generation trust contribution		-			-			-			(50,614	)
Loan repayments from (loans to) associated companies, net		(1,287	)		(3,124	)		5,724			(3,144	)
Other, net		66			(10,662	)		(84	)		(11,242	)
Net cash used for investing activities		(29,218	)		(23,978	)		(56,040	)		(98,428	)
Net change in cash and cash equivalents		-			-			(1	)		-
Cash and cash equivalents at beginning of period		35			36			36			36
Cash and cash equivalents at end of period	$	35		$	36		$	35		$	36
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part of these statements.

156

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Pennsylvania Electric Company:

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2005, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

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

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report (which contained references to the Company’s change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(G) to those consolidated financial statements and the Company’s change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated March 7, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 1, 2005

157

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern, western and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. Penelec has unbundled the price for electricity into its component elements - including generation, transmission, distribution and transition charges.

Results of Operations

Penelec recognized a net loss of $2 million in the third quarter of 2005, compared to $18 million in net income in the third quarter of 2004. During the first nine months of 2005, net income decreased to $25 million compared to $27 million in the first nine months of 2004. The decrease in both periods resulted from higher purchased power and other operating costs, partially offset by higher operating revenues and lower income taxes.

Operating revenues increased by $36 million in the third quarter and $93 million in the first nine months of 2005 compared to the same periods of 2004. Increases in both periods were due to higher retail generation revenues in all sectors ($14 million for the quarter and $23 million for the first nine months). The increases in retail generation KWH sales in both periods of 2005 were mainly due to the warmer weather in 2005 compared to 2004. While the higher generation sales in the third quarter were offset by slightly lower composite unit prices, overall higher composite unit prices - especially in the industrial sector - for the nine-month period further contributed to the increase in generation revenues.

Distribution revenues increased by $4 million in the third quarter and by $6 million in the first nine months of 2005 compared to the same periods of 2004. Increases in both periods were due to higher KWH deliveries partially offset by lower unit prices. Also contributing to higher operating revenues was an increase in transmission revenues of $18 million in the third quarter and $61 million in the first nine months of 2005. These increases were due to a change in the power supply agreement with FES in the second quarter of 2004. This change also resulted in higher transmission expenses as discussed further below.

Changes in KWH sales by customer class in the three months and nine months ended September 30, 2005 from the corresponding periods of 2004 are summarized in the following table:

	Three			Nine
Changes in KWH Sales	Months			Months
Increase (Decrease)
Retail Electric Generation:
Residential		8.8	%		4.2	%
Commercial		7.0	%		4.3	%
Industrial		17.0	%		7.3	%
Total Retail Electric Generation Sales		10.2	%		5.1	%
Distribution Deliveries:
Residential		8.7	%		4.1	%
Commercial		6.6	%		4.1	%
Industrial		8.3	%		5.2	%
Total Distribution Deliveries		7.8	%		4.5	%

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Operating Expenses and Taxes

Total operating expenses and taxes increased by $57 million in the third quarter and $97 million in the first nine months of 2005 compared with the same periods in 2004. The following table presents changes from the prior year by expense category:

	Three			Nine
Operating Expenses and Taxes - Changes	Months			Months
	(In millions)
Increase (Decrease)
Purchased power costs	$	41		$	35
Other operating costs		29			60
Provision for depreciation		-			2
Amortization of regulatory assets		1			-
General taxes		1			1
Income taxes		(15	)		(1	)
Net increase in operating expenses and taxes	$	57		$	97

Purchased power costs increased by $41 million or 29.9% in the third quarter and $35 million or 8.0% in the first nine months of 2005 compared to the same periods of 2004. The increase in the third quarter of 2005 is due to increased KWH purchased to meet increased retail generation sales requirements, and higher unit costs. Third-party power purchases and NUG costs increased $48 million and $20 million, respectively, in the third quarter of 2005, partially offset by reduced purchased power from FES of $27 million. The increase in the first nine months is due to increased KWH purchased to meet sales requirements partially offset by lower unit costs. Increases from third-party power purchases and NUG costs of $81 million and $21 million, respectively, in the first nine months of 2005, were partially offset by reduced purchased power from FES of $67 million.

Other operating costs increased by $29 million in the third quarter and $60 million in the first nine months of 2005 compared to same periods in 2004. The increases in both periods were primarily due to increased transmission expenses in 2005 as a result of the change in the power supply agreement with FES referred to above. The increased transmission expenses were partially offset by reduced labor costs that were charged to capital projects. Income taxes decreased in the third quarter of 2005 due to lower pre-tax income compared to the third quarter of 2004.

Capital Resources and Liquidity

Penelec’s cash requirements for the remainder of 2005 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met with cash from operations.

Changes in Cash Position

As of September 30, 2005, Penelec had $35,000 of cash and cash equivalents compared with $36,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from (used for) operating activities in the third quarter and first nine months of 2005, compared with the corresponding periods in 2004, are summarized as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Operating Cash Flows	2005		2004			2005		2004
	(In millions)
Cash earnings (1)	$	14	$	27		$	59	$	56
Pension trust contribution (2)		-		(30	)		-		(30	)
Working capital and other		40		(25	)		92		(7	)
Total cash flows from operating activities	$	54	$	(28	)	$	151	$	19

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

⁽²⁾ Pension trust contribution net of $20 million of income tax benefits.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Cash Earnings	2005			2004			2005			2004
	(In millions)
Net income (loss) (GAAP)	$	(2	)	$	18		$	25		$	27
Non-cash charges (credits):
Provision for depreciation		13			12			38			35
Amortization of regulatory assets		12			12			39			39
Deferred costs recoverable as regulatory assets		(5	)		(26	)		(41	)		(62	)
Deferred income taxes and investment tax credits, net		(6	)		9			(3	)		10
Other non-cash items		2			2			1			7
Cash earnings (Non-GAAP)	$	14		$	27		$	59		$	56

Net cash from operating activities increased $82 million in the third quarter of 2005, compared with the third quarter of 2004, due to a $66 million increase from changes in working capital, an absence of a $30 million after-tax voluntary pension contribution made in the third quarter of 2004, and partially offset by a $13 million decrease in cash earnings as described above under “Results of Operations”. The increase in working capital primarily reflects net changes in accounts receivable and accounts payable to associated companies of $42 million and a $22 million increase in purchase power accounts payable.

Net cash from operating activities increased $132 million in the first nine months of 2005, compared with the same period of 2004, due to a $100 million increase from changes in working capital, an absence of the $30 million after-tax voluntary pension contribution, and a $3 million increase in cash earnings as described above under “Results of Operations”. The increase in working capital primarily reflects changes in accounts receivable to associated companies of $61 million, $30 million increase in purchase power and other accounts payable, and $19 million change in accrued taxes, partially offset by changes in customer deposits.

Cash Flows From Financing Activities

Net cash used for financing activities was $25 million in the third quarter of 2005 compared to net cash provided from financing activities of $52 million in the third quarter of 2004. The net change reflects a $1 million decrease in common stock dividends to FirstEnergy and a $173 million increase in repayments of short-term borrowings, offset by a $95 million decrease in debt redemptions.

Net cash used for financing activities was $95 million for the first nine months of 2005 compared to net cash provided from financing activities of $79 million in the first nine months of 2004. The net change of $174 million reflects $150 million of long-term debt financing in 2004, a $24 million increase in common stock dividends to FirstEnergy in 2005 and a $218 million increase in repayments of short-term borrowings, offset by a $217 million decrease in debt redemptions.

Penelec had approximately $35,000 of cash and temporary investments (which included short-term notes receivable from associated companies) and approximately $190 million of short-term indebtedness as of September 30, 2005. Penelec has authorization from the SEC to incur short-term debt of up to $250 million (including the utility money pool). Penelec will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) Penelec from issuing any debt which is senior to the senior notes. As of September 30, 2005, Penelec had the capability to issue $18 million of additional senior notes based upon FMB collateral. Penelec has no restrictions on the issuance of preferred stock.

Penelec Funding LLC (Penelec Funding), a wholly owned subsidiary of Penelec, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penelec. Penelec Funding can borrow up to $75 million under a receivables financing arrangement. As a separate legal entity with separate creditors, Penelec Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to Penelec. On July 15, 2005, the facility was renewed until June 29, 2006. The facility was undrawn as of September 30, 2005. The annual facility fee is 0.25% on the entire finance limit.

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On June 14, 2005, FirstEnergy, OE, Penn, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Penelec's borrowing limit under the facility is $250 million.

Penelec has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings under these arrangements in the third quarter of 2005 was 3.5%.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. Moody’s further stated that the revision in their outlook recognized management’s regional strategy of focusing on its core utility businesses and the improvement in FirstEnergy’s credit profile stemming from the application of free cash flow toward debt reduction. Moody’s noted that a ratings upgrade could be considered if FirstEnergy continues to achieve planned improvements in its operations and balance sheet.

On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter 2005. S&P also stated that FirstEnergy’s rating reflects the benefits of supportive regulation, low-cost base load generation fleet, low-risk transmission and distribution operations and rate certainty in Ohio. FirstEnergy’s ability to consistently generate free cash flow, good liquidity, and an improving financial profile were also noted as strengths.

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

Cash Flows From Investing Activities

Cash used for investing activities was $29 million in the third quarter of 2005 compared to $24 million in the third quarter of 2004. The increase was primarily due to higher property additions, partially offset by lower loan repayments from associated companies and the absence in 2005 of an $11 million capital transfer from FESC that took place in September 2004. Cash used for investing activities was $56 million in the first nine months of 2005 compared to $98 million in the first nine months of 2004. The decrease was primarily due to a $51 million repayment to the NUG trust fund in 2004, increased loans from associated companies, and the $11 million capital transfer from above, partially offset by higher property additions in 2005. Capital expenditures for property additions primarily support Penelec’s energy delivery operations.

Penelec’s capital spending for the period 2005-2007 is expected to be about $272 million for property additions and improvements, of which about $91 million applies to 2005. In the last quarter of 2005, capital requirements for property additions are expected to be about $26 million. Penelec has no additional requirements for maturing long-term debt during the remainder of 2005. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements.

Market Risk Information

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

Commodity Price Risk

Penelec is exposed to price risk primarily due to fluctuating electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and futures contracts. The derivatives are used for hedging purposes. Penelec’s non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. As of September 30, 2005, Penelec’s commodity derivatives contract was an embedded option with a fair value of $14 million. A decrease of $1 million in the value of this asset was recorded in the first nine months of 2005 as a decrease in regulatory liabilities, and therefore, had no impact on net income.

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The valuation of derivative commodity contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for valuation of derivative contracts as of September 30, 2005 are summarized by year in the following table:

Sources of Information -
Fair Value by Contract Year	2005(1)		2006		2007		2008		2009		Thereafter		Total
Prices based on external sources(2)	$	3	$	3	$	2	$	-	$	-	$	-	$	8
Prices based on models		-		-		-		2		2		2		6
Total	$	3	$	3	$	2	$	2	$	2	$	2	$	14
(1) For the last quarter of 2005. (2) Broker quote sheets.

Penelec 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 both its trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of September 30, 2005.

Equity Price Risk

Included in nuclear decommissioning trusts are marketable equity securities carried at their current fair value of approximately $61 million and $60 million as of September 30, 2005 and December 31, 2004, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of September 30, 2005.

Regulatory Matters

Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Penelec's regulatory assets as of September 30, 2005 and December 31, 2004 were $99 million and $200 million, respectively.

In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. Met-Ed’s and Penelec’s combined portion of total merger savings is estimated to be approximately $31.5 million. On April 13, 2005, the Commonwealth Court issued an interim order in the remand proceeding that the parties should report the status of the negotiations to the PPUC with a copy to the ALJ. The parties exchanged settlement proposals in May and June 2005 and continue to have settlement discussions.

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

Penelec purchases a portion of its PLR requirements from FES through a wholesale power sales agreement. The PLR sale is automatically extended for each successive calendar year unless either party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Penelec under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Penelec's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. Penelec is authorized to defer differences between NUG contract costs and current market prices. On November 1, 2005, FES and the other parties to the wholesale power agreement amended the agreement to provide FES the right over the next year to terminate the agreement at any time upon 60 days notice. If the wholesale power agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the agreement and, as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

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On January 12, 2005, Penelec filed a request with the PPUC to defer transmission-related costs beginning January 1, 2005, estimated to be approximately $4 million per month. The OCA, OSBA, OTS, MEIUG, PICA, Allegheny Electric Cooperative and Pennsylvania Rural Electric Association have all intervened in the case. To date no hearing schedule has been established, and Penelec has not yet implemented deferral accounting for these costs.

On January 31, 2005, certain PJM transmission owners made three filings pursuant to a settlement agreement previously approved by the FERC. Penelec was party to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, Baltimore Gas and Electric Company and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. On May 31, 2005, the FERC issued an order on these cases. First, it set for hearing the existing rate design and indicated that it will issue a final order within six months. Second, the FERC approved the proposed Schedule 12 rate harmonization. Third, the FERC accepted the proposed formula rate, subject to referral and hearing procedures. On June 30, 2005, the PJM transmission owners filed a request for rehearing of the May 31, 2005 order. The rate design and formula rate filings continue to be litigated before the FERC. The outcome of these two cases cannot be predicted.

See Note 14 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a more detailed discussion of reliability initiatives, including actions by the PPUC that impact Penelec.

Environmental Matters

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

Penelec has been named a PRP at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis.

FirstEnergy plans to issue a report regarding its response to air emission requirements. FirstEnergy expects to complete the report by December 1, 2005.

See Note 13(B) to the consolidated financial statements for further details and a complete discussion of environmental matters.

Other Legal Proceedings

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

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of September 30, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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One complaint was filed on August 25, 2004 against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy's motion to dismiss the case was granted on September 26, 2005. Additionally, FirstEnergy Corp. was named in a complaint filed in Michigan State Court by an individual who is not a customer of any FirstEnergy company. A responsive pleading to this matter is not due until on or about December 1, 2005. No estimate of potential liability has been undertaken in this matter.

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

See Note 13(C) to the consolidated financial statements for further details and a complete discussion of other legal proceedings.

New Accounting Standards and Interpretations

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

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

EITF Issue No. 05-6, "Determining the Amortization Period for Leasehold Improvements Purchased after Lease Inception or Acquired in a Business Combination"

In June 2005, the EITF reached a consensus on the application guidance for Issue 05-6. EITF 05-6 addresses the amortization period for leasehold improvements that were either acquired in a business combination or placed in service significantly after and not contemplated at or near the beginning of the initial lease term. For leasehold improvements acquired in a business combination, the amortization period is the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date of acquisition. Leasehold improvements that are placed in service significantly after and not contemplated at or near the beginning of the lease term should be amortized over the shorter of the useful life of the assets or a term that includes required lease periods and renewals that are deemed to be reasonably assured at the date the leasehold improvements are purchased. This EITF was effective July 1, 2005 and is consistent with Penelec's current accounting.

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FIN 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143”

On March 30, 2005, the FASB issued FIN 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations. Under this interpretation, companies are required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event, if the fair value of the liability can be reasonably estimated. In instances where there is insufficient information to estimate the liability, the obligation is to be recognized in the first period in which sufficient information becomes available to estimate its fair value. If the fair value cannot be reasonably estimated, that fact and the reasons why must be disclosed. This Interpretation is effective for Penelec in the fourth quarter of 2005. Penelec is currently evaluating the effect this Interpretation will have on its financial statements.

SFAS 154 - “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3”

In May 2005, the FASB issued SFAS 154 to change the requirements for accounting and reporting a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement when that pronouncement does not include specific transition provisions. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. In those instances, this Statement requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that period rather than being reported in the Consolidated Statements of Income. This Statement also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. The provisions of this Statement are effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Penelec will adopt this Statement effective January 1, 2006.

SFAS 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153 amending APB 29, which was based on the principle that nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in APB 29 included certain exceptions to that principle. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective January 1, 2006 for Penelec. This FSP is not expected to have a material impact on Penelec's financial statements.

SFAS 151, “Inventory Costs - an amendment of ARB No. 43, Chapter 4”

In November 2004, the FASB issued SFAS 151 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). Previous guidance stated that in some circumstances these costs may be “so abnormal” that they would require treatment as current period costs. SFAS 151 requires abnormal amounts for these items to always be recorded as current period costs. In addition, this Statement requires that allocation of fixed production overheads to the cost of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred by Penelec beginning January 1, 2006. Penelec is currently evaluating this Standard and does not expect it to have a material impact on the financial statements.

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FSP FAS 115-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In September 2005, the FASB finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. FSP FAS 115-1 will (1) supersede Issue 03-1 and EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FASB expects to issue this FSP in the fourth quarter of 2005, which would require prospective application with an effective date for reporting periods beginning after December 15, 2005. Penelec is currently evaluating this FSP and any impact on its investments.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Results of Operation and Financial Condition - Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a)EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The applicable registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end of the date covered by the report. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective in timely alerting them to any information relating to the registrants and their consolidated subsidiaries that is required to be included in the registrants’ periodic reports and in ensuring that information required in the reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time period specified by the SEC's rules and forms.

(b)CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2005, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 13 and 14 to the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 2.CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

(e)FirstEnergy

The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.

							Maximum Number
							(or Approximate
					Total Number of		Dollar Value) of
					Shares Purchased		Shares that May
	Total Number				As Part of Publicly		Yet Be Purchased
	of Shares		Average Price		Announced Plans		Under the Plans
Period	Purchased (a)		Paid per Share		or Programs (b)		or Programs
July 1-31, 2005		219,344	$	49.40		-		-
August 1-31, 2005		698,858	$	49.46		-		-
September 1-30, 2005		489,705	$	51.69		-		-
Third quarter 2005		1,407,907	$	50.23		-		-

(a) Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan.

(b) FirstEnergy does not currently have any publicly announced plan or program for share purchases.

ITEM 5. OTHER INFORMATION

 On November 1, 2005, the Restated Partial Requirements Agreement, dated as of January 1, 2003, as amended August 29, 2003 and June 8, 2004 (as so amended, the “Agreement”), among FES, Met-Ed, Penelec and Waverly was amended by the parties to provide FES the right over the next year to terminate the Agreement at any time upon 60 days written notice. Otherwise, the agreement remains automatically extended as to each operating company for each successive calendar year unless FES or such operating company elects to cancel the agreement by November 1 of the preceding year.

 Under the Agreement, Met-Ed and Penelec currently purchase a portion of their PLR requirements from FES at fixed prices. The remainder of PLR requirements are currently sourced from existing NUG contracts or other power contracts with non-affiliated third party suppliers. If the Agreement were terminated, Met-Ed and Penelec would need to satisfy the applicable portion of their PLR obligations from other sources at prevailing prices, which are likely to be higher than the current price charged by FES under the Agreement, and as a result, Met-Ed’s and Penelec’s purchased power costs could materially increase.

 Met-Ed, Penelec and FES are all wholly owned subsidiaries of FirstEnergy and Waverly is a wholly owned subsidiary of Penelec. A copy of the November 1, 2005 amendment is filed as Exhibit 10.1 to this Quarterly Report on Form 10-Q.

ITEM 6.EXHIBITS

(a)Exhibits

Exhibit
Number
JCP&L
	12	Fixed charge ratios
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.3	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.2	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
Met-Ed
	10.1	Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement
	12	Fixed charge ratios
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
Penelec
	10.1	Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

168

FirstEnergy
	10.1	Notice of Termination Tolling Agreement, Restated Partial Requirements Agreement
	10.2	Agreement by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated August 26, 2005.*
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
OE
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
Penn
	15	Letter from independent registered public accounting firm.
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
CEI
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
TE
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e).
	32.1	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.

* Confidential Treatment has been requested with respect to certain portions of this exhibit. Omitted portions have been filed separately with the Securities and Exchange Commission.

Pursuant to reporting requirements of respective financings, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q. FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting requirements and have not filed their respective fixed charge ratios.

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec, but hereby agree to furnish to the Commission on request any such documents.

169

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

November 2, 2005

FIRSTENERGY CORP.

Registrant

OHIO EDISON COMPANY

Registrant

THE CLEVELAND ELECTRIC

ILLUMINATING COMPANY

Registrant

THE TOLEDO EDISON COMPANY

Registrant

PENNSYLVANIA POWER COMPANY

Registrant

JERSEY CENTRAL POWER & LIGHT COMPANY

Registrant

METROPOLITAN EDISON COMPANY

Registrant

PENNSYLVANIA ELECTRIC COMPANY

Registrant

  /s/      Harvey L. Wagner

    Harvey L. Wagner

    Vice President, Controller

  and Chief Accounting Officer

170

EX-10.1

Exhibit 10.1

November 1, 2005

Mr. Anthony J. Alexander

President

Metropolitan Edison Company

2800 Pottsville Pike

Reading, PA 19640-0001

Pennsylvania Electric Company

311 Industrial Park Rd.

Johnstown, PA 15904

The Waverly Electric Power and Light Company

707 Main St.

Towanda, PA 18848

RE: Notice of TerminationTolling Agreement Restated Partial Requirements Agreement, dated January 1, 2003, by and among, Metropolitan Edison Company, Pennsylvania Electric Company, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., as amended by a First Amendment to Restated Requirements Agreement, dated August 29, 2003 and by a Second Amendment to Restated Requirements Agreement, dated June 8, 2004 (“Partial Requirements Agreement”)

Dear Mr. Alexander:

Please be advised that FirstEnergy Solutions Corp. on this 1^st day of November, 2005 pursuant to Paragraph 6 of the Partial Requirements Agreement hereby notifies Metropolitan Edison Company, Pennsylvania Electric Company and The Waverly Electric Power and Light Company (“Buyers”) that FirstEnergy Solutions Corp. elects to terminate the Partial Requirements Agreement effective midnight December 31, 2005. As required pursuant to Paragraph 6, this notice is being provided sixty (60) days in advance of the next calendar year.

Notwithstanding the above, in exchange for FirstEnergy Solutions Corp. not exercising its right to terminate the Partial Requirements Agreement effective midnight December 31, 2005, the parties agree to toll the termination provisions of Paragraph 6 for a period of one (1) year, provided that FirstEnergy Solutions Corp. shall be permitted to terminate the Partial Requirements Agreement at any time during the term of this Tolling Agreement with sixty (60) days written notice.

This Tolling Agreement supercedes any conflicting provision of the Partial Requirements Agreement. This Tolling Agreement and its contents shall not be used or relied upon as

Mr. Anthony J. Alexander

November 1, 2005

Page 2

evidence or in argument in any judicial, quasi-judicial, or other proceeding for any purpose whatsoever except to enforce or show evidence of compliance with the terms of the Tolling Agreement or to show evidence of the tolling of the termination provisions of Paragraph 6. The execution of the Tolling Agreement does not constitute an admission or acknowledgment of any fact, conclusion of law, or liability by any party to this Tolling Agreement.

This Tolling Agreement may be executed in counterparts and is effective upon November 1, 2005, and is effective without the requirement of filing with or endorsement by any federal or state court or agency. The undersigned representatives certify that they are fully authorized to enter into and to bind such party to the terms and conditions of this Tolling Agreement.

Please indicate your agreement with this Tolling Agreement by signing below.

Sincerely,

Richard H. Marsh

Senior Vice President

FirstEnergy Solutions Corp.
 

Accepted and agreed to by:

Metropolitan Edison Company

Pennsylvania Electric Company

The Waverly Electric Power and Light Company

By:

Anthony J. Alexander

President

This 1st day of November, 2005

EX-10.2

Exhibit 10.2

General Terms and Conditions

for

Engineering, Procurement, and Construction

of

Air Quality Control (AQC) Systems

August 26, 2005

by and between

FirstEnergy Generation Corp.

and

Bechtel Power Corporation

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General Terms and Conditions for Engineering, Procurement, and Construction

INDEX
Article 1 - Definitions	1
Article 2 - Relationship of FirstEnergy, Contractor, and Subcontractors	6
Article 3 - Contractor’s Responsibilities	8
Article 4 - FirstEnergy’s Responsibilities	18
Article 5 - Price; Payments to Contractor	18
Article 6 - Project Schedule; Commencement of Project; Mechanical and Final Completion; Scheduled Liquidated Damages	21
Article 7 - Performance Guarantee; Performance Liquidated Damages	25
Article 8 - Change Orders	25
Article 9 - Force Majeure; FirstEnergy Delay; Recovery	29
Article 10 - Compliance with Laws, Regulations, and Permits	30
Article 11 - Intellectual Property Rights	33
Article 12 - Insurance and Bonds	34
Article 13 - Warranty and Correction of Work	37
Article 14 - Payment of Accounts; Waiver of Lien Rights	39
Article 15 - Default, Termination and Suspension	41
Article 16 - Indemnities	42
Article 17 - Confidentiality	44
Article 18 - Limitation of Liability	45
Article 19 - Miscellaneous Provisions	47

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General Terms and Conditions for Engineering, Procurement, and Construction

ARTICLE 1 - DEFINITIONS

1.1Definitions. The following terms, when used in this Agreement with initial capitalization, shall have the meanings given below unless in any particular instance the context clearly indicates otherwise:

"AE-Constructor" and/or "Contractor" means Bechtel Power Corporation, the entity primarily responsible for performing and procuring the work.

“Affiliate” means, with respect to a Party, any Person: (i) which such Party now or hereafter owns or controls directly or indirectly; (ii) which is owned or controlled by the same company or companies that owns, directly or indirectly, a controlling interest in such Party; or (iii) which owns or controls, directly or indirectly, such Party. As used herein, “control” means direct or indirect possession of the power to direct or cause the direction of the management or policies of a legal entity, whether through ownership of voting securities, by contract or otherwise, and the terms “controlled” and “controlling” have meanings correlative to the foregoing.

“Agreement” has the meaning set forth in Section 1.2.

“Applicable Codes and Standards” means the codes, standards or requirements set forth herein or in any Applicable Law, which codes and standards include those described in FirstEnergy’s Requirements, and shall govern Contractor’s performance of the Project. In the event of an inconsistency or conflict between any of the Applicable Codes and Standards as contained in this Agreement and any referenced attachment, exhibit, schedule or subcontract, the highest such performance standard shall govern Contractor’s performance under this Agreement.

“Applicable Law” means any federal, state, or local statute, ordinance, rule, regulation, policy or guidance, any judicial or administrative order or judgment (whether or not by consent), any duties imposed by common law, and any provision or condition of any permit, license, or other operating authorization of any Governmental Authority or other body having jurisdiction over the Parties, the performance of the Project, or the Site.

“AQC Unit” means a portion of a Subproject associated with a Generating Unit.

“Available Amount” has the meaning set forth in Section 12.6.

“BAPC Ohio” means Bechtel Associates Professional Corporation, (Ohio), an Ohio professional corporation which is an Affiliate of Contractor.

“Bond” means an on demand, non-replenishing performance and/or payment security, in form and substance mutually agreeable to the parties.

“Business Day” means any day other than a Saturday, Sunday or other day on which banking institutions in the State of Ohio are required to be closed.

“Change Order” means a written order issued by FirstEnergy to Contractor after the execution and delivery of this Agreement or a written instrument signed by both Parties after execution and delivery of this Agreement in accordance with Article 8 or a written determination pursuant to Section 19.4 that authorizes an addition to, deletion from, suspension of or other modification to the requirements of this Agreement, and, to the extent provided for herein, an adjustment to the Target Construction Cost, the Project Schedule, any Guaranteed Final Completion Dates, any scope of work under the Subproject, the Performance Guarantee, any of the Warranties or any other obligation of either Party hereunder.

“Changed Criteria” has the meaning set forth in Section 8.1(A).

“Commencement Date” for each Subproject means the date of issuance of a Notice to Proceed with full construction, or an equivalent release to commence full construction of that Subproject.

“Contractor Indemnified Parties” means Contractor, its Affiliates, and their respective directors, officers, agents, employees, invitees, successors, and assigns.

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"Contractor's Project Manager" means Contractor’s designated authorized Project representative actively engaged in the supervision of the Project and in all matters relating to this Agreement, who shall have complete authority to act on behalf of Contractor on all matters pertaining to the Project, including giving instructions and making changes in the Project.

“Contract Price”means the Fee, reimbursable costs, and all other amounts payable by FirstEnergy to Contractor under Section 5.1 (provided, the Contract Price shall not include any amounts paid to Contractor for payments to FE Vendors that Contractor administers on FirstEnergy’s behalf).

“Corrective Work”has the meaning set forth in Section 13.1(B).

“Craft Labor” means building and construction trades crafts employed by the Contractor or Subcontractors for the construction of the Project.

“Critical Path Schedule”has the meaning set forth in Section 6.4(A).

“Data" means documentation, manuals, maps, plans, schedules, programs, specifications, software, reports, drawings, designs and other relevant information and works of authorship.

“Development Phase” shall mean with respect to each Subproject, the time period prior to the Commencement Date.

“Drawings”mean the graphic and pictorial documents showing the design, location and dimensions of the Project, generally including plans, elevations, sections, details, schedules and diagrams and the 3-dimensional model. Upon approval by FirstEnergy pursuant to Section 3.3(C), such Drawings shall form a part of the Agreement.

“Effective Date”means the date of execution by FirstEnergy and Contractor of this Agreement, or such other date as may be mutually agreed by FirstEnergy and Contractor as the Effective Date of this Agreement.

“Environmental Law” means any Applicable Law relating to, (A) the protection of (i) natural resources and the environment, or (ii) human health and the public welfare from actual or potential exposure to any actual or potential release, discharge, disposal or emission (whether past or present) of any Hazardous Substance, or (B) the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling, of any Hazardous Substance.

“FE Vendor” means a supplier of equipment, Materials, and/or services with respect to the Project or any Subproject, under direct contract with FirstEnergy (including any direct contract with FirstEnergy in which Bechtel acts as FirstEnergy’s agent).

“FE Vendor Arrangement” has the meaning set forth in Section 3.1(B).

“Fee” has the meaning set forth in Exhibit 5.1.

“Final Completion Certificate”means a certificate signed by Contractor in the form of Exhibit 6.3(C).

“Final Completion”has the meaning set forth in Section 6.3(A).

“Final Document Delivery” has the meaning set forth in Section 6.3(A).

“Final Lien and Claim Waiver”means the waiver and releases provided to FirstEnergy by Contractor and Subcontractors in accordance with the requirements of Section 6.3(A), which shall be in the form of Exhibit 6.3(A).

“Financing Assignee” has the meaning set forth in Section 19.3(C).

“Financing Documents” means any and all loan agreements, notes, indentures, security agreements, pledges, mortgages, subordination agreements, intercreditor agreements, partnership agreements, subscription agreements, participation agreements and other documents relating to the construction, interim or long-term financing of any Subproject and any refinancing of any Subproject (including a leveraged lease), including any and all modifications, extensions, renewals and replacements of any such financing or refinancing.

2

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“FirstEnergy” means FIRSTENERGY GENERATION CORP., an Ohio corporation.

“FirstEnergy Indemnified Parties” means FirstEnergy, its Affiliates, and their respective directors, officers, agents, employees, invitees, successors, and assigns.

“FirstEnergy Designated Representative” means that Person or Persons designated by FirstEnergy in a written notice to Contractor who shall have authority to act on behalf of FirstEnergy on all matters pertaining to the Project, including giving instructions and making changes in the Project.

“FirstEnergy Reliable Information” has the meaning set forth in Section 3.1(B).

“FirstEnergy’s Requirements” means the work scope attached hereto as Attachment A, the operating specifications, performance data sheets, and coal analysis data sheets, in each case together with all attachments thereto, and all other documents provided or identified by FirstEnergy to Contractor’s Project Manager specifying the purpose, scope, and/or design and/or other technical criteria for the Project.

“Force Majeure Event”means (i) an act of God, epidemic, landslide, lightning, earthquake, flood, fire, eruption, tornado, or other unusual natural event of any kind affecting a Party that was not voluntarily induced or promoted by the affected Party and did not result from a breach of such Party’s obligations under this Agreement or unlawful behavior by such Party, or (ii) failure of renewal, revocation, denial or delay in obtaining (after the affected Party has used due diligence and all reasonable commercial efforts to obtain) any necessary governmental authorization or permit, (iii) acts of any Governmental Authority (not resulting from a violation, or failure to fulfill the requirements, of Applicable Law by the affected Party), (iv) war, riot, civil disorder, terrorist act, embargo, strike or other concerted labor action, or (v) any other event, whether similar or not to the foregoing which, in each case, is beyond the reasonable control of the affected Party, despite such Party’s best efforts to fulfill its obligations under this Agreement. “Best efforts to fulfill its obligations” includes attempting to anticipate any Force Majeure Event and to address the effects of any such event (a) as it is occurring, and (b) after it has occurred, such that the delay or violation is minimized to the greatest extent possible. Failure or delay to perform of any Subcontractor, inability to obtain or delay in obtaining equipment, Materials or transport, and lack of availability of laborers, Subcontractors or local materials, shall not be a Force Majeure Event as to a Party unless caused by a Force Majeure Event or, where a Subcontractor fails to perform, an event which would, as to the Subcontractor directly affected thereby, qualify as a Force Majeure Event hereunder.

“Generating Unit” means an electric power generating unit to which a Subproject, or a portion of a Subproject, is being applied.

“Good Practices”means those practices and methods, and that level of competence, care, skill and judgment, generally used by internationally recognized, experienced and prudent contractors, engineers, manufacturers and professionals working in the electric power generation industry in the United States to design, engineer, construct, manufacture, commission, test and operate electric power generation facilities and ancillary equipment for the electric power industry, lawfully and safely, and with due consideration for reliability, efficiency, operability and maintainability. It is not intended that Good Practices be limited to the optimum practices, methods or acts to the exclusion of others, but rather a spectrum of practices, methods, or acts which internationally recognized, experienced and prudent contractors, engineers, manufacturers and professionals would be expected to employ in carrying out the requirements of this Agreement.

“Governmental Authority”means any federal, state, or local governmental body, including any legislative, judicial, or executive body, or agency or subdivision thereof, in each case having jurisdiction to exercise authority or control over a Party or its agent or over any part of or all of the Project or the Site.

“Guaranteed Final Completion Dates”has the meaning set forth in Section 6.3(B).

“Hazardous Substances”means any chemical or other material which is or may become injurious to the public health, safety, or welfare or to natural resources or the environment; any pollutant; contaminant; waste, solid or hazardous; any petroleum product; polychlorinated biphenyls; asbestos and asbestos-containing material; and includes substances defined as "hazardous substances" in the Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, 42 U.S.C. Sec. 9601, et seq.

3

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“Incentive Criteria” means the Scorecard Incentive Criteria, Target Construction Cost, and any other criteria which adjusts Contractor’s Fee as provided in Exhibit 5.1.

“Interim Lien and Claim Waiver”means the waiver and release provided to FirstEnergy by Contractor and Subcontractors, in accordance with the requirements of Section 5.2(C), which shall be in the form of Exhibit 5.2(C)

“Liquidated Damages”means Performance Liquidated Damages and Schedule Liquidated Damages.

“Losses”mean all losses, costs, damages, claims, liabilities, fines, penalties, and expenses (including attorneys’ and other professional fees and expenses, and court costs, incurred in connection with the investigation, defense, and settlement of any claim asserted against any Party).

‘‘Materials”means all materials and equipment required for the completion of and incorporation into the Project.

“Mechanical Completion”has the meaning set forth in Section 6.2(A).

“Monthly Progress Reports” has the meaning set forth in Section 3.10(A).

“Notice to Proceed” means, for any Subproject, a written notice to fully proceed with all work on a Subproject, or with that portion of the Subproject identified in such notice, that is agreed to and signed by FirstEnergy and Contractor.

“NSR Consent Decree” means the Consent Decree, dated March 18, 2005, issued in United States of America, et al. v. Ohio Edison Company and Pennsylvania Power Company, Civil Action No: 2:99-CV-1181 (U.S. District Court, SD Ohio), accessible at: www.epa.gov/compliance/resources/cases/civil/caa/ohioedison.html.

“OEM” means an original equipment manufacturer providing major process equipment for a Subproject.

“Party” or “Parties” means FirstEnergy and/or Contractor and their permitted successors and assigns.

“Performance Guarantee(s)” means the guarantees identified in Exhibit 7.2.

“Performance Liquidated Damages” has the meaning set forth in Section 7.2.

“Performance Tests” means those tests required to be performed to ensure that the Project meets the Performance Guarantee(s), as mutually determined by the Parties during the Development Phase.

“Permit” means any valid waiver, certificate, license, exemption, variance, franchise, permit, authorization or similar order from any Governmental Authority required to be obtained and maintained in connection with the Site or otherwise in relation to the Project.

“Person” means any individual, company, joint venture, corporation, partnership, association, joint stock company, limited liability company, trust, estate, unincorporated organization, Governmental Authority or other entity having legal capacity.

“Professional Services” means the engineering, design, procurement, and non-manual construction management services performed or to be performed by Contractor under this Agreement.

“Project” means all services, labor, Materials, apparatus, structures, supplies, Data, engineering, design, fabrication, delivery, inspection, and testing, together with miscellaneous expendable job supplies, installation-related equipment and tools, and any other services, work or things furnished or used or required to be furnished or used, by Contractor in the performance of this Agreement, and including any work performed pursuant to a Warranty. The term “Project” shall refer to the work to be performed in any Subproject only when and to the extent that Contractor has been authorized to perform work on a Subproject during the Development Phase, and only when and to the extent that Contractor has been authorized by receipt of a Notice to Proceed with respect to such Subproject.

“Project Execution Plan” means a description of processes for implementation of a Subproject, as described in Attachment A and in Article 3.

4

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“Project Schedule” means the schedule of the dates for certain stages of completion of the Subproject, such as the Scheduled Mechanical Completion Dates and the Guaranteed Final Completion Dates, as mutually determined by the Parties during the Development Phase, and which Contractor shall, at a minimum, use its best efforts to ensure, meets the requirements of Ohio Edison Company and Pennsylvania Power Company under the NSR Consent Decree.

“Recovery Schedule” has the meaning set forth in Section 9.3.

“Reliability Standard” has the meaning set forth in Exhibit 7.2

“Response Period” has the meaning set forth in Section 13.2(C).

“Schedule Liquidated Damages” has the meaning set forth in Section 6.5.

“Scheduled Mechanical Completion Date” for each Subproject shall mean the date by which Contractor is scheduled to achieve Mechanical Completion of the Subproject , as set forth in the Project Schedule to be delivered pursuant to Section 6.4.

“Site” means FirstEnergy’s W.H. Sammis electric generation facility located in Stratton, Ohio, and all other locations owned and exclusively operated by FirstEnergy or its Affiliates at which the Project or any Subproject is to be performed or to which Materials are to be delivered.

“Specifications” mean those preliminary documents consisting of the written requirements for Materials, standards, and workmanship for the Project and performance of related services. Upon approval by FirstEnergy pursuant to Section 3.3(C), such Specifications shall form a part of the Agreement.

“Subcontract” means an agreement by Contractor with a Subcontractor or by a Subcontractor with a lower tier Subcontractor for the performance of any portion of the Project.

“Subcontractor” means any vendor, subcontractor, materialman or supplier of any tier engaged by Contractor, or any higher-tier Subcontractor in connection with the performance of the Project, including BAPC Ohio, the entity to which all required engineering and design work will be subcontracted. The term “Subcontractor” shall not include any FE Vendor.

“Subproject” means a portion of the Project as more fully described in Section 3.1(A).

“Target Construction Cost” has the meaning set forth in Exhibit 5.1

“Taxes” means any and all taxes, assessments, levies, duties, fees, charges and withholdings of any kind or nature whatsoever and howsoever described, including gross receipts, franchise, sales, use, value added, property, excise, capital, stamp, transfer, employment, occupation, generation, privilege, utility, regulatory, energy, consumption, lease, filing, recording and activity taxes, levies, duties, fees, charges, imposts and withholding, together with any and all penalties, interest and additions thereto, but excluding any taxes on the incomes of the Parties.

“Third Party” means employees of Contractor Indemnified Parties and the FirstEnergy Indemnified Parties, acting in their individual or personal capacity and subject to the foregoing, parties other than Contractor, FirstEnergy, and their respective Affiliates, successors and assigns.

“Updated Critical Path Schedule” has the meaning given it in Section 6.4(C).

“Vendor Termination Costs” has the meaning set forth in Section 12.6

“Warranty” has the meaning set forth in Section 13.1.

“Warranty Non-Conformance” has the meaning set forth in Section 13.2(B).

“Warranty Period”has the meaning set forth in Section 13.1.

“Work Scope” means the work scope mutually determined by the Parties during the Development Phase, which will include the matters described generally in Attachment A and such other matters as are mutually agreed by the Parties.

5

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“Wrap Arrangement” has the meaning set forth in Section 3.1(B).

1.2Entire Agreement; Modification. The terms and conditions set forth in these General Terms and Conditions for Engineering, Procurement, and Construction (including all exhibits and schedules attached hereto), together with the Purchase Order to be delivered by FirstEnergy, FirstEnergy’s Requirements, and the Drawings and Specifications approved by FirstEnergy pursuant to Section 3.3(C), in each case as they may be amended and supplemented from time to time, shall constitute the entire agreement between FirstEnergy and the Contractor with respect to the performance of the Project (the “Agreement”), and supersedes any and all other prior understandings, correspondence and agreements, oral or written, between them. This Agreement may not be altered, amended, or modified in any way except by a written modification signed by all Parties.

1.3Priority. The documents making up this Agreement are intended to be complementary and mutually explanatory of one another. For the purposes of interpretation, the priority of the documents shall be in accordance with the following sequence:

(A)the Purchase Order to be issued by FirstEnergy;

(B)these General Terms and Conditions;

(C)FirstEnergy’s Requirements;

(D)the Drawings and Specifications;

(E)any other documents forming a part of this Agreement.

The latest dated amendment or Change Order shall take precedence over that part of the foregoing documents that it supersedes. Either Party, upon becoming aware of any such conflict or variance, shall promptly notify the other Party in writing.

ARTICLE 2 - RELATIONSHIP OF FIRSTENERGY, CONTRACTOR, AND SUBCONTRACTORS

2.1Status of Contractor. The relationship of Contractor to FirstEnergy shall be that of an independent contractor. Except to the extent set forth in this Agreement, nothing herein shall be interpreted to create a master-servant or principal-agent relationship between Contractor or any of its Subcontractors and FirstEnergy. Nevertheless, the fact that Contractor is an independent contractor does not relieve it from its responsibility to fully, completely, timely and safely perform the work in strict compliance with this Agreement. Nothing in this Agreement or in the performance of the Project shall be construed to create a partnership, joint venture or other joint business arrangement between FirstEnergy and Contractor.

2.2Subcontractors. FirstEnergy acknowledges and agrees that Contractor intends to have portions of the Project accomplished by Subcontractors pursuant to written Subcontracts between Contractor and such Subcontractors. All Subcontractors shall be reputable, qualified firms with an established record of successful performance in their respective trades performing identical or substantially similar work. All Subcontracts with Subcontractors shall at all times be consistent with the terms or provisions of this Agreement. No Subcontractor is intended to be or shall be deemed a third-party beneficiary of this Agreement. Contractor shall be fully responsible to FirstEnergy for the acts and omissions of Subcontractors and of persons directly or indirectly employed by them, as it is for the acts or omissions of persons directly employed by Contractor. The work of any Subcontractor shall be subject to inspection by FirstEnergy to the same extent as the work of Contractor. All Subcontractors and personnel of Subcontractors are to be instructed in the terms and requirements of FirstEnergy-approved safety and environmental protection regulations and shall be expected to comply with such regulations. In the event that personnel are not adhering to such regulations, then they shall be removed by Contractor. Nothing contained herein shall (i) create any contractual relationship between any Subcontractor and FirstEnergy, or (ii) obligate FirstEnergy to pay or see to the payment of any Subcontractor.

6

CONFIDENTIAL TREATMENT REQUESTED

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2.3Subcontracts.

(A)Proposed Subcontractors. Prior to engaging any Subcontractor (other than any Contractor Affiliate) for performance of any part of the Project having an aggregate value in excess of [$ ******], Contractorshall (i) notify FirstEnergy of such proposed Subcontractor as soon as possible during the selection process and furnish to FirstEnergy all information reasonably requested by FirstEnergy with respect to Contractor’s selection criteria (including copies of bid packages furnished to prospective Subcontractors and the qualifications of the proposed Subcontractors), and (ii) notify FirstEnergy no less than fifteen (15) Business Days prior to the execution of such Subcontract. FirstEnergy shall have the discretion, not to be unreasonably exercised, to reject any proposed Subcontractor. Contractor shall not enter into any Subcontract with a proposed Subcontractor rejected by FirstEnergy. FirstEnergy shall undertake in good faith to review the information provided by Contractor pursuant to this Section 2.3(A) expeditiously and shall notify Contractor of its decision to accept or reject a proposed Subcontractor as soon as practicable after such decision is made, provided, in the event that FirstEnergy does not inform Contractor of its decision to accept or reject a Subcontractor within five (5) Business Days, Contractor shall be entitled to deem that FirstEnergy has accepted such proposed Subcontractor.

(B)Delivery of Subcontracts. Contractor shall furnish FirstEnergy with a copy of all Subcontracts within ten (10) days after execution thereof.

(C)Terms of Subcontracts. In addition to the requirements in Section 2.2, each Subcontract will contain the following provisions:

(1)the Subcontract (other than Subcontracts with Affiliates of Contractor) may be assigned to FirstEnergy or its designee, at the request of FirstEnergy and without the consent of the Subcontractor; and

(2)the Subcontractor shall comply with and perform for the benefit of FirstEnergy all requirements and obligations of Contractor to FirstEnergy under this Agreement, as such requirements and obligations are applicable to the performance of the work under the Subcontract, including an indemnity for the benefit of FirstEnergy in substance the same as that included in Article 16, the insurance requirements specified in Article 12, and the provisions of Section 3.7.

2.4FE Vendors. FirstEnergy may elect to obtain certain products or services relating to each Subproject directly from an FE Vendor rather than through Contractor or its Subcontractors. Contractor will provide construction management and such other management and administrative services with respect to FE Vendors as provided herein. However, nothing contained herein shall (i) create any contractual relationship between any FE Vendor and Contractor, or (ii) obligate Contractor to pay or see to the payment of any FE Vendor, except as otherwise expressly agreed. No FE Vendor is intended to be or shall be deemed a third-party beneficiary of this Agreement. FirstEnergy shall use best efforts to include in its contracts with FE Vendors (or in the case that Contractor performs any work pursuant to this Agreement other than in respect of the Work Scope as contemplated in Exhibit 5.1, in any contracts with any other FirstEnergy contractor if such Contractor work has any physical or technical interfaces with such other FirstEnergy contractor’s work) a waiver of subrogation, indemnity, and waiver and release of consequential damages for the benefit of Contractor, and shall use reasonable commercial efforts to include in such contracts a waiver of property damage liability for the benefit of Contractor.

2.5Bechtel Associates Professional Corporation (Ohio). As required by applicable Ohio law(s), Contractor intends to subcontract engineering and design services performed under this Agreement to BAPC Ohio. With respect to all services performed by BAPC Ohio, Contractor agrees that FirstEnergy shall have all rights in and to such services as though such services were performed directly by Contractor (including the rights described in Article 11). Contractor shall guaranty and be fully responsible to FirstEnergy for the acts and omissions of BAPC Ohio and of persons directly or indirectly employed by them, as it is for the acts or omissions of persons directly employed by Contractor, and FirstEnergy agrees that it shall look solely and exclusively to Contractor for fulfillment of any obligations in respect of such services. Contractor shall cause BAPC Ohio to perform, for the benefit of FirstEnergy, all of the obligations of Contractor under this Agreement that are applicable to the scope services provided by BAPC Ohio. Any Subcontract with BAPC Ohio shall be subject to approval by FirstEnergy.

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Article 3 - Contractor’s Responsibilities

3.1General Scope of Project; Phased Release of Project.

(A)The Project tasks are described generally in Attachment A. The Project will be divided into a number of Subprojects, with each Subproject made up of an Air Quality Control system applied to one or more Generating Units. FirstEnergy, at its option, may proceed with any, all, or none of the Subprojects.

(B)Development Phase. During the Development Phase of each Subproject, Contractor shall perform engineering, design, and development of the Subproject in accordance with Attachment A and in consultation with FirstEnergy. The Parties will mutually determine the scope of the Subproject, the Work Scope, and other parameters of the Subproject, the Target Construction Cost, the Project Schedule, and the Project Execution Plan, and will perform the other tasks described generally in this Agreement and in Attachment A. During the Development Phase of each Subproject, the Parties will mutually determine whether Contractor will contract with and assume responsibility for OEMs as a Subcontractor (a “Wrap Arrangement”), or whether FirstEnergy will contract with major equipment vendors as an FE Vendor (an “FE Vendor Arrangement”). Except as otherwise agreed, the Parties anticipate that the AQC Units associated with Generating Units 1 through 4 of the Sammis Plant will be performed as FE Vendor Arrangements. With respect to the AQC Units associated with Generating Units 5, 6, and 7 of the Sammis Plant, FirstEnergy, at its sole discretion, will determine whether the Subproject will be performed as an FE Vendor Arrangement or as a Wrap Arrangement. Except as otherwise mutually agreed, if the AQC Units associated with Generating Units 5, 6, and 7 are performed as Wrap Arrangements, then all such AQC Units will be treated together as a single Subproject. Further, to the extent that FirstEnergy elects to utilize Powerspan ECO technology with respect to a Wrap Arrangement, the Parties agree that the terms and conditions in this Agreement relating to such Wrap Arrangement shall be adjusted in a mutually agreeable manner to reflect that: (A) Contractor shall not be responsible for, among other things, (1) any Performance Liquidated Damages relating to the actual performance of the Powerspan ECO technology, or (2) any intellectual property indemnity obligations relating to the Powerspan ECO technology, (B) Schedule Liquidated Damages shall be applicable to achievement of Mechanical Completion after the Scheduled Mechanical Completion Date (instead of the achievement of Final Completion after the Guaranteed Final Completion Date), and (C) Contractor shall be entitled to a Change Order related to any changes in project scope to the Subproject related to the Powerspan ECO technology. Contractor may perform preliminary procurement or construction work prior to the Commencement Date under a partial Notice to Proceed. To the extent that FirstEnergy desires to utilize this Agreement in connection with any Subproject to be performed at a Site other than the W.H. Sammis facility, the Parties agree that it is their mutual anticipation that such Subprojects will be performed as part of this Agreement (subject to negotiation of and mutual agreement to site-specific changes hereto).

(C)Construction Phase. After the Commencement Date of each Subproject, Contractor shall perform construction management, procurement, engineering, design, construction, startup, testing, and operations training for the Subproject in accordance with the Work Scope and the Project Execution Plan, in compliance with the Project Schedule and in consultation with FirstEnergy.

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(D)The Project shall include all engineering, procurement, construction, and testing of the Project, all equipment, Materials, labor, workmanship, apparatus, structures, inspection, manufacture, delivery, fabrications, transportation, and storage required in connection therewith, and all other items or tasks that are required to achieve Final Completion and Final Document Delivery for the individual Subprojects in accordance with the requirements of this Agreement. Contractor shall perform the Project in accordance with Good Practices, all Applicable Laws, all Applicable Codes and Standards, and all other terms and provisions of this Agreement. It is understood and agreed that the Project shall include any incidental work necessary to complete the Project in accordance with Good Practices, Applicable Law, Applicable Codes and Standards, and all other terms and provisions of this Agreement. Contractor shall be entitled to rely on only such items of information supplied by FirstEnergy as the Parties have mutually specified in the project design basis document during the Development Phase (the “FirstEnergy Reliable Information”). Contractor’s Project Manager shall inform FirstEnergy if he learns of any inaccuracy, error, fault, or other defect in the FirstEnergy Reliable Information.

3.2Specific Obligations. Without limiting the generality of Section 3.1, or the requirements of any other provision of this Agreement, Contractor shall:

(A)Procure, supply, transport, handle, and properly store and install all Materials, except where the Parties have agreed that FirstEnergy or its agents, subcontractors, or vendors will perform such services;

(B)Provide construction, construction management (including the furnishing of all field supplies, tools, construction equipment, and all Site supervision and Craft Labor), inspection and quality control services required to ensure that the Project is performed in accordance herewith;

(C)Negotiate all guarantees, warranties, delivery schedules and performance requirements (including schedule guarantees and performance guarantees) with all Subcontractors and FE Vendors on terms that are consistent with this Agreement, to the extent achievable;

(D)Perform shop and other inspections of the work of Subcontractors and FE Vendors to ensure that such work meets all of the relevant requirements of this Agreement;

(E)Contractor shall use reasonable commercial efforts to achieve FirstEnergy’s corporate supplier sourcing goals in awarding Subcontracts under the Project. By way of example, FirstEnergy’s corporate supplier sourcing goals for 2005 are as follows:

(1)Small business spend > or = 20.00%

(2)Small disadvantaged business spend > or = 3.00%

(3)Small woman owned business spend > or = 3.00%

(4)HUBZone Business spend > or = 0.27%

(5)Veteran owned business spend > or = 0.04%

(6)Service disabled veteran business spend> or = 0.0013%

3.3Design and Engineering.

(A)General. Contractor shall, as part of the Project, perform all design and engineering work in accordance with this Agreement. Before commencing design and engineering, the Contractor shall satisfy itself regarding FirstEnergy’s Requirements (including design criteria and calculations). Contractor’s Project Manager shall give notice to FirstEnergy of any error, fault or other defect in FirstEnergy’s Requirements of which he becomes aware.

(B)Drawings and Specifications. Contractor shall prepare the Drawings and Specifications for the Project. The Drawings and Specifications shall be based on the requirements of this Agreement, including FirstEnergy’s Requirements, Good Practices, Applicable Codes and Standards, Applicable Law, and all applicable provisions of the Agreement, and in a fashion consistent therewith shall develop in detail the requirements of this Agreement.

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(C)Review Process. The Project Execution Plan to be developed by the Parties during the Development Phase shall establish a review process including the following:

(1)General Review. During the development of the Drawings and Specifications, Contractor shall provide FirstEnergy with the opportunity to perform informal reviews of the design and engineering in progress. The informal reviews may be conducted at Contractor’s office located in Frederick, Maryland, or at any of its Subcontractor’s offices. The reviews may be of progress prints, computer images, draft documents, working calculations, draft specifications or reports, Drawings, Specifications or other design documents determined by FirstEnergy.

(2)Submission by Contractor. Contractor shall submit copies of the Drawings and Specifications identified in the Project Execution Plans or as subsequently requested by FirstEnergy as requiring formal review, comment, and approval to FirstEnergy. Each submission of Drawings and Specifications shall include a statement that to the best of Contractor’s knowledge such Drawings and Specifications comply with Section 3.3(B).

(3)Review Periods. If Contractor submits Drawings and Specifications within the applicable time frame set forth in the Project Schedule, FirstEnergy shall have a period of [******] Business Days after receipt of such submission to issue written comments, proposed changes and/or written approvals or disapprovals of the submission. FirstEnergy’s review periods shall be extended by the period of any delay due to a Force Majeure Event.

If FirstEnergy does not issue any comments, proposed changes or written approvals or disapprovals within such time periods, Contractor may proceed with the development of such Drawings and Specifications, but FirstEnergy’s lack of comments, approval or disapproval, if applicable, shall in no event constitute an approval of the matters submitted or bar FirstEnergy from subsequently commenting thereon or disapproving thereof; provided, however, Contractor shall not proceed with construction until the required Drawings and Specifications have been approved in writing by FirstEnergy as set forth in this Section 3.3(C)(3).

In the event that FirstEnergy disapproves the Drawings or Specifications, FirstEnergy shall provide Contractor with a written statement of the reasons for such rejection, and Contractor shall provide FirstEnergy with revised and corrected Drawings and Specifications as soon as possible thereafter; provided that Contractor shall not receive any extensions of time to perform any of its obligations hereunder.

If Contractor submits Drawings and Specifications at times other than shown in the Project Schedule, Contractor shall give FirstEnergy advance notice prior to such submissions to facilitate schedule adjustments when and if necessary. Thereafter, FirstEnergy shall use good faith efforts to provide comments, approval and/or disapproval as expeditiously as reasonably practical, and at Contractor’s request, FirstEnergy shall state the date by which it believes that it will be able to respond to such submission.

FirstEnergy’s review or approval of any Drawings and Specifications shall not in any way be deemed to limit or in any way alter Contractor’s responsibility to perform and complete the Project in strict accordance with the requirements of this Agreement.

Upon FirstEnergy’s written approval of the Drawings and Specifications, such Drawings and Specifications shall be the Drawings and Specifications that Contractor shall use to construct the Project. Upon approval by FirstEnergy, such Drawings and Specifications shall form a part of this Agreement.

Additions, modifications, or deletions to the Drawings and Specifications shall constitute a Change Order only if and to the extent FirstEnergy requests such change pursuant to Section 8.1, or FirstEnergy is notified by Contractor of a request for such Change Order pursuant to Section 8.2 and such Change Order is thereafter approved as provided in Article 8.

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(D)Design Licenses. Contractor shall perform all design and engineering services through design professionals licensed in accordance with Applicable Law, and all design and engineering deliverables shall be stamped by design professionals licensed in accordance with Applicable Law. If any design and engineering services are to be performed offshore, then FirstEnergy shall have the right to approve such services and the billing rates applied to such services.

(E)Other Information. Contractor shall provide all other information and documentation as may be reasonably requested by FirstEnergy.

3.4Contractor’s Personnel.

(A)Key Project Personnel. Exhibit 3.4(A) is a list of Contractor’s key personnel who will be responsible for supervising the performance of Contractor’s services. Contractor shall not remove any such personnel from the Project or from any Subproject without FirstEnergy’s prior written consent. If any such individual is so removed or otherwise ceases to be available to the Project or any Subproject for any reason, any replacement personnel shall be subject to the prior written approval of FirstEnergy. The individuals identified as technical specialists on such Exhibit shall be available as needed to support the Subproject.

(B)Employees. Contractor shall employ for the Project only persons known to it to be experienced, qualified, reliable and trustworthy. At FirstEnergy's request, the credentials of any of Contractor's employees assigned to perform the Project shall be submitted to FirstEnergy in advance of such assignment. Contractor shall require all persons performing the Project at FirstEnergy's Site to be trained in and to comply with Contractor's policies, procedures and directives applicable to activities at FirstEnergy's Site, including security, environmental protection, worker health and safety, sexual harassment, access, use of controlled substances, and similar activities, such policies, procedures and directives to be no less rigorous than those of FirstEnergy. During the performance of the Project, FirstEnergy may object to any Contractor employee who, in FirstEnergy's opinion, does not meet these criteria. In such case, Contractor shall immediately replace or remove such employee.

(C)Supervision. Contractor and its Subcontractors shall be responsible for enforcing strict discipline and good order among their employees, and shall assume full responsibility for their employees’ acts and omissions in and around FirstEnergy’s Site. Contractor’s Project Manager shall enforce all environmental protection and worker health and safety and similar requirements applicable to the Project. Contractor's Project Manager shall be thoroughly competent and experienced in the line of work to be performed. He shall represent the Contractor on the job and have the authority to bind the Contractor.

(D)Substance Abuse. The Contractor shall comply with the FirstEnergy Generation Corp. Substance Abuse Testing Program (FE SATP), a copy of which is attached hereto as Exhibit 3.4(D)

(E)Labor Requirements. Contractor and its Subcontractors shall comply with the requirements set forth in Exhibit 3.4(E) with respect to labor employed in connection with the Project

3.5Construction Plant, Facilities and Operations.

(A)On-Site Facilities. The Contractor will, unless otherwise specified, construct and remove all temporary buildings, structures, construction plant, change houses, portable lavatories and temporary storage buildings required for its own use or that of its Subcontractors, if any. The location of such buildings, storage areas for materials and employees' parking space, if on FirstEnergy's site, will be designated by FirstEnergy's Designated Representative.

Should FirstEnergy provide (at a location of its choice within reasonable distance of the Project area) the water and power source required for performance of the Agreement, Contractor shall accept these services at its own risk. However, FirstEnergy will diligently pursue restoration of any such services which may be interrupted. If such water and power sources shall be provided by FirstEnergy, they shall be identified elsewhere in the Project specification. Otherwise, Contractor shall be responsible for providing the water and power sources necessary for the performance of the Agreement.

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The Contractor agrees that when any use is to be made by the Contractor or by any of its Subcontractors or by any of its or their employees for its or their convenience of any equipment, facilities, office space or apparatus (including scaffolds, ladders, cranes, derricks, platforms, runways, bridges, floor, tools, barricades, or other facilities) which are owned, rented or leased by FirstEnergy or FirstEnergy's other contractor(s), or contracted for from other contractors, the Contractor shall prior to and during such use satisfy itself as to the safety of such facilities; and the Contractor, subject at all times to the provisions and limitations of Article 16, hereby assumes the entire responsibility and liability for all injuries, claims, damages, or losses whatsoever resulting from the use of such equipment, facilities, or apparatus. Contractor agrees to execute all necessary documents required by FirstEnergy or FirstEnergy's other Contractors, to acknowledge inspection of such equipment or apparatus prior to use.

(B)Areas of Project and Non-Interference with Other Activities on Site. The Contractor shall use only the area designated by FirstEnergy's Designated Representative, and other parts of FirstEnergy's Site shall not be used for any purpose without the prior approval of FirstEnergy's Designated Representative. If any part of the Project is to be performed on an easement or right-of-way held by FirstEnergy, the Contractor shall limit its activities to that area and not allow its employees or Subcontractors outside such area. The Contractor shall direct its employees or employees of its Subcontractors to enter and leave the premises only through access ways, and to park only in parking areas designated by FirstEnergy's Designated Representative.

The portion of the areas designated that constitutes the construction site shall be under the control of the Contractor unless otherwise agreed by the Contractor and FirstEnergy's Designated Representative.

The Contractor shall, to the maximum extent reasonably practicable, so conduct its work so as to avoid any necessity to curtail the operations of FirstEnergy's Site. Where the Project requires connection to or modification of existing facilities, FirstEnergy's Designated Representative will arrange for the Contractor to perform such work at FirstEnergy's convenience and the Contractor shall at all times, to the maximum extent reasonably practicable, except when required to install such facilities, keep its employees and cause its Subcontractors to keep their employees out of, off of, and out of contact with FirstEnergy's Site and facilities.

FirstEnergy shall provide access to the existing facilities at the times indicated on the Project Schedule to allow the Contractor to connect to or make modifications to the existing facilities, in accordance with the scope of the Project. The Project Schedule completion date and the Target Construction Cost for each Subproject shall be subject to equitable adjustment as appropriate in accordance with Article 8 in the event that such access is not provided.

The Contractor shall conduct its services so as to minimize interference with other work in progress. In case of dispute between the Contractor and other contractors engaged by FirstEnergy, the decision of FirstEnergy's Designated Representative coordinating the Project shall be final.

The Contractor shall not, under the terms of this Agreement, permit its employees or the employees of any of its Subcontractors to operate the existing FirstEnergy’s Site or any of its facilities or to perform maintenance work on the existing FirstEnergy’s Site or any of its facilities, except such maintenance work as is necessary for construction purposes.

(C)Access to Project; Surveillance. FirstEnergy shall be afforded free access at all reasonable times upon prior notice to the Contractor's or any of its Subcontractors’ work, facilities, and records, to perform surveillance and reviews of work completion and quality, and contract cost and quality records (except with respect to the financial information described in the last sentence of Section 3.7(B)), and to perform work sampling observation and recording surveillance activities. Any such surveillance or review performed by FirstEnergy or any failure by FirstEnergy to so perform shall in no manner reduce the responsibility and liability of Contractor or its Subcontractors or excuse them from performance. Access to a Subcontractor's facilities and records will be coordinated through the Contractor.

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(D)Responsibility for Materials and Work Prior to Acceptance. The Contractor shall receive, check in, unload, store, handle and protect all materials to be used, furnished or erected by the Contractor or its Subcontractors. Subject to Section 18.4(A), the property being used, furnished and/or erected, installed or constructed under the Agreement shall be considered to be in the care, custody and control of the Contractor, and the Contractor shall be responsible for all materials and work until permanently placed, installed or constructed and accepted by FirstEnergy.

The Contractor shall satisfactorily dispose of all rubbish resulting from the operations under this Agreement on a day-to-day basis and upon completion of the Project shall perform all work necessary to restore territory embraced within FirstEnergy’s Site of its operations to at least as good order and condition as at the beginning of the Project under the Agreement.

(E)Security and Safety. The Contractor’s site-specific safety program shall, at a minimum, comply with the FirstEnergy Contractor Safety Program for Fossil Generation, a copy of which is attached hereto as Exhibit 3.5(E)-1 The Contractor shall take the necessary precautions to render the Project secure in order to decrease the probability of accident from any cause and to avoid delay in completion of the Project. The Contractor shall use proper safety appliances and provide first aid treatment and ambulance service for emergency treatment of injuries and shall comply with all rules, laws, regulations of the United States of America, the State of Ohio, or any political subdivision or duly constituted Governmental Authority with regard to the safe performance of the Project. Contractor shall also comply with the requirements set forth in Exhibit 3.5(E)-2 (OSHA compliance and safety).

The Contractor shall provide temporary fire protection facilities to the extent required by FirstEnergy during the construction period. The Contractor may be working adjacent to or concurrent with FirstEnergy's operations or other construction activities. The Contractor shall maintain close cooperation and flexible working arrangements with FirstEnergy in consideration of adjacent structures and work. The Contractor shall maintain close cooperation with other contractors working at the site.

Upon commencing work, the Contractor shall establish and maintain sanitary facilities for its employees and those of its Subcontractors, to the extent such facilities are not provided by FirstEnergy and in conformity with local and state regulations. The Contractor will remove these facilities upon completion of the Agreement and clean the site to FirstEnergy's satisfaction.

Contractor shall maintain adequate project security guards and procedures for the area of any work to be performed under a Subproject. Without limiting Contractor’s obligations hereunder, FirstEnergy may at its discretion provide a security guard at the entrance and exits to the site who shall have the right to check all persons entering and leaving the site, check all automobiles, cars and trucks and carry out such control of persons and vehicles as deemed necessary.

(F)Sales Prohibited. The Contractor is advised that the sale of anything (i.e. food, beverages, articles of clothing, etc.) on FirstEnergy's Site by the Contractor's or Subcontractor's personnel is strictly prohibited.

(G)Arrival and Departure of Contractor's Tools, Equipment, and Materials.

(1)Mobilization:

The Contractor shall provide the necessary resources to receive all material or equipment the Contractor or Subcontractors have shipped to FirstEnergy’s Site.

The Contractor shall be responsible for providing FirstEnergy's Designated Representative with the detailed packing lists of all tools, equipment, and materials the Contractor is bringing onto the jobsite. The list(s) shall have been provided to FirstEnergy’s Designated Representative prior to the time the shipment of such tools, equipment, and materials arrive at the site. Contractor shall, where known, identify the specific Subproject associated therewith and itemize such tools, equipment, and/or materials on separate forms.

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(2)Demobilization

The Contractor shall provide to FirstEnergy proper verification of ownership of all tools, equipment, and materials being removed from the jobsite at anytime.

The Contractor shall prepare and submit new forms (not marked up original forms used to bring the tools, equipment, and materials onto the jobsite) itemizing the tools, equipment, and materials leaving the jobsite for each individual shipment.

The forms shall be signed by the Contractor's Project Manager or his designee signifying that everything listed on the form(s) as being removed from the jobsite is the property of the Contractor.

The Contractor shall prepare sufficient copies of the forms to provide at minimum one copy for FirstEnergy's Designated Representative and one copy to be left with the security guard when leaving the jobsite.

The Contractor shall be responsible for providing at least a minimum 24 hour notification of the tools, equipment, and materials that are being readied for shipment off the jobsite.

The Contractor shall, prior to beginning to pack and load tools, equipment, and materials for shipment off the jobsite, contact FirstEnergy's Designated Representative to determine if FirstEnergy desires to be present to monitor the packing and loading process. Should the Contractor fail to notify FirstEnergy's Designated Representative prior to packing and loading any shipment, thus resulting in FirstEnergy's inability to verify the tools, equipment, and materials being shipped, all costs to redo the entire loading process from the beginning will be to the Contractor's account.

FirstEnergy retains the sole option to perform a total or partial ownership verification audit of all Contractors' shipments leaving the jobsite.

(H)Radio Equipment. The Contractor shall not use any two-way radios or radio controlled equipment in the performance of work covered in this Agreement unless:

(1)The Contractor shall notify FirstEnergy, in writing, listing all such frequencies proposed, their effective radiated power (ERP) and dBm, and, in the situation of radio controlled equipment, the receiver sensitivity, selectivity and coding.

(2)FirstEnergy has received a copy of the current FCC authorization/license document covering the radio frequencies for which the Contractor has been granted by the FCC an authorization/license. The Contractor shall also notify FirstEnergy as to the location of the original document, who in the Contractor’s organization is responsible for its renewal and equipment maintenance and whereon the jobsite the document or copy thereof will be posted.

3.6Certificates, Permits and Licenses. Except as otherwise expressly agreed in writing, Contractor shall obtain all Permits which are required to be obtained in Contractor’s own name to perform the Project. Contractor shall provide FirstEnergy with copies of such Permits as soon as they are obtained. Contractor shall provide information, assistance and documentation to FirstEnergy as reasonably requested in connection with any Permits to be obtained by FirstEnergy.

3.7Books, Records and Audits.

(A)Contractor shall keep such full and detailed Project records including books, construction logs, records, daily reports, accounts, payroll records and other pertinent documents as may be necessary for proper financial management under this Agreement and as required under Applicable Law. Contractor shall maintain all such books and records in accordance with applicable generally accepted accounting principles. Contractor shall also retain all non-identical copies of all records and documents (including records and documents in electronic form) as are required to be retained under the NSR Consent Decree. The Parties shall determine a records retention protocol during the Development Phase. Contractor shall grant FirstEnergy such access to such records as is required for FirstEnergy to comply with the NSR Consent Decree.

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(B)With respect to each Subproject, upon reasonable notice during the [******] year period following Final Completion, FirstEnergy or its designee shall have the right to audit or to have audited the Project books and records of Contractor which relate to any work under this Agreement. When requested by FirstEnergy, Contractor shall provide the auditors with reasonable access to all personnel relevant to the audit, property, and records, and Contractor’s personnel shall cooperate with the auditors to effectuate the audit or audits hereunder. The auditors shall have the right to copy any and all documentation relating to performance of cost reimbursable work under this Agreement. Contractor shall pay for all reasonable internal costs (except personnel assigned to any Subproject) incurred by it in assisting FirstEnergy with one yearly audit performed pursuant to this Section 3.7. For audits performed more frequently than yearly during the foregoing period, FirstEnergy shall pay for such Contractor reasonable internal costs, except in the event that such audits discover any errors in Contractor’s billing during such period. Contractor shall include audit provisions identical to this Section 3.7 in all Subcontracts. FirstEnergy shall have no right to examine, audit, or evaluate the basis underlying any hourly rates of Contractor professional labor or other fixed elements of compensation agreed to in the rate sheets included in Exhibit 5.1.

3.8Hazardous Substances.

(A)Use of Hazardous Substances by Contractor. Contractor, any Subcontractor or its or their personnel, agents or representatives may only bring onto, use, store or locate on the Site such Hazardous Substances as are necessary for the performance of the Project. If such Hazardous Substances are brought onto, used, stored or located on the Site by Contractor or any Subcontractor or its or their personnel, agents or representatives, Contractor shall exercise or cause to be exercised the utmost care and skill and shall carry on its activities under the supervision of properly qualified personnel in accordance with Applicable Law. Before Final Completion of each Subproject, Contractor shall (i) remove all such Hazardous Substances previously brought onto, stored, used or located on the Site by Contractor or the Subcontractors in connection with the delivery, installation, commissioning, characterization or testing of such work (unless the same have been permanently incorporated into the Project in accordance with Applicable Law); and (ii) certify that removal in writing to FirstEnergy.

(B)Assumption of Risk. Contractor shall retain and assume the risk of all Hazardous Substances brought onto, used, stored or located on the Site and under the control of Contractor or a Subcontractor or its or their personnel, agents or representatives, and shall be responsible, at its sole cost, for the proper handling, collection, storage, removal, use, clean-up, transportation and disposal of such Hazardous Substances.

(C)Notice of Presence. Contractor shall provide FirstEnergy with (i) written notice of the existence of any Hazardous Substances which Contractor or the Subcontractors or its or their personnel, agents or representatives bring onto the Site; and (ii) appropriate instructions for shipping, handling, exposure to and disposal of such Hazardous Substances, as required by Applicable Law.

(D)Compliance with Applicable Law. Contractor or the Subcontractors or its or their personnel, agents or representatives shall not introduce or release or allow to be introduced or released from the Site or handle, collect, remove, transport or dispose of Hazardous Substances in violation of Applicable Law.

(E)Other Environmental Compliance Requirements. Contractor and its Subcontractors shall comply with the requirements set forth in Exhibit 3.8(E)-1 (Asbestos Handling and Removal ), Exhibit 3.8(E)-2 (Inorganic Arsenic), and Exhibit 3.8(E)-3 (Lead Abatement Terms of Reimbursement) in connection with the Project.

(F)Pre-existing Hazardous Substances. Contractor shall not be responsible or liable for dealing with, handling or disposing of Hazardous Substances which are pre-existing at, under, above, on or adjacent to the Site. If, in the course of performance of the Project, the Contractor encounters on the Site any matter which it reasonably believes is a Hazardous Substance, the Contractor shall immediately suspend the work in the area affected and report the condition to FirstEnergy in writing. In any such event, the obligations and duties of the Parties hereto shall be as follows:

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(1)If it is determined that such condition involves a pre-existing Hazardous Substance, then any required, necessary or appropriate remedial actions shall be performed by FirstEnergy at its sole cost and expense;

(2)If it is determined that such condition involves a Hazardous Substance introduced to the Project Site after the date of this Agreement by the Contractor, its Subcontractors or any Person for whom either may be liable, then any required, necessary or appropriate remedial actions shall be performed by the Contractor at its sole cost and expense; or

(3)If it is determined that the condition does not involve a Hazardous Substance, the Contractor shall, promptly after receiving written notice from FirstEnergy authorizing the Contractor to recommence site activities in the subject area, resume the portion of the work that had been suspended.

3.9Quality Control, Testing and Inspection. The Project Execution Plan to be developed by the Parties during the Development Phase shall establish quality control, testing, and inspection processes including the following:

(A)Contractor Responsibility. Contractor shall be responsible for all quality assurance, quality control, testing and inspection activities related to the Project, including all Materials, whether such work is performed by Contractor or Subcontractors. During the Development Phase, Contractor shall submit to FirstEnergy for its review a project specific quality assurance, quality control, testing and inspection plan, but excluding tests and inspections relating to Performance Tests. FirstEnergy may review and comment on, without assuming liability for, such quality assurance, quality control, testing and inspection procedures, and Contractor shall make revisions in accordance with FirstEnergy’s comments. Contractor’s quality assurance plan shall provide for a quality assurance individual or individuals to be present at the Site to supervise the implementation of the quality assurance, quality control, testing and inspection plan, including all such quality assurance plan requirements as may be described in FirstEnergy’s Requirements. FirstEnergy shall be provided reasonable access during normal working hours to Contractor’s and the Subcontractors’ facilities for inspection of all testing activities related to the Project or any portion thereof and shall be given ten (10) Business Days notice prior to the commencement of any such testing to ensure that FirstEnergy is able to be present for all such tests. Records of all testing and inspection work by Contractor shall be kept complete and available to FirstEnergy during the performance of this Agreement and for such longer period as may be specified by Contractor’s standard recordkeeping practices.

(B)FirstEnergy Rights.If any work or component thereof at the Site has a Warranty Non-Conformance and cannot be repaired, Contractor shall dispose of same at no cost to FirstEnergy. If Contractor fails to dispose of such work or component on a timely basis, then FirstEnergy may dispose of such work or component in a reasonable manner and shall be entitled to obtain reimbursement for all reasonable expenses incurred by FirstEnergy in the disposition thereof.

3.10Progress Reporting. The Project Execution Plan to be developed by the Parties during the Development Phase shall establish a progress reporting process including the following:

(A)Monthly Progress Reports. On or before the fifth Business Day of each month, Contractor shall submit to FirstEnergy, along with the Updated Critical Path Schedule, a monthly progress report in a form acceptable to FirstEnergy, which shall cover all activities up through the 23^rd day of the preceding month (the “Monthly Progress Report”). Contractor shall provide FirstEnergy with the number of copies of such reports and shall arrange for the distribution thereof as FirstEnergy may reasonably request.

(1)The Monthly Progress Report shall include the following information:

(i)an executive summary with a description of overall status and progress of the Project;

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(ii)a description, as compared with the Project Schedule and the Critical Path Schedule, of engineering status including actual percentage complete versus planned percentage, document status, significant activities accomplished the previous month and significant activities planned for the current month;

(iii)a description, as compared with the Project Schedule and the Critical Path Schedule, of procurement activities including actual percentage complete versus planned percentage, manufacturing and delivery status, significant activities accomplished the previous month and significant activities planned for the current month;

(iv)a description, as compared with the Project Schedule and the Critical Path Schedule, of construction activities including actual percentage complete versus planned percentage, progress summary, numbers of skilled, unskilled, and supervisory staff on Site compared to planned levels, significant activities accomplished the previous month and significant activities planned for the current month;

(v)a description of critical items, including an evaluation of problem areas, and, to the extent applicable, of strategies to recovery any delays so as to comply with the Project Schedule and the Critical Path Schedule and the expected completion date for such delayed or problematic areas or activities;

(vi)a description of all permitting and environmental issues;

(vii)a description of all safety and security issues;

(viii)a description of quality assurance, quality control, inspection and testing activities;

(ix)progress photos, including a description of the photograph and the date taken; and

(x)any other information reasonably requested by FirstEnergy, including any material information of which Contractor is aware that could reasonably be foreseen to adversely affect the performance of the Project.

(B)Other Contractor Provided Information. Contractor shall provide FirstEnergy with such other information as reasonably requested by FirstEnergy, including the following:

(1)Minutes for all status and other project meetings within five (5) Business Days following such meeting; and

(2)Safety incident reports within three (3) Business Days of the occurrence of any such incident.

(3)Progress reports at such other intervals as may be requested by FirstEnergy.

(C)Review Meetings. Contractor shall conduct review meetings with FirstEnergy in person (or if approved by FirstEnergy, by telephone) within five (5) Business Days after the submission of each Monthly Progress Report and Updated Critical Path Schedule and at such other intervals as may be requested by FirstEnergy, at a mutually agreeable location and time to review the status of the Project.

(D)Additional Reports. If any material problem, emergency, strike, injury, work stoppage or legal problem is anticipated, or any unanticipated event occurs, that might adversely affect Contractor’s ability to perform its obligations hereunder in a timely manner, in addition to other reports, notices and actions required hereunder, Contractor shall promptly prepare a written report detailing available information and steps being taken or taken to correct such problem or event and shall deliver such report to FirstEnergy as soon as reasonably practicable. FirstEnergy may at any time request such report with respect to any event that FirstEnergy reasonably regards as significant.

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3.11NSR Consent Decree. Per the disclosure requirements of the NSR Consent Decree, Contractor acknowledges that it has received a copy of the NSR Consent Decree, and shall provide a copy of the NSR Consent Decree to all Subcontractors and any other company or other organization retained by Contractor to perform any of the work under this Agreement.

3.12FirstEnergy’s Review and Approvals. FirstEnergy’s review or approval of, or right to review and approve, any work provided or performed by Contractor and its Subcontractors under this Agreement (including approval of Drawings and Specifications, Subcontractors, safety and environmental protection guidelines, quality assurance, quality control, testing and inspection procedures) shall not in any way be deemed to limit or in any way alter Contractor’s responsibility to perform and complete the Project in strict accordance with the requirements of this Agreement, or Contractor’s obligations under Article 13 (Warranty).

ARTICLE 4 - FIRSTENERGY’S RESPONSIBILITIES

FirstEnergy shall comply with the following provisions in a timely manner:

4.1Payment. FirstEnergy shall timely pay the Contract Price required to be paid by it to Contractor pursuant to the terms of this Agreement, and in accordance with the provisions of Article 5 hereof.

4.2Permits. FirstEnergy shall provide Contractor with copies of all Permits obtained by FirstEnergy related to the Project as soon as they are obtained. FirstEnergy shall provide information, assistance and documentation to Contractor as reasonably requested in connection with the Permits to be obtained by Contractor hereunder.

4.3Access to the Site. FirstEnergy shall provide Contractor with reasonable access to the Site within the time (or times) stated in the Project Schedule. Such access shall be sufficient to permit Contractor to progress with construction on a continuous basis without substantial interruption or interference.

4.4Other Responsibilities. FirstEnergy shall perform or cause to be performed any obligation of FirstEnergy explicitly provided in the Agreement.

ARTICLE 5 - PRICE; PAYMENTS TO CONTRACTOR

5.1Price. FirstEnergy will compensate Contractor in the manner and at the times specified in Exhibit 5.1. FirstEnergy may request different pricing arrangements for any Subproject, but subject to the consent and agreement of Contractor.

5.2Interim Payments.

(A)Invoices.

(1)With respect to each Subproject, Contractor shall submit to FirstEnergy invoices for payments due as provided in Exhibit 5.1. An invoice shall constitute a representation by Contractor, and Contractor shall provide to FirstEnergy and such other Persons as FirstEnergy may designate a certificate to the effect, that: (a) the Subproject is progressing in accordance with the Project Schedule and the Critical Path Schedule, or shall specify any reasons why such is not the case; (b) the quality of all work described in the invoice is in accordance with the terms of this Agreement, or shall specify any reasons why such is not the case; (c) Contractor is entitled to payment of the amount invoiced; (d) the work (or any portion thereof) described in the statement accompanying the invoice and all previous invoices are free and clear of all liens, security interests and encumbrances; and (e) all Subcontractors have been paid the monies due and payable to them for work performed (except for such amounts as may be disputed in good faith by Contractor).

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(2)Invoices shall be submitted to FirstEnergy’s Designated Representative for approval and payment. The elements of all amounts invoiced shall be shown separately, by applicable line items, and shall be classified or further broken down as FirstEnergy may require for accounting and payment purposes. Any disputed invoice or portion thereof need not be paid, but in such case, FirstEnergy shall promptly notify Contractor of any rejected invoice or portion thereof with reasons for such rejection. Specific details of the invoicing process are as follows:

(i)By the [******] of the month in advance of the cost being incurred, Contractor will electronically submit two payment requests to FirstEnergy. The first payment request will be equal to [******}% of the estimated sum of all reimbursable costs that Contractor anticipates billing to FirstEnergy for the month the cost will be incurred, adjusted by an amount equal to the difference (deficiency or excess) between the payments received for the month preceding the date of invoice and the actual costs incurred for such preceding month; adding the amount of the deficiency or subtracting the amount of the excess. The second payment request will be equal to [******]% of the estimated sum of all reimbursable costs that Contractor anticipates billing to FirstEnergy for the month the costs are incurred.

(ii)FirstEnergy will electronically transfer funds on a date that will allow Contractor to receive payment for the first payment request by the [******] day of the month in advance of the cost being incurred and the second payment request by the [******] day of the month the cost will be incurred.

(iii)As soon as practical after the close of each monthly accounting period, Contractor will electronically submit to FirstEnergy a Statement of Reimbursable Cost for the accounting period just ended. Contractor will make its best efforts to issue this statement on or prior to the [******] day of the following month. The statement will be supported by a schedule of charges, together with any supporting records, invoice copies, payroll abstracts and/or other documentation that FirstEnergy reasonably requires. Along with each statement, Contractor will submit a reconciliation of monthly payments and reimbursable costs incurred. The reconciliation will include monthly payments received and cost incurred for the latest period and from inception-to-date.

(iv)FirstEnergy will not withhold payment of any undisputed amount which is due Contractor beyond the date payment is due under the Contract.

(v)Interest will be accrued and payable to Contractor on undisputed amounts that are due and remain unpaid with such accrual to begin [******] days after the payment due date. Interest will be due at the rate of the prime rate as specified under the caption “Money Rates” in the Wall Street Journal (New York Edition dated the date such interest begins to accrue) plus [******]%. The obligation to pay interest will be waived during the first [******] billing cycles under the first Subproject.

(vi)Fee shall be calculated in accordance with Exhibit 5.1 and Fee adjustments defined in Exhibit 5.1(A).

(vii)Payment of Fees for Engineering/Graphics Labor and Other Professional Labor will be paid using the same methodology used for payment of costs as provided in Sections 5.2(A)(2)(i) through (vi). Payment of Fees for all other amounts will be in accordance with the percentage of Construction Progress, as defined in the “Project Status” section of the Fee adjustment sheet provided in Exhibit 5.1-1(A).

(viii)Contractor will certify that all amounts due and payable to all Subcontractors prior to the end of the period covered by a Monthly Progress Report, unless reasonably disputed, have been paid in accordance with the terms of the Subcontracts.

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(3)Invoice charges shall be allocated to appropriate accounts, a list of which will be furnished by FirstEnergy. For work performed by the Contractor under Article 8 of this Agreement, the charges will be listed by FirstEnergy's Change Order documentation number (Field Change Request (FCR) Numbers, Maintenance Work Order (MWO) Numbers, Extra Work Request (EWR) Numbers, Contracted Services Change Order (CSCO) Numbers, etc.) and listed by current month and shall be supported by daily time sheets, accurately describing the work being performed, signed by FirstEnergy's Designated Representative showing the craft, first and last names and a unique personal identification number of each worker and each piece of equipment employed on the Project. All material charges shall be supported by the original invoices or other evidence as required by FirstEnergy to substantiate the charges submitted.

(B)Payment. Each invoice shall, after approval by FirstEnergy, be processed for payment for the amount of each approved invoice less any monies withheld under Section 5.4 below. Payments by FirstEnergy shall not be deemed evidence of acceptance by FirstEnergy of the services or goods called for hereunder.

(C)Interim Lien and Claim Waivers. Each invoice prior to Final Completion of each Subproject shall be accompanied by a fully executed Contractor’s Interim Lien and Claim Waiver in the form set forth in Exhibit 5.2(C) for all work performed through the date for which payment is requested, and fully executed Interim Lien and Claim Waivers from each Subcontractor (other than with respect to Subcontracts with a total payment obligation of less than $500,000) in the form set forth in Exhibit 5.2(C) for all work performed through the date for which payment is requested.

5.3Final Payment. Upon Final Completion of each Subproject, Contractor shall, in addition to the other requirements in the Agreement, submit a statement summarizing and reconciling all previous invoices, payments and Change Orders, and an affidavit that all payrolls, payroll taxes, liens, charges, claims, demands, judgments, security interests, bills for Materials, and any other indebtedness connected with the Project have been paid, accompanied by a fully executed Contractor’s Final Lien and Claim Waiver in the form set forth in Exhibit 6.3(A) and fully executed Final Lien and Claim Waivers from each Subcontractor in the form set forth in Exhibit 6.3(A).

5.4Withholding. Should FirstEnergy in good faith dispute any portion of an invoice, FirstEnergy shall be entitled to withhold payment of the disputed portion provided that FirstEnergy gives notice to Contractor of such disputed portion, together with reasons for such dispute, within the period specified for payment in Section 5.2(A)(2)(ii). FirstEnergy shall also pay the undisputed portion of the invoice within such period. In addition to disputed amounts in an invoice, FirstEnergy may withhold payment of all or any portion of any invoice, in the amount reasonably necessary to protect FirstEnergy in the event that: (A) a third party claim has been asserted for which Contractor has an indemnity obligation under Section 16.1 unless Contractor is satisfying the obligation; (B) Contractor has failed to make a payment as and when due to a Subcontractor or supplier for materials, labor or equipment; or (C) Contractor has failed to supply any affidavit, release or waiver of lien which is required pursuant to this Agreement. If any monies are so withheld, they shall be paid only when the cause of such withholding has been eliminated. Moreover, if any monies are so withheld, FirstEnergy shall not be responsible for any interest payment to Contractor. In the event any controversy, claim or dispute between the Parties relating to non-payment of any disputed amounts, including any Change Order, Contractor shall, unless otherwise agreed in writing by the Parties or terminated by FirstEnergy pursuant to Article 15, continue with the Project, and FirstEnergy shall continue to pay all undisputed amounts owed to Contractor under the Agreement.

5.5Retainage for Final Subproject. FirstEnergy shall be entitled to retain a portion of the Fee payable with respect to the final Subproject of the Project, in an amount sufficient to provide for any difference between the amount of Fees paid to Contractor during the Project (including any other Subproject) and the amount finally determined to be due. The retainage shall be released upon Final Completion and Final Document Delivery of the final Subproject of the Project. No interest will be payable by FirstEnergy on the amount of the retainage prior to payment thereof. Contractor may provide a letter of credit with mutually satisfactory terms, or other payment security acceptable to FirstEnergy in lieu of any retainage provided under this Section 5.5.

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5.6Sales Tax.

(A)Direct Pay Permit. A Direct Payment Permit authorizing the purchase of tangible personal property without payment of the tax at the time of purchase has been issued to FirstEnergy Generation Corp. The Permit Number for FirstEnergy Generation Corp. is 98-002723. FirstEnergy agrees to maintain adequate records of all purchases and pay tax on the taxable items directly to the Treasurer of the State of Ohio. The Direct Payment Permit does not apply to construction contracts under which the contractor is considered to be the consumer and liable for the tax on materials incorporated into a structure or improvement as provided in Section 5739.01 (B) Ohio Revised Code.

(B)Tax Exempt Project - FirstEnergy states that the overall Project is defined by Ohio Revised Code § 5709.20 and is anticipated to be exempt from Ohio Sales and Use Taxes under Ohio Revised Code § 5709.25. All parties to this contract will work together to minimize FirstEnergy’s sale and use tax liability by taking the following actions:

(1)Contractor - The Contractor will register for Ohio sales tax purposes as a vendor, thereby gaining the ability to issue Ohio “Resale Exemption Certificates” when purchasing items to be incorporated into the “facility”, and sold to FirstEnergy.

(2) Contractor retains the sales and use tax liability to report or pay Ohio sales and use taxes on its purchase, lease or rental of office supplies, construction tools and equipment used in performing the work. Taxes required to be paid related to the foregoing shall be reimbursed as a reimbursable cost pursuant to Section 5.1.

(3)FirstEnergy Generation Corp. either has or will apply for an Ohio “Pollution Control Facilities” exemption certificate as provided by Ohio Revised Code § 5709.25.

(4)In the event that FirstEnergy is unable to obtain the "pollution control facility" exemption, or in the event that Contractor is prohibited by Ohio governmental authorities from taking the actions provided in subsection (i) above, FirstEnergy acknowledges that Ohio sales and use taxes as it relates to the work performed under this Agreement are reimbursable as a reimbursable cost pursuant to Section 5.1(A).

Any questions as to the application should be submitted to:

Director, Tax Planning & Compliance

FirstEnergy Corp.

76 S. Main Street

Akron, OH 44308

Phone Number: (330) 384-5256

5.7No Release. Final payment shall not in any way release Contractor or any surety of Contractor from any unperformed obligations of this Agreement, including its warranties, obligations, any liabilities for which insurance is required or any other responsibility of Contractor. It is expressly understood and agreed to by the Parties that nothing in this Article 5 shall in any way modify or alter Contractor’s obligations under this Agreement.

ARTICLE 6 - PROJECT SCHEDULE; COMMENCEMENT OF PROJECT; MECHANICAL AND FINAL COMPLETION; SCHEDULED LIQUIDATED DAMAGES

6.1Commencement of Project. The Project will be released to Contractor in Subprojects, as set forth in Section 3.1(A). Upon execution of a Notice to Proceed, Contractor shall commence with the performance of the work specified in such Notice to Proceed.

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6.2Mechanical Completion.

(A)Definition of Mechanical Completion. “Mechanical Completion” for each Subproject (or any AQC Unit, as applicable) shall be deemed to have occurred only upon the completion of the procurement, fabrication, installation, and inspection of all necessary components and systems of the Subproject (or AQC Unit, as applicable) (including all non-destructive examinations and static integrity tests, such as hydrostatic and pneumatic pressure or tightness tests, radiography tests, and other pre-operational mechanical and electrical tests, calibrations, clean-outs and flushes) to the extent necessary to permit Performance Testing. Prior to Mechanical Completion, Contractor shall perform and provide FirstEnergy with documentation of all checks and tests required to ensure that the Subproject has been correctly installed and is capable of being operated safely and reliably within the requirements of the Agreement and without damage or injury to the Project, the Site, or any other property or person.

(B)Notice of Mechanical Completion. Contractor shall provide written notice to FirstEnergy at such time as the Subproject (or AQC Unit, as applicable) has achieved Mechanical Completion. Within fifteen Business Days of such notice, FirstEnergy shall respond to Contractor in writing that the Subproject (or AQC Unit, as applicable) has achieved Mechanical Completion on the date stated in Contractor’s notice or provide Contractor with reasons why FirstEnergy disputes that Mechanical Completion was achieved on such date.

6.3Final Completion.

(A)Definition of Final Completion and Final Document Delivery.

“Final Completion” for each Subproject (or any AQC Unit, as applicable) shall be deemed to have occurred only upon completion of the following requirements for the Subproject (or the AQC Unit, as applicable): (i) Mechanical Completion has been achieved; (ii) Performance Tests have been successfully completed, or at the election of Contractor (but provided in the case of the Wrap Arrangement, solely in the event that the Performance Tests have resulted in the removal of at least [******]% of SO2). Contractor has paid FirstEnergy any and all undisputed Performance Liquidated Damages owed by Contractor and its Subcontractors; (iii) Contractor has paid FirstEnergy any and all undisputed Schedule Liquidated Damages owed; (iv)  the Reliability Standard has been achieved; (v) Contractor has delivered to FirstEnergy a Final Completion Certificate, which FirstEnergy has approved (provided, for purposes of clarity, that the date of delivery of a conforming and correct Final Completion Certificate, and not the date of approval thereof by FirstEnergy, shall be deemed the date on which this requirement has been completed); (vi) Contractor has obtained all Permits required in connection with the performance thereof; (vii) Contractor has removed all Hazardous Substances for which it is responsible under Section 3.8(A) and provided to FirstEnergy written certification thereof, as provided in Section 3.8(A); (viii) Contractor has removed all supplies, waste, materials, rubbish, and temporary facilities from the Site (except to the extent the Parties mutually agree the same are necessary to performing additional AQC Units or Subprojects); (ix) the Subproject (or AQC Unit, as applicable) has been fully completed as required under the Agreement, except for items of incomplete work which do not impair the operation thereof.

“Final Document Delivery” for each Subproject (or any AQC Unit, as applicable) shall be deemed to have occurred only upon completion of the following requirements: (a) Contractor has delivered to FirstEnergy a fully executed Contractor’s Final Lien and Claim Waiver in the form of Exhibit 6.3(A) and fully executed Final Lien and Claim Waivers from all Subcontractors in the form of Exhibit 6.3(A); (b) Contractor has delivered to FirstEnergy all documentation required to be delivered under the Agreement, including Drawings and FirstEnergy’s Confidential Information ; (c) Contractor has assigned or provided FirstEnergy with all warranties to the extent Contractor is obligated to do so pursuant to this Agreement.

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(B)Guaranteed Final Completion Dates. Contractor shall achieve Final Completion and Final Document Delivery in accordance with the dates set forth in the Project Schedule to be developed and delivered pursuant to Section 6.4 (“Guaranteed Final Completion Dates”). The parties anticipate that the Project Schedule for the Subproject associated with Generating Units 1 through 4 of the Sammis Plant will designate a separate Guaranteed Final Completion Date for each AQC Unit within that Subproject. At the election of FirstEnergy, the Project Schedule for the Subproject associated with Sammis Plant Generating Units 5, 6, and 7 will designate either a single Guaranteed Final Completion Date for all AQC Units within that Subproject, or separate Guaranteed Final Completion Dates for each AQC Unit within that Subproject (with an adequate time allowed between the Scheduled Mechanical Completion Dates established for Generating Units 5, 6 and 7).

(C)Notice of Final Completion. When Contractor believes it has achieved Final Completion, Contractor shall deliver to FirstEnergy a written notice and certification thereof (“Final Completion Certificate,” which shall be in the form of Exhibit 6.3(C)), certifying to FirstEnergy that all of the requirements for Final Completion have occurred. The Final Completion Certificate shall be accompanied by all other supporting documentation as may be required to establish that the requirements for Final Completion have been met.

(D)FirstEnergy Acceptance of Final Completion. FirstEnergy shall notify Contractor whether it accepts or rejects the Final Completion Certificate within thirty (30) days following receipt of such notice. If FirstEnergy agrees that Final Completion has occurred, FirstEnergy shall deliver to Contractor a written acceptance of Final Completion. If FirstEnergy does not agree that Final Completion has occurred, then FirstEnergy shall state the basis for its rejection in reasonable detail in the written notice provided to Contractor. In the event that Final Completion has not been achieved, Contractor shall promptly take such action or perform such additional work as will achieve Final Completion and shall issue to FirstEnergy another Final Completion Certificate. Such procedure shall be repeated as necessary until Final Completion is achieved.

6.4Project Schedule.

(A)Project Schedule; Critical Path Schedule. With respect to each Subproject, during the Development Phase, Contractor shall prepare and submit to FirstEnergy for its review a detailed Project Schedule, and critical path method schedules for the Subprojects and for the Project as a whole, which shall be submitted in native electronic and paper form (“Critical Path Schedule”). The Project Schedule and Critical Path Schedule shall govern Contractor’s performance of the Subproject. The Contractor shall use its best efforts to cause the Project Schedule and Critical Path Schedule to be consistent with the timetables, goals and objectives of FirstEnergy, including achievement of the compliance dates established in the NSR Consent Decree. The Critical Path Schedule shall represent Contractor’s best judgment as to how it shall complete the Subproject in compliance with the Project Schedule and the Guaranteed Final Completion Date. The Critical Path Schedule shall be a detailed graphic representation of all significant aspects of the Subproject, showing Contractor’s plans for performance of the Subproject. Without limiting the generality of the foregoing, the Critical Path Schedule shall:

(1)include separate activities for each portion of the Subproject performed by Contractor, its Subcontractors, or FE Vendors, along with non-physical activities related to the Subproject, such as the submittal and approval of shop drawings, product data, samples, Drawings and Specifications, procurement of Materials, inspection and testing of the Subproject, and obtaining Permits;

(2)be detailed such that no activity is longer than fifteen (15) days;

(3)show the duration, early/late start dates, early/late finish dates and available float for each activity. Float time shall not belong to either Party, and shall be allocated as needed during the progress of the Subproject;

(4)show the percentage completion as of the date thereof;

(5)identify the Person responsible for the activity;

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(6)for cost-reimbursable work, show the projected manpower to be used per activity, whether provided by Contractor or its Subcontractors, showing the number of personnel, the positions and titles of such personnel and a general description of the work being performed;

(7)show the Scheduled Mechanical Completion Date, the Guaranteed Final Completion Date and all other milestones listed in the Project Schedule;

(8)include allocations of resources among the scheduled activities; and

(9)reflect logical relationships between activities, reasonable durations and adequate float time to account for existing conditions and foreseeable complications.

The Critical Path Schedule shall be the schedule which Contractor shall use in planning, organizing, directing, coordinating, performing and executing the Subproject (including all activities of Subcontractors and FE Vendors) and shall be the basis for evaluating progress of the Subproject.

(B)FirstEnergy Review of Schedule. FirstEnergy may review the Critical Path Schedule for general conformance with this Agreement. If FirstEnergy determines at any time that the Critical Path Schedule does not conform with this Agreement or the Project Schedule in any respect, Contractor shall promptly revise and resubmit the Critical Path Schedule to FirstEnergy. FirstEnergy’s review of the Critical Path Schedule shall not relieve Contractor of any obligations for the performance of the Project, change any Project Schedule milestone or any Guaranteed Final Completion Date, or be construed to establish the reasonableness of the Critical Path Schedule. FirstEnergy may reasonably rely upon the Critical Path Schedule in FirstEnergy’s dealings with other contractors operating at the Site or any other Person.

(C)Updated Critical Path Schedule. Contractor shall update the Critical Path Schedule monthly and at such other intervals as may be requested by FirstEnergy by showing the actual progress of the Subproject; however, Contractor may not modify the Critical Path Schedule, including any of the Guaranteed Final Completion Dates or any Project Schedule milestone, without obtaining FirstEnergy’s prior written approval. Any modifications to any of the Guaranteed Final Completion Dates or Project Schedule milestones shall be only by Change Order. Contractor shall provide FirstEnergy monthly (weekly during the Generating Unit outage) with a current updated Critical Path Schedule in both hard copy and electronic form (“Updated Critical Path Schedule”) reflecting the actual progress of work against the Critical Path Schedule and Project Schedule. The Updated Critical Path Schedule shall be in the same detail and form as required by the Critical Path Schedule.

6.5Schedule Liquidated Damages. With respect to each Subproject (or any AQC Unit, as applicable), if Final Completion occurs after the Guaranteed Final Completion Date and/or if Final Document Delivery occurs after the date of Final Completion (or in the case of a Subproject making use of the Powerspan ECO technology, if Mechanical Completion occurs after the Scheduled Mechanical Completion Date), and Contractor is responsible for the payment of schedule liquidated damages for such delay in accordance with Exhibit 6.5, then Contractor shall pay such amounts to FirstEnergy in accordance with Exhibit 6.5 until Final Completion (or Mechanical Completion, in the case of a Subproject making use of the Powerspan ECO technology), and Final Document Delivery, as applicable (the “Schedule Liquidated Damages”). When any Schedule Liquidated Damages payment is owed under this Section 6.5 , FirstEnergy shall calculate such Schedule Liquidated Damages payment and invoice Contractor for such amount. Payment of such Schedule Liquidated Damages shall be due in arrears ten (10) days after delivery of such invoice.

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ARTICLE 7 - PERFORMANCE GUARANTEE; PERFORMANCE LIQUIDATED DAMAGES

7.1Performance Tests and Protocol. Performance Testing will be carried out in accordance with the Performance Test procedures to be mutually determined by the Parties during the Development Phase which shall be consistent with the requirements of the NSR Consent Decree and, with respect to matters not indicated in such document, in accordance with the standards and principles normally applied in test runs for plants of a similar kind. FirstEnergy shall provide labor, equipment, supplies, and all other items necessary for the conduct of the Performance Tests. The Performance Tests shall be conducted and the data obtained during the Performance Tests shall be analyzed by a Third Party, coordinated by Contractor and subject to the review and approval of FirstEnergy. A complete copy of all raw performance data and a detailed listing of all testing instrumentation utilized shall be provided to both Parties at the completion of testing.

7.2Performance Liquidated Damages. With respect to each Subproject, if such Subproject fails to achieve all of the Performance Guarantees listed in Exhibit 7.2 , Contractor shall, to the extent possible, within such time frame so as to not delay Final Completion, perform such repair, redesign and replacements as are required in order that such Subproject might achieve all Performance Guarantees. If, after exhausting repair, redesign and replacement alternatives, the Subproject fails to achieve all of the Performance Guarantees within the required time frame, and if the Contractor is responsible for the payment of Liquidated Damages for such failure in accordance with Exhibit 7.2, then Contractor shall pay, as Liquidated Damages and not as a penalty, the amount specified for such Performance Guarantee listed on Exhibit 7.2 (“Performance Liquidated Damages”).

ARTICLE 8 - CHANGE ORDERS

8.1Change Orders Requested by FirstEnergy. FirstEnergy shall be entitled to request change(s) to any Subproject by way of a Change Order request in accordance with this Section 8.1.

(A)FirstEnergy shall submit to Contractor a written proposed Change Order for each requested change. Contractor must respond to FirstEnergy within ten (10) Business Days with a written statement setting forth Contractor’s estimate as to the effect, if any, which such proposed Change Order would have on the Target Construction Cost, the Project Schedule, any Guaranteed Final Completion Dates, the Performance Guarantee, the Warranties, or any other obligation or potential liability of either Party hereunder (collectively, the “Changed Criteria”). To the extent reasonably practicable, the written statement shall include all information required by Section 8.5.

(B)If the Parties agree on such effect of the proposed Change Order (or modify such Change Order so that the Parties agree on such effect of all provisions as modified), the Parties shall execute such Change Order, and such Change Order shall become binding on the Parties.

(C)If the Parties cannot agree on such effect of the proposed Change Order within fifteen (15) Business Days of Contractor’s receipt of FirstEnergy’s proposed Change Order, or if FirstEnergy desires that the changed work set forth in the proposed Change Order commence immediately without the requirement of a written statement by Contractor, FirstEnergy may, by issuance of a unilateral Change Order, require Contractor to commence and perform such changed work (which Contractor shall be compensated for in accordance with Section 5.1), with the effect of such unilateral Change Order on the Changed Criteria to be determined as soon as possible. Pending resolution of any dispute, Contractor shall perform the work as specified in such unilateral Change Order and FirstEnergy shall continue to pay Contractor in accordance with the terms of this Agreement and any previous agreed Change Orders. When FirstEnergy and Contractor agree on the effect of such unilateral Change Order on all of the Changed Criteria, the Parties shall record such agreement by execution of a Change Order, which shall supersede the unilateral Change Order previously issued and relating to such changed work. Contractor shall utilize all reasonable efforts to commence the performance of the changed work or other obligations required in the unilateral Change Order within three (3) Business Days of receipt of such unilateral Change Order.

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8.2Change Orders Requested by Contractor.

(A)Contractor shall have the right to a Change Order in the event of any of the following occurrences:

(1)acts or omissions of any Governmental Authority, including changes in Applicable Law occurring after the Effective Date of this Agreement and changes in the terms of Permits or issuance of new Permits occurring after the Effective Date of this Agreement, which affect Contractor’s direct cost to perform the work under this Agreement, delay the time of performance of such work, or materially affects Contractor’s ability to achieve any Performance Guarantee offered by Contractor hereunder, other than with respect to United States import duties, acts of customs authorities, or acts by a Governmental Authority requiring compliance with Applicable Law existing prior to the Effective Date of this Agreement;

(2)acts or omissions of FirstEnergy or its agents which constitute a breach of this Agreement by FirstEnergy and which affect Contractor’s direct cost to perform the work under this Agreement, and, with respect to delays, interruptions, disruptions, interferences or hindrances caused by FirstEnergy or such Persons, to the extent allowed under Section 9.2;

(3)inaccuracy in FirstEnergy Reliable Information which materially affects Contractor’s direct cost to perform the work under the Subproject, materially delays the time of performance of the Subproject, or materially affects Contractor’s ability to achieve any Performance Guarantee offered by Contractor hereunder;

(4)discovery of Hazardous Substances for which Contractor has not assumed and retained the risk under Section 3.8(B), which affects Contractor’s direct cost to perform the work under this Agreement or delays the time of performance of such work; provided, however, that delays or other impacts to the Project caused by the subcontractor retained by FirstEnergy to perform lead abatement activities shall not be cause for a Change Order;

(5)a Force Majeure Event; or

(6)acts or omissions of an FE Vendor which materially and adversely affect Contractor’s direct cost of performance and, with respect to delays, interruptions, disruptions, interferences or hindrances caused by such FE Vendor, to the extent allowed under Section 9.2.

(B)Should Contractor desire to request a Change Order under Section 8.2, Contractor shall, pursuant to Section 8.5, notify FirstEnergy in writing and issue to FirstEnergy a request for a proposed Change Order in the form attached hereto as Exhibit 8.2, a reasonably detailed explanation of the proposed change and Contractor’s reasons for proposing the change, all documentation necessary to verify the effects of the change on the Changed Criteria, and all other information required by Section 8.5.

(C)If FirstEnergy agrees that a Change Order is necessary and agrees with Contractor’s statement of such effect of the proposed Change Order on the Changed Criteria, then FirstEnergy shall issue such Change Order, which shall be in the form of Exhibit 8.2 attached hereto, and such Change Order shall become binding on the Parties upon execution by the Parties of such Change Order.

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(D)If the Parties agree that Contractor is entitled to a Change Order but cannot agree on such effect of the proposed Change Order on the Changed Criteria within ten (10) Business Days of FirstEnergy’s receipt of Contractor’s written notice and proposed Change Order and all other required information, or if FirstEnergy desires that the changed work set forth in the proposed Change Order commence immediately, FirstEnergy may, by issuance of an unilateral Change Order in the form attached hereto as Exhibit 8.2, require Contractor to commence and perform such changed work (which Contractor shall be compensated for in accordance with Section 5.1), with the effect of such unilateral Change Order on the Changed Criteria (or if the Parties agree on the effect of such Change Order for some but not all of the Changed Criteria, the impact of each of the components of the Changed Criteria on which the Parties disagree) to be determined as soon as possible. Pending resolution of the dispute, Contractor shall perform the work as specified in such unilateral Change Order and FirstEnergy shall continue to pay Contractor in accordance with the terms of this Agreement and any previous agreed Change Orders. When FirstEnergy and Contractor agree on the effect of such unilateral Change Order on all of the Changed Criteria, such agreement shall be recorded by execution by the Parties of a Change Order in the form attached hereto as Exhibit 8.2, which shall supercede the unilateral Change Order previously issued and relating to such changed work.

(E)If the Parties cannot agree upon whether Contractor is entitled to a Change Order, then pending resolution of the dispute, Contractor shall continue to perform the work required under the Agreement, and FirstEnergy shall continue to pay Contractor in accordance with the terms of this Agreement and any previous agreed Change Orders.

(F)In the event that Contractor desires a change that it believes would be advantageous to the Subproject for reasons other than those set forth in Section 8.2(A), it shall notify FirstEnergy of the desired change and shall furnish to FirstEnergy, along with such notice, a request for a Change Order in the form attached hereto as Exhibit 8.2, including a reasonably detailed explanation of the proposed change and Contractor’s reasons for proposing the change, supported by all documentation necessary to verify the effects of the change on the Changed Criteria, including the information required under Section 8.5. Within ten (10) Business Days of receipt of Contractor’s notice and Change Order request with the required supporting documentation, FirstEnergy shall have the right in its sole and absolute discretion to reject Contractor’s Change Order request and shall notify Contractor of its decision. If FirstEnergy does not reply within such ten (10) Business Day period, FirstEnergy shall be deemed to have rejected the proposed change, and Contractor shall not be entitled to the corresponding Change Order.

8.3No Change Orders Due to Contractor Error or Deviation. Notwithstanding anything in this Article 8 to the contrary, no adjustment for the Target Construction Cost, the Project Schedule, any Guaranteed Final Completion Date, any scope of work under the Subproject, any of the Warranties, the Performance Guarantee or any other obligation of Contractor hereunder shall be made in connection with any completion, correction of errors, omissions or deficiencies in, or incomplete, improper or defective, work on the part of Contractor or any Subcontractor, or any deviation by Contractor from the scope of the Subproject which is not the subject of a prior Change Order.

8.4Change Orders Act as Accord and Satisfaction. Change Orders agreed pursuant to Section 8.1(B) or 8.2(C) by the Parties, and unilateral Change Orders entered into pursuant to Section 8.1(C) or 8.2(D) and which the Parties have subsequently agreed upon the effect of such unilateral Change Order and have executed a superceding and mutually agreed upon Change Order as provided in Section 8.1(C) or 8.2(D), shall constitute a full and final settlement and accord and satisfaction of all effects of the change as described in the Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change.

8.5Timing Requirements for Notifications and Change Order Requests by Contractor. Should Contractor desire to seek an adjustment to the Target Construction Cost, the Project Schedule, any Guaranteed Final Completion Date, the scope of work under the Subproject, the Performance Guarantee, Warranties or any other modification to any other obligation of Contractor under the Agreement for any circumstance that Contractor has reason to believe may give rise to a right to request the issuance of a Change Order, Contractor shall, with respect to each such circumstance,

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(A)notify the FirstEnergy Designated Representative in writing of the existence of such circumstance within fourteen (14) days (or such other period expressly provided under the Agreement) of the date that Contractor knew or reasonably should have known of the first occurrence or beginning of such circumstance, provided that Contractor shall use reasonable efforts to give such notice prior to the expiration of such fourteen (14) day period should any action or inaction by FirstEnergy or Contractor be required or necessary in relation to such circumstance to prevent or mitigate any damages to either Party and in either case, prior to commencement of work for which a Change Order may be requested (except in the event that such work is required to be immediately undertaken to avoid imminent loss or damage to property or persons). In such notice, Contractor shall state in detail all known and presumed facts upon which its claim is based, including the character, duration and extent of the claimed circumstance, the date Contractor first knew of the circumstance, any activities impacted by the circumstance, the cost and time consequences of the circumstance and any other details or information that are expressly required under this Agreement. Contractor shall only be required to comply with the notice requirements of this Section 8.5 once for continuing circumstances, provided the notice expressly states that the circumstance is continuing and includes Contractor’s best estimate of the time and cost consequences of the claimed circumstance; and

(B)submit to the FirstEnergy Designated Representative a request for a proposed Change Order as soon as reasonably practicable after giving FirstEnergy written notice but in no event later than ten (10) Business Days after the completion of each such circumstance, together with a written statement (a) detailing why Contractor believes that a Change Order should be issued, plus all documentation reasonably requested by or necessary for FirstEnergy to determine the factors necessitating the possibility of a Change Order and all other information and details expressly required under this Agreement (including the information required by Exhibit 8.2, schedules, detailed estimates and cost records, daily time sheets); and (b) setting forth the effect, if any, which such proposed Change Order would have for the work on any of the Changed Criteria.

8.6Adjustment Only Through Change Order. No change in the requirements of the Agreement, whether an addition to, deletion from, suspension of or modification to the Agreement, including any Subproject, shall be the basis for an adjustment for any change in the Target Construction Cost, the Project Schedule, any Guaranteed Final Completion Date, the scope of work under the Subproject, the Performance Guarantee, any Warranties or any other obligations of Contractor under this Agreement unless and until such addition, deletion, suspension or modification has been authorized by a Change Order executed and issued in accordance with and in strict compliance with the requirements of this Article 8 or as required pursuant to Section 19.4. No course of conduct or dealings between the Parties, nor express or implied acceptance of additions, deletions, suspensions or modifications to the Agreement, including any work, and no claim that FirstEnergy has been unjustly enriched by any such addition, deletion, suspension or modification to the Agreement, whether or not there is in fact any such unjust enrichment, shall be the basis for any claim for an adjustment in the Target Construction Cost, the Project Schedule, the scope of work under the Subproject, the Performance Guarantee, any Warranties or any other obligations of Contractor under this Agreement.

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ARTICLE 9 - FORCE MAJEURE; FIRSTENERGY DELAY; RECOVERY

9.1Force Majeure.

(A)Duties of the Affected Party. Within three (3) Business Days after becoming aware of the occurrence of a Force Majeure Event, the affected Party shall (i) provide written notice to the other Party containing full particulars of such Force Majeure Event (including the anticipated length of time that the delay may persist, the cause or causes of the delay, all measures taken or to be taken by the affected Party to prevent or minimize the delay, the schedule by which the affected Party proposes to implement those measures, and the affected Party’s rationale for attributing a delay to a Force Majeure Event), including the requirements set forth in Section 8.5, together with the obligations affected thereby, and (ii) use reasonable commercial efforts to mitigate the effect of such delay or failure and to remedy the Force Majeure Event. The affected Party shall resume performance of its obligations affected by the Force Majeure Event as soon as practicable after the conclusion of the Force Majeure Event, and shall give prompt written notice to the other Party of all significant facts and events concerning the affected Party’s efforts to perform and of the conclusion of the Force Majeure Event. Force Majeure Events shall not excuse any delay or failure to make payments when due and Contractor shall continue to be paid under this Agreement notwithstanding any Force Majeure Event. For purposes of this Section 9.1(A), Contractor shall be deemed to know of any circumstance of which Contractor or its Subcontractors knew or by the exercise of due diligence should have known.

(B)Effect of Force Majeure Event. Except as otherwise provided in Section 9.1, the affected Party’s obligations under this Agreement shall be suspended insofar as performance of such obligations is rendered impossible by a Force Majeure Event. Any delay or failure by the affected Party in the performance of any of its obligations under this Agreement on account of a Force Majeure Event shall not constitute a default under this Agreement during the period the Force Majeure Event is in effect to the extent such delay or failure is caused by the Force Majeure Event; provided that the affected Party shall have complied with its obligations under Section 9.1(A) as an express condition precedent; and provided that delay of Contractor in achieving Final Completion and Final Document Delivery with respect to any Subproject shall only be excused, and the Guaranteed Final Completion Date shall be extended, by one day for each day of delay during which (i) such Force Majeure Event made it impossible for Contractor to carry out all activities relating to such Subproject which are necessary to the fulfillment of Final Completion of such Subproject by the Guaranteed Final Completion Date and caused a delay to the critical path of the Critical Path Schedule; (ii) Contractor could not practicably recover by the use of due diligence and all reasonable commercial efforts, including the expenditure of moneys, overtime work, and work over weekends and holidays; and (iii) such Force Majeure Event was the direct and proximate cause of Contractor’s failure to meet such Guaranteed Final Completion Date. If Contractor seeks an extension of time to a Guaranteed Final Completion Date, it shall comply with Sections 8.2(B) and 8.5(B).

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9.2FirstEnergy-Caused Delay. In the event of any interruption, delay (including delay caused by FirstEnergy’s failure to respond to Drawings and Specifications within the 15 Business Day review period provided in Section 3.3(C)(3)), disruption, interference or hindrance to Contractor or the Subproject caused by FirstEnergy, its Affiliates, or any Person acting on behalf of or under the control of FirstEnergy (including any FE Vendor) which prevents or delays Contractor from performing the Project, Contractor may request, and shall justify by written notice to FirstEnergy pursuant to Section 8.5, an extension of time to the applicable Guaranteed Final Completion Dates and/or an adjustment of the Target Construction Cost within the time and in accordance with the notice requirements set forth in Section 8.5 for giving written notice. In addition, Contractor shall submit a request for a Change Order as required under Sections 8.2(B) and 8.5(B). Compliance with the requirements of Section 8.5 shall be a condition precedent to any extension of time to the applicable Guaranteed Final Completion Date or adjustment to the Target Construction Cost on account of a FirstEnergy-caused delay. Contractor is entitled to such extension only to the extent such delay is the result of actions or inactions of FirstEnergy, its Affiliates, or any Person acting on behalf of or under the control of FirstEnergy (including any FE Vendor): (a) constituting a breach of this Agreement (or in the case of an Affiliate of, or any Person acting on behalf of or under the control of FirstEnergy (including any FE Vendor), impacts the work being performed by Contractor under this Agreement), (b) is not attributable to Contractor or its Subcontractors, (c) affects the performance of work that is on the Critical Path Schedule (or the Updated Critical Path Schedule), (d) causes or will cause Contractor to finish beyond the Guaranteed Final Completion Date, and (e) Contractor is unable to proceed with other portions of the Project so as to not cause a delay in the Guaranteed Final Completion Date, provided that such extension is approved in writing by FirstEnergy, which approval shall not be unreasonably withheld.

9.3Recovery and Recovery Schedule. If at any time during the prosecution of the Subproject should the Updated Critical Path Schedule or Monthly Progress Report show that any activity on the critical path of the Critical Path Schedule is seven (7) or more calendar days behind schedule, FirstEnergy may require that Contractor prepare a schedule to explain and display how it intends to regain compliance with the Critical Path Schedule (“Recovery Schedule”). Contractor shall do the following after the determination by FirstEnergy of the requirement for a Recovery Schedule:

(A)Within five (5) calendar days of such determination, Contractor shall prepare the Recovery Schedule and submit it to FirstEnergy for its review and approval. The Recovery Schedule shall represent Contractor’s best judgment as to how the Subproject may regain compliance with the Critical Path Schedule. Contractor shall perform the Subproject in accordance with the Recovery Schedule.

(B)In preparing and executing the Recovery Schedule, Contractor shall take all steps necessary to regain compliance with the Critical Path Schedule, including additional shifts, additional manpower, overtime, providing additional equipment, and resequencing of activities.

(C)Contractor shall have the right to a Change Order under Section 8.2 for implementation of a Recovery Schedule which is required as a result of Force Majeure Event or a FirstEnergy-Caused Delay as described in Section 9.2.

ARTICLE 10 - COMPLIANCE WITH LAWS, REGULATIONS, AND PERMITS

10.1During the performance of this Agreement, the Contractor and FirstEnergy shall strictly comply with all federal, state and local laws, rules or regulations and executive orders applicable to the Project.

10.2Without limiting the foregoing, and where applicable, in connection with the Project, the Contractor agrees as follows:

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(A)The Contractor shall not discriminate against any employee or applicant for employment because of race, color, religion, sex or national origin. The Contractor shall take affirmative action to ensure that applicants are employed, and that employees are treated during employment, without regard to their race, color, religion, sex or national origin. Such action shall include employment, upgrading, demotion or transfer; recruitment or recruitment advertising; layoff or termination; rates of pay or other forms of compensation; and selection for training, including apprenticeship. Contractor shall post in conspicuous places, available to employees and applicants for employment, notices to be provided by the U.S. Department of Labor setting forth the provisions of this nondiscrimination clause.

(B)The Contractor shall state, in all solicitations or advertisements for employees placed by or on its behalf, that all qualified applicants will receive consideration for employment without regard to race, color, religion, sex or national origin.

(C)The Contractor shall send to each labor union or representative of workers with which it has a collective bargaining agreement, contract or understanding, a notice to be provided by the U.S. Department of Labor, advising the labor union or workers’ representative of the Contractor’s commitments under the following provisions, as amended from time to time:

(1)Section 202 of Executive Order 11246 (Equal Opportunity);

(2)Executive Order 11701 (Employment of Veterans);

(3)Executive Order 11758 (Employment of the Handicapped);

(4)Executive Order 11141 (Employment Discrimination Because of Age); and

(5)Executive Order 11625 and Public Law 95-507 (Utilization of Disadvantaged Business Enterprises),

and shall post copies thereof in conspicuous places available to employees and applicants for employment.

10.3Because FirstEnergy (or if applicable, one or more affiliates or non-affiliated companies) is a supplier of electricity and/or services to the U.S. government, it must include, and the Contractor shall comply with, the below listed clauses from the Federal Acquisition Regulation (“FAR”), 48 Code of Federal Regulations Chapter 1, as amended from time to time, if the applicable criteria specified in the FAR (those currently applicable are summarized parenthetically) are met. If Contractor’s subcontracts meet such criteria, Contractor shall include the terms or substance of the applicable clause in its subcontracts. If the provisions of this Section 10.3 conflict with the balance of the Agreement, this Section 10.3 shall prevail.

(A)52.203-6 Restrictions on Subcontractor Sales to the Government (required in all subcontracts under this Agreement which exceed $100,000);

(B)52.203-7 Anti-Kickback Procedures (required in all subcontracts under this Agreement which exceed $100,000, other than those for commercial items);

(C)52.204-2 Security Requirements (required in all subcontracts under this Agreement which involve access to classified information);

(D)52.219-8 Utilization of Small Business Concerns (required in all non-personal subcontracts with a value greater than $100,000);

(E)52.219-9 Small Business Subcontracting Plan (Contractors receiving subcontracts exceeding $500,000, other than small business concerns, are required to adopt a subcontracting plan that complies with the requirements of this clause);

(F)52.222-4 Contract Work Hours and Safety Standards Act—Overtime Compensation (required in all subcontracts exceeding $100,000, unless otherwise exempted);

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(G)52.222-26 Equal Opportunity (required in all contracts/subcontracts; however, if the cumulative value of nonexempt Federal contracts/subcontracts is $10,000 or less in any 12 month period, including the 12 months preceding the award, the contractor/subcontractor is exempt from the clause requirements);

(H)52.222-35 Affirmative Action for Disabled Veterans and Veterans of the Vietnam Era (required in all contracts/subcontracts with a value of $10,000 or more);

(I)52.222-36 Affirmative Action for Workers with Disabilities (required in all contracts/subcontracts with a value of $10,000 or more);

(J)52.222-37 Employment Reports on Disabled Veterans and Veterans of the Vietnam Era (required in all contracts/subcontracts with a value of $10,000 or more);

(K)52.223-14 Toxic Chemical Release Reporting (Except for acquisitions of commercial items, and unless otherwise exempt, this clause is required for competitive subcontracts expected to exceed $100,000, including all options, and in any resultant subcontract exceeding $100,000, including all options);

(L)52.225-13 Restrictions on Certain Foreign Purchases (required in all subcontracts for contracts with a value exceeding $2,500, unless otherwise exempted);

(M)52.222-11 Subcontracts (Labor Standards) (required in all service contracts in excess of $2,000 for construction within the United States) This provision requires that the following clauses be inserted into contracts meeting the criteria: Davis-Bacon Act, Contract Work Hours and Safety Standards Act—Overtime Compensation, Apprentices and Trainees, Payrolls and Basic Records, Compliance with Copeland Act Requirements, Withholding of Funds, Subcontracts (Labor Standards), Contract Termination—Debarment, Disputes Concerning Labor Standards, Compliance with Davis-Bacon and Related Act Regulations, and Certification of Eligibility.

(N)52.222-41 Service Contract Act of 1965, as Amended (required in all service contracts subject to the Act (i) which exceed $2,500; or (ii) which are for an indefinite dollar amount and the contracting officer does not know in advance that the contract amount will be $2,500 or less).

(O)Contractor shall comply with the Department of Commerce Export Administration Regulations (“EAR”) in 15 CFR Chapter VII, subchapter C, including 15 CFR Section 734.2 which prohibits the export or release of controlled technology and/or software to foreign nationals within the United States who are not lawfully admitted to the United States for permanent residence. Contractor shall confirm that these regulations either do not apply to Contractor’s activities under the terms of this Agreement or that Contractor has procedures to ensure compliance. If Contractor is directly or indirectly employing a foreign national not currently lawfully admitted to the United Sates for permanent residence to perform work under this Agreement, Contractor warrants to FirstEnergy that such employment does not violate the foregoing regulations.

(P)FOREIGN CORRUPT PRACTICES ACT PROVISIONS The following provisions shall apply to FirstEnergy and Contractor (unless it is a foreign concern) if it performs or obtains any of the work in a foreign country:

(1)All payments to Contractor shall be by check or bank transfer only. No payment shall be in cash or by bearer instrument, and no payment shall be made to any corporation or Person other than Contractor. All payments due hereunder shall be made to Contractor at its principal place of business in the United States, even if Contractor performs or obtains the work in a foreign country.

(2)Each of FirstEnergy and Contractor represents that it is familiar with the Foreign Corrupt Practices Act (the "FCPA") and its purposes; and that, in particular, it is familiar with the prohibition against paying or giving of anything of value, either directly or indirectly, by an American company to an official of a foreign government for the purpose of influencing an act or decision in his official capacity, or inducing him to use his influence with that government, to assist a company in obtaining or retaining business for or with, or directing business to, any Person.

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(3)Contractor shall not use any part of its compensation for any purpose, and shall take no action, that would constitute a violation of any law of the United States (including the FCPA) or of any jurisdiction where it performs services or manufactures or sells goods. Likewise, FirstEnergy shall take no action that would constitute a violation of any law of the United States (including the FCPA) or of any jurisdiction where it engages in business. FirstEnergy represents that it does not desire and will not request any work by Contractor that would or might constitute any such violation.

(4)FirstEnergy may terminate this Agreement for default at any time, without any liability or obligation, if it believes, in good faith, that Contractor has violated this Section 10.3(P). Any action by Contractor constituting a violation of the FCPA, or a request for such action from Contractor's representative, shall result in immediate termination of this Agreement for default. Should Contractor ever receive, directly or indirectly, from any FirstEnergy representative a request that Contractor believes will or might violate the FCPA, Contractor shall immediately notify FirstEnergy's general counsel.

(5)FirstEnergy may disclose the existence and terms of this Agreement, including the compensation provisions, at any time, for any reason and to whomever FirstEnergy's general counsel determines has a legitimate need to know the same in connection with obligations under the FCPA, including the United States government, the government of any country where the work is performed or obtained, and any regulatory agency with jurisdiction over FirstEnergy.

10.4Contractor shall comply with the Occupational Safety and Health Act of 1970 and all rules, regulations, standards, requirements and revisions thereof or adopted pursuant thereto.

10.5Unless this Agreement otherwise provides, Contractor shall, at its own expense, obtain from appropriate governmental authorities all Permits, inspections and licenses which are required for it to perform its work under the Project and shall comply with all rules and regulations of insurance companies which have insured any of the Project.

10.6If applicable, Contractor agrees to comply with all Hazard Communication Standards promulgated by the Occupational Safety and Health Administration (OSHA), 29 CFR 1910.1200, et seq., as amended, to insure that chemical hazards produced, imported, or used with the workplace are evaluated, and that hazard information is transmitted to affected employees of Contractor, of any subcontractor or of FirstEnergy.

ARTICLE 11 - INTELLECTUAL PROPERTY RIGHTS

11.1Ownership of Project and Data. All deliverables provided by Contractor (but not its Subcontractors) to FirstEnergy associated with the Project (including Drawings and Specifications, Data, manuals, reports, purchasing documents, Permits, calculations, and training materials), whether or not patentable, registrable as a copyrightable work, or registrable as a trademark or service mark, shall become the property of FirstEnergy and FirstEnergy shall own all intellectual property rights therein (including the rights to any patent, trademark or service mark, trade secret, and copyright therein). Contractor hereby agrees that any such engineering deliverables provided by Contractor to FirstEnergy during the term of this Agreement that pertain in any material respect to the Project shall be done as “work made for hire” as defined and used in the Copyright Act of 1976, 17 USC §1 et seq., and that FirstEnergy, as the entity for which the work is prepared, shall own all right, title and interest in and to such materials, including the entire copyright therein. To the extent that any such deliverables are not deemed to be a "work made for hire," Contractor will assign to FirstEnergy ownership of all right, title, and interest in and to such materials, including ownership of the entire copyright therein. Notwithstanding the foregoing, nothing herein shall be deemed to convey or grant any ownership of intellectual property rights (i) owned by Contractor prior to the Effective Date, or (ii) developed by Contractor outside of the scope of work on the Project; provided that FirstEnergy shall receive with respect to any such rights a nonexclusive, irrevocable, fully-paid-up and royalty-free, transferable license to use, copy, communicate, and prepare modifications to such rights for the purpose of completing, operating, maintaining, repairing, modifying, adding to, improving and demolishing the Project, the Subproject, and related systems.

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If any design and development work is to be performed by Subcontractors or FE Vendors, Contractor shall consult with FirstEnergy prior to and during the negotiation and award of such contracts with regard to the treatment of intellectual property rights to any inventions and works of authorship developed under such contracts, and shall seek to obtain from each such Subcontractor (and FE Vendors to the extent directed by FirstEnergy) rights similar to those described in the preceding paragraph.

FirstEnergy releases and agrees to hold Contractor harmless from and against any claim or liability arising from any unauthorized use of such work product by FirstEnergy or with respect to any work made for hire, the use of such work product by FirstEnergy for any purpose other than in connection with the Project being performed pursuant to this Agreement.

11.2Infringement. Contractor warrants that the goods or services provided by Contractor or its Subcontractors hereunder are and will be original (as required by law), do not and will not infringe on or misappropriate any United States or foreign patent, copyright, trademark, or other intellectual property rights of any third party, and to the extent such intellectual property is to be owned by FirstEnergy in accordance with and subject to Section 11.1, have not been and will not be previously assigned or licensed. If the goods or services provided by Contractor or its Subcontractors hereunder or any portion thereof is held to constitute an infringement or misappropriation of the intellectual property rights of a third party, then Section 16.3 shall apply.

11.3Data Furnished by FirstEnergy. All Data furnished by FirstEnergy in connection with the Project shall remain FirstEnergy's exclusive property. Contractor shall not use FirstEnergy-furnished Data for any purpose other than for the Project. Contractor shall return such FirstEnergy-furnished Data and all copies thereof to FirstEnergy upon completing the Project, or upon FirstEnergy’s request; provided that Contractor shall be entitled to retain an archival copy of such Data subject to confidentiality obligations.

ARTICLE 12 - INSURANCE AND BONDS

12.1Contractor’s Insurance. The Contractor agrees to secure and maintain in force policies of insurance of the types listed below and shall furnish to FirstEnergy, prior to starting work and throughout the duration of the Project, Certificates of Insurance evidencing current coverage listed below. These certificates shall be endorsed with substantially the following language:

"This policy will not be canceled or allowed to lapse, and no change shall be made in this policy which alters, restricts or reduces the insurance provided or changes the name of the insured without first giving at least thirty (30) days' notice in writing to FirstEnergy Corp., Risk Management Section, at its office in Akron, Ohio, with receipt of notice acknowledged."

(A)Comprehensive General Liability insurance including Contractual Liability and including coverage of third-party claims arising out of Contractor’s professional liability (Errors and Omissions), and if any work is to be performed by Subcontractor, Contractors Protective Liability with minimum limits of $[******] per occurrence, combined single limit, for bodily injury and property damage. Coverage shall be on an occurrence-based form.

(B)Comprehensive Automobile Liability insurance including non-ownership and hired car endorsement with minimum limits of $[******] per occurrence, combined single limit, for bodily injury and property damage. Coverage shall be on an occurrence-based form.

(C)Worker’s Compensation coverage in the statutory amounts under the worker’s compensation act(s) of the location(s) in which the Project is to be performed, for the current period.

(D)Employer's Liability with a minimum limit of $[******] per occurrence.

(E)Excess liability insurance with a limit of $[******] each occurrence. Coverage shall be on an occurrence-based form.

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12.2Additional Insured. FirstEnergy Corp. and its subsidiaries and affiliates shall be included as an additional insured to the extent of any liability deriving from the acts or omissions of Contractor, for the policies provided in Sections 12.1(A), (B), and (E), it being understood that said policies shall provide primary insurance to FirstEnergy Corp. and its subsidiaries and affiliates, with no special restrictions or reservations that are inconsistent with this Agreement. A signed copy of the endorsement adding FirstEnergy Corp. and its subsidiaries and its affiliates as an additional insured shall be attached to the certificate of insurance providing general liability coverage. It is expressly agreed and understood that the contractual obligations under this Article 12 are for insurance and not indemnity.

12.3Lapse of Coverage. In the event of cancellation or lapse of or prohibited change in any policy for which a certificate is required to be furnished under this Agreement, FirstEnergy shall have the right to suspend the work of the Contractor until the policy and certificate in evidence thereof are reinstated or arrangements acceptable to FirstEnergy are made pending issuance of new policies and certificates. If any such insurance shall be about to lapse or be canceled, the Contractor shall, at least thirty (30) days before coverage thereunder ceases, obtain a new policy with like coverage, and if Contractor fails to do so, FirstEnergy may obtain insurance protecting it from the hazards covered by such lapsed or cancelled policy, and the difference between all premiums and expenses of such insurance and premiums and expenses of the Contractor’s cancelled or lapsed policies shall be charged against the Contractor and shall be a legitimate deduction from any sum due it from FirstEnergy.

12.4Waiver of Subrogation. Contractor and any of its Subcontractors shall waive and hereby waives any rights of subrogation which they or any of their insurers may have against FirstEnergy, its affiliates, and each non-affiliated company disclosed in this Agreement, their respective agents or employees.

12.5Project Insurance. At the request of FirstEnergy, Contractor shall procure Construction All Risk property insurance with limits of $5,000,000 per loss event and deductibles not to exceed either one hundred thousand dollars ($100,000) or five hundred thousand dollars ($500,000) (which desired deductible level FirstEnergy will inform Contractor of during the Development Phase), with the following coverages:

(A)For each Subproject, for the period from Notice to Proceed until commencement of the Warranty Period  (1) “All Risks” of  physical loss or damage to the Subproject and (2) any physical loss or damage to existing property of FirstEnergy or its Affiliates arising from or in connection with the  work hereunder ;  and

(B)For each Subproject, during the Warranty Period,  extended maintenance covering loss or damage caused by any act or omission of Contractor or its Subcontractors while at the Site during the construction period and/or Contractor or its Subcontractors while at the Site for the purpose of doing any work in order to comply with the  warranty obligations under this Agreement.

Contractor shall separately invoice FirstEnergy for all policy premiums and FirstEnergy shall pay such invoice no later than the date of Contractor’s next subsequent payment due date provided under Section 5.1 above. 

Subject to the provisions of Section 18.4(A), payment of all deductibles arising under this policy shall be to FirstEnergy’s account.

12.6Payment and Performance Bonds. With respect to each AQC Unit, at the request of FirstEnergy, Contractor shall provide FirstEnergy with a Bond valued in the aggregate in an amount equal to [*****] thereon through the date of Final Completion (the “Available Amount”). The value of the Bond shall be reviewed and amended every three months such that the value of the Bond is updated to reflect the amount of [*****] as set out herein.

With respect to the Bond for Subproject(s) which will be performed as an FE Vendor Arrangement, upon achievement of Final Completion, the Available Amount under such Bond shall be reduced to an amount equally pro-rated between all AQC Units performed under an FE Vendor Arrangement as is required for Contractor to provide Bonds during the Warranty Period in a cumulative aggregate amount of no greater than $[******] in respect of all such AQC Units.

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With respect to the Bond for Subproject(s) which will be performed as a Wrap Arrangement, upon the achievement of Mechanical Completion, Contractor shall increase the Available Amount of such Bond by an amount equal to the difference between [******] through such date and the Contractor’s maximum liability for Performance Liquidated Damages for such Subproject. Upon commencement of the Warranty Period, the Available Amount of such Bond shall be reduced to an amount no greater than the amount of [******] through the date of Mechanical Completion. Upon achievement of Final Completion, the Available Amount under such Bond shall be reduced to an amount no greater than $[******]. With respect to each Subproject, the Bond shall expire at the end of the Warranty Period and FirstEnergy shall return such Bond to Contractor within [******] days of such expiration.

With respect to each Bond, FirstEnergy may draw upon such Bond with respect to any amount due from Contractor to FirstEnergy in satisfaction of any Contractor obligation under this Agreement that has not been paid within thirty (30) days of FirstEnergy’s demand therefore. The parties agree that drawdown under a Bond by FirstEnergy shall be permitted as follows:

(A)to the extent the amount requested is not in excess of the then Available Amount thereunder as determined in the Bond; and

(B)the Agreement has not been terminated by reason of mutual consent or by FirstEnergy’s default; and

(C)one of the following has occurred:

(1)a Contractor Event of Default in respect of the subject Subproject has occurred; or

(2)Contractor has not paid FirstEnergy any sums or damages in respect of the subject Subproject within the time stipulated, or, if none is provided, within a reasonable time, that it is obliged to pay pursuant to this Agreement in respect of such Subproject, including but not limited to any undisputed Schedule Liquidated Damages or Performance Liquidated Damages, and any amounts due pursuant to any indemnity, if applicable; and

(3)the amount being claimed in respect of any of the above circumstances does not exceed FirstEnergy’s good faith estimate of the amount that FirstEnergy is entitled to recover from Contractor under the Agreement.

In the event FirstEnergy draws down on any Bond and it is later determined that such drawdown or payment was in excess of FirstEnergy’s rights as provided above, FirstEnergy shall return such amount to Contractor upon such determination within five (5) Business Days, with interest at the rate set forth in Section 5.2(A)(2)(iv) from the date of drawn down until the date such amount is returned.

The premium for these Bonds shall be separately invoiced to FirstEnergy and FirstEnergy shall pay such invoice no later than the date of Contractor’s next subsequent payment due date provided under Section 5.1 above.  Contractor shall deliver the executed originals and two executed copies of each Bond to FirstEnergy prior to commencing any work. Commencement of the Project or any Subproject by Contractor without having provided the Bonds shall not be considered a waiver or release by FirstEnergy of the requirement for the Bonds.

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12.7Security for Vendor Termination Costs. During the Development Phase of any Subproject which will be performed as a Wrap Arrangement, Contractor will identify to FirstEnergy any contract with an OEM for such Subproject which will require payment to the vendor of cancellation or termination fees or similar costs (“Vendor Termination Costs”) in the event such contract is terminated by Contractor prior to completion of performance, and a description (including the dollar amount and the circumstances of payment) of the Vendor Termination Costs for such vendor contract. Provided that FirstEnergy has approved such vendor contract and the identified Vendor Termination Costs associated therewith prior to the Commencement Date for such Subproject, FirstEnergy will provide to Contractor a Bond, or similar form of security acceptable to Contractor as security for reimbursement of such Vendor Termination Costs, but only at such time(s) and in such amount(s) as Contractor would then be exposed to an obligation to pay such Vendor Termination Costs if the vendor agreement were terminated at that time. For purposes of clarity, Vendor Termination Costs shall not include any amount attributable to a failure of performance or payment by Contractor (other than at the direction of FirstEnergy or other than to the extent such is directly due to FirstEnergy’s failure to timely pay any amounts that are due and outstanding under this Agreement), any amount corresponding to a payment which has been paid by FirstEnergy to Contractor, or any amount not specifically approved by FirstEnergy as a Vendor Termination Cost prior to the Commencement Date of the Subproject (or after the Commencement Date pursuant to a Change Order in accordance with Article 8).

ARTICLE 13 - WARRANTY AND CORRECTION OF WORK

13.1Warranty. With respect to each Subproject, the warranties set forth in this Article 13 are referred to collectively as the “Warranty”. With respect to each Subproject (or AQC Unit, as applicable), the period ending two (2) years after the date that the requirements of Final Completion of such Subproject (or AQC Unit, as applicable) with respect to successful passage of the Performance Tests or liquidation thereof as provided in Section 6.3(A)(ii) and the Reliability Standard as provided in Section 6.3(A)(iv) have been achieved is referred to as the “Warranty Period” for that Subproject (or AQC Unit, as applicable), and Contractor’s obligations and liabilities under this Article 13 (irrespective of whether such claim arises from a patent or latent defect) shall cease upon the termination of the Warranty Period for such Subproject (or AQC Unit, as applicable).

(A)Warranty of Professional Services. Contractor hereby warrants that the Professional Services provided by Contractor shall be performed in accordance with Good Practices, the requirements of this Agreement, the Drawings and Specifications, Applicable Law, and Applicable Codes and Standards.

(B)Warranty of Services Other Than Professional Services. Contractor hereby warrants that all Craft Labor, and any services other than Professional Services provided by Contractor and its Subcontractors, shall be performed in accordance with Good Practices, the requirements of this Agreement, the Drawings and Specifications, Applicable Law, and Applicable Codes and Standards.

(C)Warranty of Materials. Contractor hereby warrants that the Materials, and each component thereof (other than Materials provided by an FE Vendor) shall be:

(1)new, complete, fit for the purpose specified in this Agreement and of suitable grade for the intended function and use;

(2)in accordance with Good Practices;

(3)in accordance with this Agreement, including FirstEnergy’s Requirements, the Drawings and Specifications, Applicable Law, and Applicable Codes and Standards;

(4)free of encumbrances to title; and

(5)free from defects in design, material and workmanship.

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(D)Subcontractor Warranties. Contractor shall obtain warranties from Subcontractors consistent with Sections 13.1(A),13.1(B), and 13.1(C), which shall be deemed to run to the benefit of FirstEnergy, its assignee(s), and Contractor. All warranties provided by any Subcontractor shall be in such form as to permit direct enforcement by Contractor or FirstEnergy (or its assignees) against any Subcontractor whose warranty is called for (but only in the event that Contractor has not performed, or no longer has any warranty obligations with respect to the subject matter of such directly enforced warranties). This Section 13.1(D) shall not in any way be construed to limit Contractor’s obligations under Sections 13.1(A),13.1(B), or 13.1(C) of this Agreement.

(E)Exceptions to Warranty. The Warranty excludes remedy for damage or failure to the extent Contractor can demonstrate that such damage or failure was caused by: (i) improper repairs, replacements or alterations of the Project by FirstEnergy; (ii) operation, maintenance or use of the Project in a manner not in material compliance with the operating parameters to be mutually determined by the Parties during the Development Phase or (iii) maintenance that may be required as a result of normal wear and tear.

13.2Correction of Work.

(A)Correction of Work Prior to Commencement of the Warranty Period. With respect to each Subproject (or AQC Unit, as applicable), prior to commencement of the Warranty Period, Contractor shall promptly correct or procure the correction of work rejected by FirstEnergy or that fails to comply with the requirements of the Agreement, whether or not fabricated, installed or completed. FirstEnergy shall be responsible for paying in accordance with Exhibit 5.1 all costs of correcting such work, including additional testing and inspections and compensation for consultants retained by FirstEnergy and expenses made necessary thereby. For purposes of clarity, commencement of the Warranty Period shall not preclude Contractor’s right to be paid in accordance with Exhibit 5.1 for any work performed thereafter to fulfill any of its then remaining obligations, other than with respect to performance of work required to satisfy its Warranty obligations.

(B)Correction of Work During the Warranty Period.

(1)If, during the Warranty Period, FirstEnergy discovers any nonconformance with the warranties set forth in Section 13.1 (“Warranty Non-Conformance”), FirstEnergy shall provide Contractor with written notice detailing such Warranty Non-Conformance as soon as practicable following such discovery but in no event later than the end of the Warranty Period. Such notice shall be in accordance with warranty procedures (as will be mutually agreed upon between FirstEnergy and Contractor during the Development Phase).

(2)In the event of any Warranty Non-Conformance with the warranty provided under Section 13.1(A), Contractor shall, at its sole expense, reperform such non-conforming Professional Services.

(3)In addition, but subject to the limitation of remedies set forth in Section 13.3, in the event of any Warranty Non-Conformance with the warranties provided under Section 13.1(A), Section 13.1(B) or Section 13.1(C), Contractor and/or its Subcontractors shall provide and perform (or reperform) any work (including any required assembly or disassembly of any affected work or other structure, installation, equipment, fixtures, or portion of the Site and or any required obligations under Section 3.9(B)), whether by repair, replacement or otherwise, as required to correct any such Warranty Non-Conformance (“Corrective Work”), at Contractor’s expense. If the alleged nonconformance is established to be due to FirstEnergy act or omission or ordinary wear and tear or as otherwise excluded from warranty coverage under Section 13.1(E), all reasonable Contractor costs will be the subject of a Change Order.

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(C)Response Period. During the Warranty Period, Contractor shall initiate Corrective Work within five (5) days after receiving notification from FirstEnergy of the existence of any Warranty Non-Conformance, or within such other period as the Parties may agree with due regard for the involvement of appropriate Subcontractors, and shall diligently and continuously use all reasonable efforts to complete same within thirty (30) days or such other period which such completion may reasonably require. Notwithstanding the foregoing, if a Warranty Non-Conformance causes a Generating Unit outage, or presents an imminent threat to the safety or health of any person or the risk of material damage to property, then Contractor shall initiate Corrective Work within the lesser of: (a) a reasonable period under the circumstances, or (b) twelve (12) hours; and shall diligently and continuously use all reasonable efforts to complete same within fifteen (15) days or such other period which such completion may reasonably require. The time periods specified in this Section 13.2(C) for initiation and completion of Corrective Work are referred to herein as the “Response Period.”

(D)FirstEnergy Right to Correct or Complete Work. Subject to the limitations of remedies provided in Section 13.3, during the Warranty Period, if Contractor fails or refuses to initiate Corrective Work or to diligently and continuously utilize all reasonable efforts to complete same within the Response Period, then FirstEnergy, after further notice to Contractor, may perform such Corrective Work with its own forces or those of another vendor, and (x) if there are outstanding amounts due to Contractor from FirstEnergy, charge Contractor a backcharge (at reasonable rates) against such outstanding amounts, or (y) in the event no such outstanding amounts exist, charge Contractor for all reasonable costs and expenses associated with the performance or reperformance of such Corrective Work.

13.3Limitation of Remedies. Contractor shall perform Corrective Work for any Warranty Non-Conformance with the warranties set forth in Sections 13.1(A),13.1(B), and 13.1(C) at Contractor’s sole expense; provided, however, that Contractor shall not be required to incur expense in excess of $[******] in the cumulative aggregate in connection with performing any Corrective Work under this Agreement (provided the foregoing limit shall exclude amounts expended by Contractor to reperform its Professional Services as provided in Section 13.2(B)(2)). Upon the attainment of the expenditure limit described in the prior sentence, Contractor shall have no further liability with respect to the warranties provided under Sections 13.1(B) or 13.1(C) and further shall have no additional obligation to thereafter perform any Corrective Work.

13.4THE WARRANTIES CONTAINED IN THIS AGREEMENT ARE EXCLUSIVE AND CONTRACTOR MAKES NO OTHER WARRANTIES OF ANY KIND WHATSOEVER, EXPRESS OR IMPLIED, STATUTORY OR OTHERWISE, INCLUDING ANY WARRANTIES OF MERCHANTABILITY OR FITNESS FOR PURPOSE, RELATING TO DESIGN OR OTHER SERVICES, OR TO EQUIPMENT OR MATERIALS TO BE SUPPLIED BY CONTRACTOR UNDER THIS AGREEMENT.

ARTICLE 14 PAYMENT OF ACCOUNTS; WAIVER OF LIEN RIGHTS

14.1Contractor shall promptly pay all claims for labor, material, services, and other expenses incurred by it and its Subcontractors in connection with the Project.

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14.2Waiver of Lien Rights. To the extent permitted by law, Contractor, for itself and anyone else acting or claiming through or under it, does hereby expressly waive and relinquish all right to file a mechanics' or materialmen's lien, or notice of intention to file any lien, and agrees that no mechanics', materialmen’s, or similar lien shall be filed or maintained against any property where the Project is to be performed, or any interest of FirstEnergy in such property, by or in the name of Contractor or any Subcontractor, materialman or laborer acting or claiming through or under Contractor for work performed or materials furnished in connection with this Agreement. Contractor further agrees that it will defend, indemnify and hold FirstEnergy harmless from and against any and all loss, cost, expense (including attorneys' fees and costs of defense), liability, claim or demand arising from any mechanics', materialmen's or similar lien of Contractor or any Subcontractor, sub-subcontractor, materialman, supplier or laborer acting or claiming through or under Contractor for work performed or materials furnished in connection with this Agreement. Notwithstanding the foregoing, Contractor shall not be required to so waive its rights or to cause Subcontractors to so waive their rights to file any mechanics' or materialmen's lien with respect to any Subproject for which FirstEnergy assigns its rights and obligations under this Agreement to another entity, , and in such event Contractor’s obligation to defend, indemnify and hold harmless FirstEnergy against any such liens shall apply only to the extent that Contractor has been timely paid all amounts due under the Agreement.

14.3No-Lien Agreement. Contractor shall execute a Waiver of Liens Agreement consistent with the foregoing provisions of this Article 14, and acceptable in form and substance to FirstEnergy, in recordable form, which FirstEnergy may file in the jurisdiction(s) in which the Project will be performed.

14.4Right to Withhold. FirstEnergy may require evidence reasonably satisfactory to it from Contractor that all work in progress, work done or delivered, or service performed, for which FirstEnergy has made a payment, are free and clear of mechanic's, materialmen’s, and other liens, attachments, claims, demands, charges or other similar encumbrances. If evidence of mechanic’s, materialmen’s, and other liens, attachments, claims, demands, charges or other similar encumbrances is discovered, FirstEnergy may withhold payments due Contractor in amount sufficient to cover any such potential claim. Prior to invoicing final payment, Contractor and its Subcontractors shall sign a release of liens in a form prepared by FirstEnergy and furnished to Contractor. As applicable pursuant to Section 14.2, Contractor shall, within thirty (30) days, cause to be discharged and terminate any mechanics’ or materialmen’s lien filed by any of its Subcontractors, sub-subcontractors, materialman, laborers or suppliers, or shall bond against the same at its own cost and expense with a bond satisfactory to FirstEnergy.

14.5Subcontracts. Every subcontract for any portion of the Project shall contain an undertaking by the Subcontractor similar in effect to this Article 14. It is intended by the Parties that Contractor's agreement to waive and relinquish lien rights as above provided shall be effective only in those jurisdictions which permit such agreement to be made. The fact that some jurisdictions in which work will be performed do not permit such waiver shall not affect the enforceability of this waiver in those jurisdictions that do permit such waivers. The above obligations of the Contractor and/or Subcontractors are supplementary to and not a substitute for rights of FirstEnergy, its subsidiaries and affiliates, under the provisions of the Mechanics Lien Laws of the jurisdiction in which the work is being performed.

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ARTICLE 15 - DEFAULT, TERMINATION AND SUSPENSION

15.1Default by Contractor.

(A)Termination by FirstEnergy for Default. With respect to each Subproject, if Contractor shall at any time (i) refuse or materially fail to provide sufficient properly skilled workers, adequate supervision or materials of the proper quality; (ii) fail in any material respect to prosecute such Subproject according to the Project Schedule; (iii) materially fail to comply with any provision of this Agreement; (iv) make a general assignment for the benefit of its creditors; or (v) become insolvent, have a receiver appointed, or make a general assignment for the benefit of its creditors, in which such case the cure provisions found below shall not apply, then, after FirstEnergy serving written notice to Contractor specifying the nature and origin of the alleged default, unless Contractor shall have taken adequate steps to cure such condition within forty-five (45) days of such notice, or if the default is impossible to correct within such forty-five (45) day period], then within a reasonable period of time not to exceed sixty (60) days from the date of such notice (or a longer period, if agreed by FirstEnergy in its sole discretion) provided Contractor has commenced corrective action within seven (7) days after receiving notice of such condition from FirstEnergy and has proceeded diligently to cure such condition thereafter, then FirstEnergy, at its option, without voiding the other provisions of this Agreement and without further notice to any Party, may (a) take such steps as are necessary to overcome the condition, (b) terminate for default Contractor’s performance of all or any part of the Subproject by written notice to Contractor, or (c) seek specific performance or interlocutory mandatory injunctive relief requiring performance of Contractor’s obligations, provided, only to the extent that such relief may be necessary to avoid irreparable harm to FirstEnergy.

(B)Additional Rights of FirstEnergy Upon Termination. In the event that FirstEnergy terminates this Agreement in whole or in part for default, then FirstEnergy may, at its sole option, (i) enter onto the Site and take possession, for the purpose of completing the Project, all of the equipment, Materials, tools, supplies, documents, and information of Contractor (subject to reasonable arrangement for costs associated therewith to the extent not already paid), (ii) take assignment of any or all of the Subcontracts, (iii) either itself or through others complete the Project by the most cost efficient means reasonably practicable, and/or (iv) recover from Contractor any direct damages suffered by FirstEnergy as a result of such default. Subject to FirstEnergy’s foregoing recovery rights, Contractor shall be paid according to the terms of this Agreement for all work performed and materials provided or committed prior to termination plus the amount of Fee and G&A accrued prior to the date of termination but shall not be entitled to recover any of its close out costs (except third party demobilization, cancellation and other termination costs if any). FirstEnergy’s rights under this Section 15.1(B) are in addition to any other rights provided for under this Agreement. FirstEnergy agrees to act reasonably and use its best efforts to mitigate any costs it might incur in connection with any termination for default.

(C)Erroneous Termination for Default. If any termination for default by FirstEnergy is found to be not in accordance with the provisions of this Agreement or is otherwise deemed to be unenforceable, then such termination for default shall be deemed to be a termination for convenience as provided in Section 15.2.

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15.2Termination for Convenience by FirstEnergy. FirstEnergy shall have the right to terminate for convenience Contractor’s performance of all or any part of the Project or any Subproject by providing Contractor with a written notice of termination. Upon receipt of notice of termination for convenience, Contractor shall (i) immediately discontinue the Project (or portion thereof) on the date and to the extent specified in such notice, (ii) except as agreed by FirstEnergy, place no further orders for Subcontracts, Materials, or services except as may be necessary for completion of such portion of the Project (or portion thereof) as is not discontinued, (iii) promptly make every reasonable effort to procure cancellation or assignment upon terms satisfactory to FirstEnergy of all Subcontracts and rental agreements to the extent they relate to the performance of the Project (or portion thereof) that is discontinued, (iv) cooperate with FirstEnergy for the efficient transition of the Project, and (v) thereafter execute only that portion of the Project as may be necessary to preserve and protect work already in progress and to protect Materials at the Site or in transit thereto, and to comply with all Applicable Laws and Governmental Authorities. FirstEnergy may, at its sole option, take assignment of any or all of the Subcontracts. Contractor shall be paid according to the terms of this Agreement for all work performed prior to demobilization and materials and equipment provided or committed prior to termination plus reasonable direct close-out costs (including reasonable demobilization, cancellation and other termination costs) plus the amount of [******] prior to demobilization.

15.3Suspension of Project. FirstEnergy may, for any reason, at any time and from time to time, by ten (10) days prior written notice to Contractor, suspend the carrying out of the Project or any part thereof, whereupon Contractor shall suspend the carrying out of the Project or any part thereof for such time or times and in such manner as FirstEnergy may require. During any such suspension, Contractor shall properly protect and secure the Project in such manner as FirstEnergy may reasonably require. Unless otherwise instructed by FirstEnergy, Contractor shall during any such suspension maintain its staff and labor on or near the Site and otherwise ready to proceed with the Project upon receipt of FirstEnergy’s further instructions. FirstEnergy and Contractor shall negotiate a Change Order as provided in Section 8.2, and Contractor shall be paid during such suspension period for the reasonable costs (including actual overhead and reasonable profit) of such suspension, including demobilization and remobilization costs, if required, along with appropriate supporting documentation to evidence such costs, and the Changed Criteria shall be equitably adjusted to reflect such suspension. In the event that FirstEnergy does not pay Contractor any undisputed amounts due under this Agreement within fifteen (15) days after Notice that such payment has become due, Contractor, may at its option, suspend the performance of the Project, and its obligations under this Agreement, until such payment is made and such suspension shall be treated as a suspension under this Section 15.3 If FirstEnergy does not make payment of any undisputed amounts due under this Agreement within thirty (30) days after Notice that such payment becomes due, then Contractor may terminate this Agreement. In the event Contractor so terminates this Agreement, such termination shall be treated as a termination pursuant to Section 15.2.

ARTICLE 16 - INDEMNITIES

16.1Contractor’s Indemnity. Contractor shall indemnify, defend, and hold harmless the FirstEnergy Indemnified Parties from and against any and all Losses which any of the FirstEnergy Indemnified Parties may suffer or incur to the extent arising out of: (A) personal injury or death of any person, damage to the property of a Third Party, or damage to the property of a FirstEnergy indemnified Party (subject to the limitation set forth in Section 18.4(A)), in each case to the extent resulting from the negligent acts or omissions of Contractor, its Affiliates, and/or their respective agents, employees, and subcontractors; or (B) fines and penalties imposed on the FirstEnergy Indemnified Parties to the extent resulting from Contractor’s failure to comply with Applicable Laws governing Contractor (except to the extent a portion of such fine or damage is attributable to the acts of any FirstEnergy Indemnified Parties), subject to Section 18.3.

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16.2FirstEnergy’s Indemnity. FirstEnergy shall indemnify, defend, and hold harmless the Contractor Indemnified Parties, from and against any and all Losses which any of the Contractor Indemnified Parties may suffer or incur to the extent arising out of: (A) personal injury or death of any person, or damage to the property of a third party, in each case to the extent resulting from the negligent acts or omissions of FirstEnergy, its Affiliates, and/or their respective agents, employees, and subcontractors (except Contractor and any subcontractor of Contractor); or (B) fines and penalties imposed on the Contractor Indemnified Parties to the extent resulting from FirstEnergy’s failure to comply with Applicable Law governing FirstEnergy (except to the extent a portion of such fine or change is attributable to acts of any Contractor Indemnified Parties).

16.3Patent and Copyright Indemnification. Contractor shall fully indemnify, save harmless and defend FirstEnergy Indemnified Parties from any and all Losses arising out of or resulting from or related to actual or asserted violation, infringement, or misappropriation of any domestic or foreign patent rights, copyrights or other intellectual property, proprietary or confidentiality rights with respect to materials and information designed or used by Contractor or any Subcontractor in performing the Project. In the event that any suit, claim, temporary restraining order or preliminary injunction is granted in connection with Section 16.3,Contractor shall make every reasonable effort, by giving a satisfactory bond or otherwise, to secure the suspension of the injunction or restraining order. If, in any such suit or claim, the materials and information designed or used by Contractor or any Subcontractor in performing the Project, or any part, combination or process thereof, is held to constitute an infringement and its use is permanently enjoined, Contractor shall promptly make every reasonable effort to secure for FirstEnergy a license, at no cost to FirstEnergy, authorizing continued use of the infringing work. If Contractor is unable to secure such a license within areasonable time, Contractor shall, at its own expense and without impairing performance requirements, either replace the affected work, in whole or part, with non-infringing components or parts or modify the same so that they become non-infringing. FirstEnergy shall indemnify Contractor Indemnified Parties in the same terms as this Section 16.3, mutatis mutandis, with respect to designs, equipment and processes required by FirstEnergy to be used and/or incorporated in connection with the Project.

16.4Lien Indemnification of Contractor. Contractor shall promptly indemnify and hold harmless each FirstEnergy indemnified Party and defend each of them from any and all liens and similar encumbrances (including claims of Subcontractors) filed in connection with any Subproject brought by or in the name of Contractor or any Subcontractor, materialman or laborer acting or claiming through or under Contractor or any Subcontractor for work performed or materials furnished in connection with this Agreement, including all expenses and reasonable attorneys’ fees incurred in discharging any of same. If Contractor should default in promptly discharging any lien or similar encumbrances upon the Project, the Site or any portion thereof, or any materials encompassed therein, Contractor shall, within thirty (30) days of FirstEnergy’s written notice to Contractor demanding the discharge of such lien or encumbrance, satisfy or discharge the same (provided that Contractor shall have the right to submit a bond reasonably satisfactory to FirstEnergy, in the amount required by law, if Contractor, despite its reasonable efforts, has been unable to obtain discharge thereof) at its own cost and expense. If Contractor either does not satisfy or discharge such lien or similar encumbrance within the required thirty (30) days (or, where permitted, fails to provide FirstEnergy with a bond in lieu thereof), then FirstEnergy may, in its sole discretion, remove and discharge same. If FirstEnergy elects to exercise its right to remove and discharge, then Contractor shall be liable to FirstEnergy for all Losses incurred by FirstEnergy in discharging or removing same.

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16.5Notice and Legal Defense.Promptly after receipt by an indemnified Party of any claim or notice of the commencement of any action, administrative or legal proceeding, or investigation as to which the indemnity provided for in Sections 16.1, 16.2, 16.3, or 16.4 applies, such Party shall notify the indemnifying Party in writing of such fact. The indemnifying Party shall, at its own cost and expense, assume on behalf of the indemnified Party and conduct with due diligence and in good faith the defense thereof with counsel selected by the indemnifying Party and reasonably satisfactory to the indemnified Party; provided that the indemnified Party shall have the right to be represented therein by advisory counsel of its own selection and at its own expense; and provided that if the defendants in any such action include both the indemnifying Party and the indemnified Party and the indemnified Party shall have reasonably concluded that there may be legal defenses available to it which are different from or additional to, or inconsistent with, those available to the indemnifying Party, the indemnified Party shall have the right to select up to one separate counsel to participate in the defense of such action on its own behalf at the indemnified Party’s expense. The indemnified Party shall provide reasonable support and assistance to the indemnifying Party in connection with the defense of any claim to which an indemnity provided for herein shall apply.

16.6Waiver of Immunities. Each of Contractor and FirstEnergy, for itself, its successors, assigns, and subcontractors, hereby expressly agrees to waive any provision of any workers’ compensation act or other similar law whereby such the indemnifying Party could preclude its joinder by an indemnified Party as an additional defendant, or avoid liability for damages, contribution, or indemnity in any action at law, or otherwise where the indemnifying Party’s or its subcontractor’s employee or employees, heirs, assigns, or anyone otherwise entitled to receive damages by reason of injury or death brings an action at law against any indemnified Party. An indemnifying Party 's obligation to an indemnified Party herein shall not be limited by any limitation on the amount or type of damages, benefits or compensation payable by or for the indemnifying Party under any worker's compensation acts, disability benefit acts, or other employee benefit acts on account of claims against the indemnified Party by an employee of the indemnifying Party or anyone employed directly or indirectly by the indemnifying Party or anyone for whose acts the indemnifying Party may be liable.

16.7Comparative Negligence; Enforceability. Each Party’s indemnity obligations shall apply regardless of whether the indemnified Party was concurrently negligent (whether actively or passively), it being agreed by the Parties that their respective liability or responsibility for Losses under this Article 16 shall be determined in accordance with principles of comparative negligence. In the event that any indemnity provisions in this Agreement are contrary to the law governing this Agreement, then the indemnity obligations applicable hereunder shall be applied to the maximum extent allowed by Applicable Law.

ARTICLE 17 - CONFIDENTIALITY

17.1The Parties acknowledge that in the course of this engagement they will have access to and/or be in possession of Confidential Information of the other. With respect to each disclosure of Confidential Information under this Agreement, “Disclosing Party” shall mean the Party who discloses Confidential Information to the other Party, and “Receiving Party” shall mean the Party who receives Confidential Information from the Disclosing Party. In this Agreement, “Confidential Information” means scientific and technical information, formulas, devices, concepts, inventions, designs, drawings, methods, techniques, marketing and commercial strategies, information concerning the Disclosing Party’s or any of its Affiliates’ customers or suppliers, processes, data concepts, and know-how, and unique combinations of separate items which individually may or may not be confidential, which information is not generally known to the public and either derives economic value, actual or potential, from not being generally known or has a character such that the Disclosing Party or any of its Affiliates has an interest in maintaining its secrecy. Confidential Information disclosed in writing shall be marked at the time of disclosure to indicate it is confidential, and/or if it is disclosed in any other manner, it shall be identified and described in writing within thirty (30) days following such disclosure, and be marked "Confidential Information" with its date of disclosure.

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17.2Each Party shall hold in confidence all Confidential Information of the other to which it may have access hereunder, and shall use such Confidential Information solely for the performance of its obligations under this Agreement. The Receiving Party shall take all reasonable and appropriate measures to safeguard the Confidential Information from theft, loss, and negligent disclosure to others, including any such measures as it takes with respect to its own Confidential Information of like kind. Access to Confidential Information shall be restricted to those of the Receiving Party's personnel with a need to know such information in connection with the performance of its obligations under this Agreement. The obligations set forth in this Article shall expire five (5) years after Final Completion of the last Subproject; provided, that such expiration shall not affect the rights of either Party under applicable state trade secrets law.

17.3The obligations of the Receiving Party under this Agreement shall not apply with respect to Confidential Information which the Receiving Party can establish by documentary evidence: (a) is or has become generally known to, or readily ascertainable by, the public without the fault or omission of the Receiving Party or its employees or agents; (b) was known to the Receiving Party prior to the first disclosure of such information by the Disclosing Party; (c) was received by the Receiving Party without restrictions as to its use from a third party who is lawfully in possession and not restricted as to the use thereof; or (d) was independently developed by the Receiving Party through persons who have not had, either directly or indirectly, access to or knowledge of similar information provided by the Disclosing Party.

17.4If the Receiving Party is requested or required (by oral questions, interrogatories, requests for information or documents, subpoena, Civil Investigative Demand or similar process) to disclose any Confidential Information supplied to Receiving Party in the course of its dealings with the Disclosing Party, Receiving Party shall provide the Disclosing Party with prompt notice of such request(s) so that the Disclosing Party may seek an appropriate protective order and/or waive Receiving Party's compliance with the provisions of this Agreement.

17.5If a Party breaches or threatens to breach any of the provisions of this Article 17, the Parties acknowledge that there may exist no adequate remedy at law, and hereby agree that the non-defaulting Party shall have the right to seek temporary and permanent injunctive relief to restrain such violation, without the necessity of posting a bond. The right to injunctive relief shall be cumulative and in addition to the right to seek and obtain other remedies, including monetary damages.

17.6Restrictions on Public Announcements. Contractor shall not refer to this Agreement or reference FirstEnergy, its subsidiaries and affiliates, or the Site, directly or indirectly, in its advertising or promotional materials or communications, without the prior written consent of FirstEnergy.

17.7Contractor shall incorporate the above provisions in all agreements with its Subcontractors, agents and assigns.

ARTICLE 18 - LIMITATION OF LIABILITY

18.1Consequential Damages. Neither of FirstEnergy or Contractor, nor any of their respective Affiliates, subcontractors, FE Vendors, employees, officers, directors, shareholders, agents, and representatives, shall be liable under this Agreement or under any cause of action related to the subject matter of this Agreement, whether arising out of contract, warranty, tort (including negligence), strict liability, products liability, professional liability, indemnity, contribution, or any other cause of action for loss of profit, use, revenues, financing, bonding capacity or business opportunity, damages or losses for principal office expenses including the compensation of personnel stationed there, cost of replacement power, loss of data, losses resulting from downtime of the Site, cost of or repayment of capital, claims of customers, or any indirect, incidental, special or consequential damages of any nature (including claims of such Party’s customers, subcontractors, vendors or suppliers to the extent seeking recovery of damages described in this paragraph).

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18.2Liquidated Damages Not Penalty. It is expressly agreed that Liquidated Damages payable under this Agreement do not constitute a penalty and that the Parties, having negotiated in good faith for such specific Liquidated Damages and having agreed that the amount of such Liquidated Damages is reasonable in light of the anticipated harm caused by the breach related thereto and the difficulties of proof of loss and inconvenience or nonfeasibility of obtaining any adequate remedy, are estopped from contesting the validity or enforceability of such Liquidated Damages. The Parties acknowledge that the availability of Liquidated Damages was an inducement to FirstEnergy’s agreement to waive consequential damages, and in the event any Liquidated Damages are held to be unenforceable, Contractor specifically agrees to mutually and in good faith negotiate an alternative financial settlement with FirstEnergy designed to compensate FirstEnergy in amounts similar to the amounts that FirstEnergy would have been entitled to receive had such Liquidated Damages not been held to be unenforceable.

18.3Liquidated Damages as Exclusive Remedy. Payment of any Liquidated Damages with respect to any Subproject shall be in addition to, and not in lieu of, Contractor’s other obligations under this Agreement and shall, except to the extent provided herein, in no way affect FirstEnergy’s right to terminate this Agreement under Article 15 or receive other Liquidated Damages or remedies contemplated in this Agreement for any other aspect of Contractor’s obligations hereunder. Notwithstanding the foregoing, but otherwise without limitation of FirstEnergy’s right to terminate under Section 15.1, Liquidated Damages shall be FirstEnergy’s sole and exclusive remedy, and the payment of such Liquidated Damages or satisfaction of the Schedule or Performance Guarantees in accordance with this Agreement shall be the sole and exclusive liability of Contractor, for:

(A)Delay as set forth in Section 6.5 (including any fines and penalties imposed on the FirstEnergy Indemnified Parties as a result of a failure of the Project to be completed within the time required under the NSR Consent Decree); and

(B)failure of the Project to achieve Performance Guarantees as set forth in Section 7.2 (including any fines and penalties imposed on the FirstEnergy Indemnified Parties as a result of a failure of the Project to meet the emission limits required under the NSR Consent Decree).

18.4Liability Cap Contractor's total liability to FirstEnergy Indemnified Parties arising out of or in connection with this Agreement shall be subject to the following limitations and conditions:

(A)Contractor’s cumulative liability to FirstEnergy and its Affiliates for physical loss or damage to any property of such parties (including any Materials) shall not exceed the sum of: (i) the proceeds of the insurance coverage provided in Section 12.5, and (ii) $[******] per loss/event caused in whole or in part by Contractor or its Subcontractors fault or negligence prior to the end of the Warranty Period. No FirstEnergy Indemnified Party may make a claim under this Agreement for Losses arising out of damage to such Person’s property to the extent that such claim exceeds the foregoing limitation.

(B)With respect to each Subproject, Contractor’s cumulative liability to FirstEnergy with respect to the following matters shall not in the aggregate exceed the [******] by Contractor on such Subproject and FirstEnergy may not claim an amount in excess thereof:

(1)any and all warranty obligations provided in Section 3.9(B) and Article 13;

(2)any and all Schedule Liquidated Damages owed by Contractor, as provided in Section 6.5;

(3)any and all Performance Liquidated Damages (where the Subproject is an FE Vendor Arrangement) owed by Contractor, as provided in Section 7.2; and

(4)any and all amounts owed by Contractor pursuant to Section 15.1(B)(iv).

(C)FirstEnergy may not claim an amount in excess of the amount set forth in Exhibit 7.2 with respect to Performance Liquidated Damages (where the Subproject is a Wrap Arrangement) owed by Contractor as provided in Section 7.2.

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(D)With respect to each Subproject, subject to the foregoing sublimits and releases, Contractor’s cumulative total liability to the FirstEnergy Indemnified Parties arising out of or in connection with this Agreement and the work to be performed under this Agreement shall in no event exceed a cumulative aggregate amount equivalent to [******]% of the Contract Price paid to Contractor with respect to such Subproject (and provided further, with respect to the Subproject to be performed under a Wrap Arrangement, that the foregoing limitation shall in no event exceed the lesser of [******]% of the Contract Price paid to Contractor or $[******]) and FirstEnergy and the FirstEnergy Indemnified Parties may not claim an amount in excess of the foregoing.

(E) Notwithstanding the foregoing, the limitations of liability set forth in this Section 18.4 shall not apply to Losses arising out of: (i) Third-Party property damage and personal injury claims and (ii) infringement or misappropriation of patents, trade secrets or other intellectual property rights.

18.5FirstEnergy's remedies specified in this Agreement are FirstEnergy's exclusive remedies for liabilities of Contractor arising under this Agreement. Contractor disclaims and FirstEnergy agrees to waive any standards of performance or warranties, including implied or statutory warranties, other than those expressed in this Agreement.

18.6FirstEnergy represents that it and its Affiliates possess all ownership rights as to the Project and the existing facilities at the Site. FirstEnergy’s successors, assigns, and any future recipient of any equity ownership or other property interest in the Project and any of the existing facilities shall be bound by the releases, limitations on liability, and other protections of Contractor set forth hereunder.

18.7 Except to the extent prohibited by law, the waivers and disclaimers of liability, releases from liability, limitations of liability, indemnities, and exclusive remedy provisions set forth in this Agreement shall apply even in the event of the fault, negligence (in whole or in part), strict liability, or other basis of liability of the Party to whose benefit such provisions operate and shall extend to the benefit of such Party’s Affiliates, Subcontractors and its and their shareholders, directors, officers, employees, and agents.

ARTICLE 19 - MISCELLANEOUS PROVISIONS

19.1Waiver. None of the terms or provisions of this Agreement shall be deemed waived except by a writing signed by the Party which is entitled to the benefits thereof. The failure of any Party to require performance of any provision hereof shall in no manner affect such Party's right at a later time to enforce the same. The waiver by a Party of any provision hereof shall not be deemed to be a continuing waiver of any such provision or a waiver of any other provision hereof.

19.2Parties in Interest. Nothing in this Agreement is intended to confer any rights or remedies under or by reason of this Agreement on any Persons other than the Parties hereto, nor is anything in this Agreement intended to relieve or discharge the obligations or liabilities of any third Person or give any third Person any right of subrogation or action over or against any Party hereto. This Agreement is binding upon and shall inure to the benefit of the Parties and their permitted successors and assigns.

19.3Assignment.

(A)This Agreement is not assignable by Contractor, directly or indirectly, in whole or in part, without the prior written consent of FirstEnergy.

(B)FirstEnergy shall have the right to assign its rights and obligations under this Agreement with respect to any or all Subprojects at any time to: (a) any Affiliate of FirstEnergy, (b) any Person succeeding to all or substantially all of the assets or business of FirstEnergy, or (c) any Person acquiring any property interest in or rights to develop and operate the Project Site, the Project, or any Subproject, by purchase, lease, or contractual arrangement, in any such case without the necessity of obtaining Contractor’s consent, provided FirstEnergy and/or such assignee has demonstrated the existence of reasonable financial and technical resources or other assurances to fulfill such assignee’s payment and other obligations hereunder. No assignment permitted hereunder shall release FirstEnergy from any of the limitations and releases from liability and other protections enjoyed by Contractor under this Agreement or from any obligations or liabilities of FirstEnergy arising or relating to events occurring prior to the date of such assignment.

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(C)Assignment to Financing Assignee; Assumption by Financing Assignee. With respect to any one or more Subproject(s) for which FirstEnergy pursues project financing, prior to the Commencement Date of such Subproject(s), FirstEnergy may assign its rights under this Agreement with respect to each such Subproject to a project company in connection with effecting such financing (such project company, hereinafter a “Financing Assignee”). Prior to such assignment, FirstEnergy shall on a timely basis keep Contractor informed as to the progress of any efforts to obtain such financing and shall similarly provide Contractor with copies of Financing Documents or portions thereof relevant to Contractor’s interest (and allow Contractor an opportunity to review and comment thereon). An assignment in connection with such a financing shall only be effective if prior to such assignment, the Financing Assignee shall have entered into either: (i) binding financing arrangements to provide sufficient funds for the construction of the assigned Subproject and fulfillment of its payment obligations to Contractor with respect to such Subproject which Financing Assignee is entitled to make the first drawdown; or (ii) if the Financing Assignee has obtained financing commitments of less than the total cost of the assigned Subproject and amounts necessary to fulfill its payment obligations to Contractor with respect to such Subproject, mutually acceptable agreements with Contractor concerning appropriate security for payment for the assigned Subproject and release of FirstEnergy’s obligations hereunder with respect to such Subproject (except as noted below). In addition, the Financing Assignee shall also be required to have arranged to provide any Bond required under Section 12.6. Upon Contractor being specifically notified in writing that FirstEnergy has so assigned any such Subproject and that such Financing Assignee has succeeded to FirstEnergy’s interests and assumed the obligations of FirstEnergy thereunder, Contractor shall accept the Financing Assignee in place of FirstEnergy for all purposes under or in connection with this Agreement in respect of such assigned Subproject for the remainder of its term, provided the foregoing conditions precedent to such assignment have been satisfied. In connection with such assignment, Contractor shall provide assignments and consents, acknowledgments, estoppel certificates, legal opinions and such other closing documents as are customary in such transactions and in form reasonably acceptable to Contractor. Except with respect to the assigned Subproject, no Financing Assignee shall otherwise be liable for payment, performance, or observation of any of the obligations or duties of FirstEnergy. No assignment permitted hereunder shall release FirstEnergy from any of the limitations and releases from liability and other protections enjoyed by Contractor under this Agreement. Once such assignment if effected, there shall be no modification to the Financing Documents that operates to reduce the funds available to pay amounts due to Contractor from the Financing Assignee or to increase Contractor’s obligation(s) under this Agreement without the prior consent of Contractor.

(D)Information for Financing Parties. Contractor shall provide such documents and other technical assistance in its possession, or which can reasonably be prepared, as FirstEnergy may reasonably request in connection with obtaining financing for the Project (or any Subproject(s)). During the performance of the work, Contractor shall make available to FirstEnergy, any Financing Assignee, and its financing parties (provided, such parties have executed non-disclosure agreements similar in substance to the provisions of Article 17 of the Agreement) information relating to the status of the work including information relating to the design, engineering, construction and testing of the Project and such other matters as FirstEnergy, the Financing Assignee, or its financing parties may reasonably request.

(E)Right to Inspect. The financing parties and their engineers and consultants shall have the right to participate in all inspections conducted by the Financing Assignee under the assigned Subproject(s) and to attend all Performance Tests of the assigned Subproject(s). FirstEnergy and/or the Financing Assignee shall cause all such persons to observe Contractor’s security and safety regulations at all applicable locations and to refrain from interfering with Contractor’s performance of the work.

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(F)Contractor’s Cooperation. Contractor agrees to cooperate with FirstEnergy in FirstEnergy’s negotiation and execution of the Financing Documents, including appropriate assignments of FirstEnergy’s rights under this Agreement to financing parties and reasonable consents or similar agreements related to this Agreement requested by financing parties. For purposes of this cooperation, any assignment, consent or similar agreement that would in any material respect increase Contractor's costs or risks under this Agreement without appropriate additional compensation to Contractor under this Agreement will not be considered to be reasonable or appropriate.

19.4Governing Law; Dispute Resolution. This Agreement shall be governed by and interpreted in accordance with the laws of the State of Ohio. The Parties expressly exclude the applicability of the United Nations Convention on Contracts for the International Sale of Goods, if the same would otherwise apply here. All claims, disputes and other matters in question between Contractor and FirstEnergy, arising out of or relating to this Agreement or the breach thereof, shall be settled, if possible, by negotiation and mutual agreement of the parties thereto. Each Party shall give notice promptly (or in the case of a disputed Change Order, within 15 Business Days after rejection of such Change Order) to the other of the claim, dispute or other matter in question arising out of or relating to this Agreement or that breach thereof (“Notice of Dispute”). Within ten (10) calendar days following such notice, the Parties’ project management oversight team or other senior representatives shall conduct good faith negotiations with the object of reaching mutual agreement. If the senior representatives of the Parties are unable to agree within twenty days after delivery of a Notice of Dispute, then any legal suit, action, or proceeding arising out of or relating to this Agreement, shall be instituted in any Ohio Federal court to the extent such federal court has jurisdiction over the dispute. Notwithstanding the foregoing, either Party may seek from a court any interim or provisional injunctive or other equitable relief that is necessary to protect the rights or property of that party, pending the commencement of discussions between the Parties’ senior representatives (or pending the conclusion of such discussions). The Parties recognize and agree that each are citizens of different States within the meaning of 28 U.S.C. 1332(a)(1) and as such a federal court in the State of Ohio would have jurisdiction over any dispute arising out of or relating to this Agreement, to the extent the amount in controversy exceeds the federal amount in controversy requirement pursuant to 28 U.S.C. 1332(a). The Parties agree that each will refrain from joining any other parties to any litigation for the sole purpose of destroying such federal jurisdiction. In the event federal jurisdiction is lacking for any dispute between the Parties, the Parties agree that venue for any such dispute shall be in any State court in the State of Ohio having jurisdiction over such dispute. To the extent permitted by law, each of Contractor and FirstEnergy agree not to demand a jury trial in any proceeding arising out of or related to this Agreement. Subject to satisfaction of the foregoing undertakings, each of Contractor and FirstEnergy waives any objection which it may have now or hereafter to the laying of the venue of any such suit, action or proceeding and hereby irrevocably submits to the jurisdiction of any such Ohio state or federal court in any such suit, action or proceeding. The Parties agree to discuss in good faith settlement of disputes through alternative dispute resolution (ADR) proceedings such as mediation or arbitration.

19.5Notices. Any notice, demand, request, or other communication or document to be provided under this Agreement to a Party to this Agreement (“Notice”) shall be in writing, and shall be given to the Party at its address or telecopy number set forth below, or to such other address or telecopy number as the Party may later specify for that purpose by notice to the other Party. Each Notice shall be deemed given and received: (i) if given by telecopy, when the telecopy is transmitted and confirmation of complete receipt is received by that transmitting Party during normal business hours or on the next business day if not confirmed during normal business hours; (ii) if hand delivered or given by overnight delivery service, the day on which the notice is actually delivered to the address listed herein (whether or not delivered to the Party); or (iii) if given by normal or certified U.S. mail, two (2) business days after it is posted with the U.S. Postal Service.

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If to FirstEnergy:	FirstEnergy Generation Corp. 76 South Main Street
	Akron, Ohio 44308 attn: Director of Air Quality Compliance
	Fax: to be Separately Provided in Writing
with a copy to:	FirstEnergy Corp. 76 South Main Street
	Akron, Ohio 44308 attn: General Counsel
	Fax: (330) 384-3875
If to the Company:	Bechtel Power Corporation 5275 Westview Drive
	Frederick, Maryland 21703-8306
	attn: Project Manager, FirstEnergy Sammis Retrofit Project
	Fax: to be Separately Provided in Writing
with copies to:	Bechtel Power Corporation 5272 Westview Drive
	Frederick, Maryland 21703-8306
	attn:  President, Fossil Power Fax: (301) 698-4776
	Bechtel Power Corporation 5275 Westview Drive
	Frederick, Maryland 21703-8306 Attn: Principal Counsel, Power
	Fax: (301) 696-8526

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19.6Interpretation of Agreement. For purposes of this Agreement:

(A)The section and other headings in this Agreement are inserted solely as a matter of convenience and for reference, and shall be given no effect in the construction or interpretation of this Agreement;

(B)Unless the context of this Agreement otherwise clearly requires, references in the plural form include the singular and vice versa;

(C)This Agreement has been freely negotiated by all Parties and in the event there is any controversy, dispute, or claim involving the meaning, interpretation, validity, or enforceability of this Agreement or any of its terms or conditions, there shall be no inference, presumption, or conclusion drawn against a Party by virtue of such Party having drafted this Agreement or any portion hereof;

(D)The words “hereof,”“herein,”“hereunder,” and words of similar import shall refer to this Agreement as a whole and not to any particular provision thereof;

(E)When used herein, the words “include” and “including” shall be construed as “include, without limitation” and “including, without limitation”;

(F)When used herein, the word “day” means a calendar day, “month” means a calendar month, and “year” means 365 days;

(G)Provisions including the word “agree,”“agreed,” or “agreement” require the agreement to be recorded in writing; and

(H)“Written” or “in writing” means hand-written, type-written, printed, or electronically made or transmitted, and resulting in a permanent record.

19.7Severability. Any provision hereof that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof or affecting the validity or enforceability of such provision in any other jurisdiction and the provision that is prohibited or unenforceable shall be reformed or modified to reflect the Parties' intent to the maximum extent permitted by applicable legal requirements.

19.8Survival. The terms, covenants, conditions and obligations provided in the following Sections and Articles shall survive the termination of this Agreement: Sections 3.7, 3.8, 3.9, and 3.11, and Articles 10, 11, 12, 13, 14, 15, 16, 17, 18, and 19, and any claims, demands, losses, liens, or causes of action arising out of the Project prior to the date of termination.

19.9Further Assurances. Contractor and FirstEnergy agree to provide such information, execute and deliver any such instruments and documents and to take such other actions as may be necessary or reasonably requested by the other Party that are not inconsistent with the provisions of this Agreement and that do not involve the assumption of obligations other than those provided for in this Agreement, in order to give full effect to this Agreement and to carry out the intent of this Agreement.

19.10Execution and Counterparts. This Agreement may be executed in multiple counterparts, which taken together shall constitute an original without the necessity of all parties signing the same page or the same documents, and may be executed by signatures to electronically or telephonically transmitted counterparts in lieu of original printed or photocopied documents. Signatures transmitted by facsimile shall be considered original signatures.

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FIRSTENERGY GENERATION CORP.
By:
	Title

BECHTEL POWER CORPORATION
By:	/s/
	Title

:

8/17/2005 4:18 PM

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ATTACHMENT A - WORK SCOPE

1.0 PLANT/UNIT DESCRIPTIONS

1.1   The 2,220 MW Sammis Plant is located in Stratton, OH and is made up of 7 generating units that draw cooling water from the Ohio River.

1.1.1   Units 1-4 are 180 MW single reheat, sub-critical drum units placed in service in the years 1959 though 1962 respectively. The Foster Wheeler P.C. boilers generate 1,250,000 lbs./hr. of 2450 psig, 1050°F main steam (1000°F reheat).

1.1.2   Unit 5 is a 300 MW sub-critical, once-through unit placed in service in 1967. The Babcock and Wilcox coal fired, single reheat boiler generates 2,355,000 lbs./hr. of 2625 psig, 1005°F main steam (1005°F reheat).

1.1.3   Units 6 and 7 are 600 MW super-critical, once-through units placed in service in 1969 and 1971 respectively. The Babcock and Wilcox coal fired, single reheat boilers generate 4,628,000 lbs./hr. of 3785 psig, 1005°F main steam and 3,900,000 lbs/hr. of 654 psig, 1005°F reheat steam.

2.0 PROJECT (SUBPROJECT) DESCRIPTION

2.1   The Project will be made up of two Subprojects.

2.2   In Subproject 1, each of the Sammis units 1 through 4 will be retrofit with dry scrubber technology that would provide a 60% SO₂ reduction.

2.2.1   An initial review of the site seems to indicate the best approach may be to install the first system on Unit 4 and continue building north finishing with Unit 1.

2.2.2   Due to operational and performance concerns with the dry technology, FirstEnergy would like to operate the first system for approximately 6 to 9 months prior to beginning construction on the second unit, thereby providing an opportunity to make changes based on the operating experience gained during that period.

2.2.3   Present outage plans for the Sammis Plant call for Unit 4 to be off line in early 2007 with the other units following over the subsequent two years.

2.2.4   The reagent handling facilities for the Units 1-4 dry scrubbing technology will be common. However, those facilities do not necessarily have to be ready for use at the time the initial dry system is placed in service on Unit 4. Since the initial purpose of the Unit 4 system will be to provide some operational experience with dry scrubbing at the Sammis Plant, it may be decided to operate the dry system for short test periods using stored reagent brought in by truck

2.3   In Subproject 2, each of the Sammis units 5 through 7 will be retrofit with wet scrubber technology.

2.3.1   The projected schedule requires the AE-Constructor to support the development of the project design basis, work scope, and detailed cost estimate during 2005. The intent is to be prepared to bid FGD OEM services, if required, by the fourth quarter of 2005. Final Target Construction Cost estimates will follow pending availability of OEM information. Specific targets for finalizing cost and schedule commitments for each subproject will be established during the development period.

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ATTACHMENT A - WORK SCOPE

2.4   (Intentionally Omitted)

2.5   AE-Constructor Work Scope

2.5.1   During the Development Phase, the Parties will work to develop a detailed Project work scope that will include, but not necessarily be limited to, the following:

·Project Management

·Prepare Project Execution Plan document

·Support technology application decisions

·Support FGD OEM selection

·Establish Project performance parameters

·Complete site evaluations and layouts

·Constructability reviews

·Complete Project design basis

·Prepare estimating documents

·Prepare cost estimate

·Support permitting process

·Support reagent supply discussions

·Detailed engineering

·Procurement

·Construction

·Checkout, Startup & Commissioning

·Training

·Documentation

·Performance testing

·Security

3.0 EXECUTION OF THE WORKSCOPE

The selected AE-Constructor will be expected to execute the Project (engineering, design, fabrication, procurement, construction, startup and commissioning) in an open, collaborative and safe manner resulting in the most competitive overall cost (construction and future O&M) and optimal performance of the air quality control systems. This objective will be accomplished by meeting the following goals:

· Mutually developing Project designs to minimize construction costs and future O&M costs while ensuring the highest overall operational reliability.

· Each stakeholder being responsive to the needs of the other parties to insure actions and decisions are made in a manner consistent with all Project goals.

· The selected AE-Constructor will be expected to develop, evaluate and report Project information as close to real time as practical, insuring actions necessary to address safety, design, cost and scheduling issues are implemented promptly upon recognition.

3.1   Project Management

3.1.1   The AE-Constructor will be responsible for all Project Management related to the Project including management of all Subcontractors and the OEM’s.

3.2   Prepare Project Execution Plan

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ATTACHMENT A - WORK SCOPE

3.2.1   The AE-Constructor will work with the FirstEnergy Project team to develop an overall Project Execution Plan. The plan will establish a Project Team and organization chart as well as project controls including:

3.2.1.1   Owner releases - FirstEnergy will be integrally involved in all areas and Phases of the Project and therefore will require a review process be established that gives adequate time for that review without unduly affecting the Project schedule.

3.2.1.2   Status reporting requirements - FirstEnergy will require access to Project progress information including schedule, budget, significant issues and work completed on a continuous basis through a web based electronic platform. FirstEnergy's requires the Contractor establish a system that allows as close to real time updates as possible.

3.2.1.3   Invoicing - Invoicing and payment will be by electronic means (including submittal of timesheets).

3.2.1.4   Payment procedures - payment will be made based on FirstEnergy verification of AE-Constructor expenses and supporting documentation.

3.2.1.5   Changes to scope - FirstEnergy will require access to estimates, including schedule impacts, and scope change descriptions as part of an approval process for changes to scope for both the AE-Constructor & it's Subcontractors as well as the OEM.

3.2.1.6   Design review - FirstEnergy will perform a detailed, ongoing design review during all Phases of the Project. The AE-Constructor should be prepared to support FirstEnergy technical and support staff in the AE-Constructor's offices during the design portion of each Subproject. Such review will include Subcontractor design efforts, where applicable.

3.2.1.7   Design practices - the AE-Constructor will be required to submit the Engineering Procedures Manual and Project specific criteria documents for FE review. In addition, Contractor shall provide, as requested by FirstEnergy, access to their design practices on Contractor’s premises. Final drawings must be provided per the requirements listed in this specification.

3.2.1.8   Communications - FirstEnergy prefers the implementation of a centralized, web based document control system. The system will provide real-time access to the Project Team (AE-Constructor, OEM and FirstEnergy) to key Project documents.

3.2.1.9   Document control - FirstEnergy utilizes FileNet P8 3.0 as a document storage system. The AE-Constructor will be required to maintain a complete set of all permits, design documents, O&M manuals, drawings, bid documents, correspondence and reports as part of the official Project file. Once the Project is complete, the documents are to be provided to FirstEnergy in native format if electronic. If they are non-CAD drawings they shall be provided as .tif images and if they are scanned documents, they shall be provided as .pdf documents format.

3.2.1.10   Procurement and Subcontracting procedures - FirstEnergy will require a competitive process which may include electronic reverse auctions, for selecting Subcontractors, equipment suppliers, tools, rentals and service suppliers to obtain the lowest life cycle cost for the Project. The procedure must include FirstEnergy review and release steps. The Procurement and Subcontracting procedures should allow for exceptions when bidders are limited.

3.2.1.11   Safety programs - The AE-Constructor is expected to utilize "world class" site/Project specific safety programs, practices and procedures and enforce them across the site. While zero (0) safety incidents is the goal for this Project, the Safety Program should result in an OSHA recordable IR rate <[*****] for non-manual and field labor. The program should address site housekeeping as a method of improving safety. FirstEnergy will review and release the AE-Constructor's safety program which must be consistent with Exhibit 3.5 (E)-1 , Contractor Safety Guide, Air Quality Compliance.

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ATTACHMENT A - WORK SCOPE

In addition, the AE-Constructor must administer and enforce a Drug and Alcohol Testing Program consistent with the attached FirstEnergy generation Corp. Substance Abuse Testing Program (See Exhibit 3.4 (D)) and meet the requirements of Exhibits 3.8 (E)-1, 3.8 (E)-2, 3.8 (E)-3 & 3.5 (E)-2 dealing with Asbestos, Inorganic Arsenic, Lead and OSHA Compliance.

3.2.1.12   Quality assurance - FirstEnergy expects the Project to be completed with a high degree of quality. The AE-Constructor will have FirstEnergy reviewed and approved quality assurance programs in place for both field and shop work. In addition, the AE-Constructor will be expected to monitor and track the quality of major equipment as it is fabricated in the various Vendors' shops. FirstEnergy is to be notified of all significant inspections and may participate, as FirstEnergy deems necessary. In any case, all quality program reports will be provided to FirstEnergy.

3.2.1.13   Scheduling - Scheduling is to be done in an electronic format (Primavera) and is to be made available to FirstEnergy electronically in native format. FirstEnergy requires all schedules, including those provided by Subcontractors, be in Primavera. In any case, the Primavera integrated master schedule shall be kept by the AE-Constructor and will include all activities required to complete the Project regardless of the responsible party (AE-Constructor, FirstEnergy, OEM, Subcontractor, equipment supplier, etc.) or the form in which the individual schedules are provided.

3.2.1.14   Estimating - All estimates will be completed using accepted estimating practices common to the industry. The basis for all labor rates, equipment prices, indices, adjustments, contingencies, labor-hour quantities, ratios etc. will be provided and stated clearly in the estimate. FirstEnergy will be provided access to the method of calculation and the Project specific data used in the creation of any such estimates. FirstEnergy will review and release all estimates.

3.3   Support technology application decisions

3.3.1   The AE-Constructor will support FirstEnergy in it's effort to establish and evaluate the capital cost, operating cost, performance, risks and total life cycle costs associated with each subproject to make a determination which of the technologies to pursue.

3.4   Support FGD OEM selection

3.4.1   FirstEnergy has not selected any FGD technology suppliers. The AE-Constructor will support the solicitation of proposals from various technology providers. The AE-Constructor will write a specification for the various technology suppliers to bid to, review the proposals, interface with the various bidders to ensure they are properly interpreting the bid documents, prepare a bid tabulation and generally support FirstEnergy's selection process.

3.5   Assist in establishing Project performance parameters not already established within this Agreement.

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ATTACHMENT A - WORK SCOPE

3.5.1   The AE-Constructor will be required to provide support to FirstEnergy in establishing the performance requirements, performance guarantees and warranties associated with the technology provider.

3.6   Complete site evaluations and layouts

3.6.1   The AE-Constructor will be required to review the Sammis site for interferences, construction issues and existing undergrounds. From that review, the AE-Constructor will work with FirstEnergy to develop layout options, taking into account the potential configurations and the timing for their application. The various options will then be evaluated jointly by the AE-Constructor and FirstEnergy.

3.7   Complete Project design basis

3.7.1   The AE-Constructor will work with the FirstEnergy Project team and Sammis Plant operations personnel to develop a Project design basis.

3.7.2   The AE-Constructor will perform optimization studies, as directed by FirstEnergy.

3.8   Prepare estimating documents

3.8.1   The estimating documents will include site layouts, design basis documents, mass & energy balances, process flow diagrams, piping and instrumentation diagrams, Vendor quotes for major equipment, material estimates, detailed local labor surveys and Subcontractor estimates.

3.8.2   The level and detail of estimating documents that will be prepared in advance will be based upon FirstEnergy’s desired estimate accuracy for a given Subproject and may be different for the two Subprojects within the Project.

3.9   Prepare cost estimate

3.9.1   The Project estimate will be a collaborative effort between FirstEnergy, the AE-Constructor and the OEM and will be prepared in an "open book" manner. All of the estimating documents will be available to each of the parties for review and for their use in preparing their own portion of the estimate as well as to come to their own conclusions as to the accuracy of the overall estimate.

3.9.2   FirstEnergy reserves the right to retain the services of a mutually acceptable third party to review the estimates. All of the materials provided to FirstEnergy will be provided to the third party.

3.9.3   It is FirstEnergy’s expectation that there will be “continuous improvement” in the design/engineering and construction of the series of AQC Systems to be installed. This “continuous improvement” should be reflected in all aspects of the Subprojects including pricing, schedule, final quality and safety.

3.9.4   The Target Construction Cost for an individual Subproject will be based on the Subproject estimate for that Subproject.

3.10   Support Permitting Process

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ATTACHMENT A - WORK SCOPE

3.10.1   The AE-Constructor will establish a Permit list. This list will include all permits required to construct and operate the proposed facilities, the responsible party, permitting duration, applicable permitting agency as well as what activities are dependent on the permit.

3.10.2   The AE-Constructor is to include all the necessary permitting activities in the project schedule.

3.10.3   The AE-Constructor will be responsible for obtaining all of the construction permits.

3.10.4   The AE-Constructor will work with FirstEnergy to develop an environmental permitting strategy and will be responsible for managing the environmental permitting process, the creation and submission of all permit applications and providing responses to information requests from the agencies as required. The permits will be obtained in the name of FirstEnergy and FirstEnergy will be the official interface for the project with the permitting agencies.

3.11   Support reagent supply discussions

3.11.1   The AE-Constructor will be required to provide input and be present at times for reagent supply discussions that pertain to the quality, quantity, form and delivery of reagent.

3.11.2   The AE-Constructor will provide input on the effect of various reagents on the process performance and its cost effectiveness as well as its impact on design and operating parameters.

3.12   Detailed engineering

3.12.1   The AE-Constructor will prepare working drawings and specifications setting forth in detail the requirements for the construction of the Project. The design and engineering documents shall include all drawings, specifications schedules, diagrams and plans and such content and detail as is necessary to obtain required permits and governmental approvals and to properly complete the construction of the Project. The working drawings and specifications shall include information customarily necessary for the use of such documents by those in the building trades. Design drawings in the following categories are typically provided for Owner review:

· Site Grading/Roadway Drawings

· Logic Diagrams, Instrument Control Diagrams, Panel Layout Drawings

· Single Line Diagrams, Control SchematicDiagrams

· Piping and Instrument Diagrams, System Descriptions, Piping Class Sheets

· General Arrangement Drawings

· Major Equipment Specifications, Design Criteria Documents

A specific list of the design and engineering documents to be reviewed and released by FirstEnergy will be created during the Project Development Phase.

3.12.2   The Design and engineering documents must meet the requirements of applicable laws including Professional Certifications (e.g. Engineer stamps, etc.) as required.

3.13   Procurement

3.13.1   FirstEnergy reserves the right to purchase equipment and materials for the Project directly.

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ATTACHMENT A - WORK SCOPE

3.13.2   The AE-Constructor will be responsible for issuing purchase orders for all equipment and material in the AE-Constructor's scope of procurement. The AE-Constructor will be responsible for material control and handling of all equipment and materials purchased including any directly purchased by FirstEnergy. FirstEnergy will have direct input on the review and final selection of Vendors and equipment suppliers and on the type and quality of the equipment to be purchased for this Project.

3.13.3   FirstEnergy and the AE-Constructor will mutually agree upon the best method of contracting for labor services. Subject to section 2.3(A) of the Agreement, FirstEnergy will approve all Subcontractors and will be involved in the final bid evaluations. The AE-Constructor will develop the bidders list with FirstEnergy's approval, solicit bids, and present final bid evaluations to FirstEnergy for final review. FirstEnergy and the AE-Constructor will mutually agree to the final selection of the bidders.

3.13.4   FirstEnergy, with the AE-Constructor, will mutually determine the "best fit" technology and OEM, where applicable, for each of the two Subprojects.

3.14 Construction

3.14.1 FirstEnergy will provide oversight of the construction work performed at the applicable site.

3.14.2 FirstEnergy site construction personnel will have the option to attend AE-Constructor site meetings, that must be held daily, relating to Project planning and/or progress.

3.14.3 AE-Constructor will hold weekly status update meetings with FirstEnergy site construction personnel to review Project safety statistics, schedule, cost, productivity, and any other relevant Project topics. AE-Constructor to provide Gantt charts, cost and productivity reports, “S” curves, etc. as needed to clearly communicate current Project status and trends.

3.14.4 AE-Constructor will be required to utilize the National Maintenance Agreement. Discussions on specific Labor Requirements for this work are in progress. FirstEnergy's current standard Labor Requirements are listed in Exhibit 3.4 (E), Labor Requirements.

3.14.5 The AE-Constructor will be required to supply all temporary facilities, construction tools and equipment for each of the two Subprojects.

3.14.6 The AE-Constructor will be responsible for all demolition required for this Project. The AE-Constructor will identify the facilities to be demolished, engineer the demolition, schedule the demolition taking into account operating plant requirements and develop any safety procedures that may be required.

3.15 Checkout, Start-Up, Commissioning

3.15.1 AE-Constructor shall have responsibility for checkout, start-up, and commissioning of all systems within their work scope. Site specific procedures shall be developed by the AE-Constructor and submitted to FirstEnergy for review and approval.

3.15.2 FirstEnergy shall assign a Start-up Coordinator to interface with AE-Constructor and FirstEnergy plant personnel relating to the start-up process. At FirstEnergy’s option, FirstEnergy personnel may be integrated into the Start-up and Commissioning Team (participation to be under the management of and in support of AE-Constructor personnel).

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ATTACHMENT A - WORK SCOPE

3.16   Training

3.16.1   The AE-Constructor will be required to provide training for FirstEnergy operations and maintenance personnel for all portions of the new AQC Systems. The training program will be developed in conjunction with FirstEnergy operations and maintenance personnel in accordance with FirstEnergy standard practices and will include training material development, classroom training development and execution along with hands on training in the field.

3.16.1.1   Training programs and materials for plant non-operational support personnel will also be required.

3.16.1.2   The AE-Constructor will be responsible for working with FirstEnergy operations personnel to create Operating Procedures for each of the two Subprojects. The AE-Constructor will take the lead in the development of the Operating Procedures.

3.17   Documentation

3.17.1   All Project related documentation including; reports, correspondence, drawings, specifications, purchasing documents, O&M manuals, calculations, permits, etc. will be controlled by the AE-Constructor throughout the Project. At Project completion, all documentation controlled by the AE-Constructor will be provided to FirstEnergy in electronic format as follows:

3.17.1.1   All documents are to be provided in native format. In the case of drawings, native format is .dwg. Scanned non-drawing documents are to be provided in .pdf while scanned drawings (for which the .dwg format is unavailable) shall be provided in .tif format.

3.17.1.2   Two separate formatted excel spreadsheets will be provided by FirstEnergy that the AE-Constructor will use to create an index of all drawings (.dwg and .tif) and a separate index of all other documents. Those indexes will allow FirstEnergy to electronically populate its internal document management system.

3.17.1.3   FirstEnergy drawings that interface with the existing facilities will be provided to the AE-Constructor when required. The AE-Constructor will modify non-CAD drawings (provided as .tif files by FirstEnergy) with Autodesk CAD Overlay software to create hybrid revisions.

3.17.1.4   The AE-Constructor will be responsible for providing final "as-built" drawings for the Project including assuring that all drawings provided by subcontractors, in the field or shop, and all equipment drawings are as-built. The specific as-built drawing requirements will be established during the Project Development Phase.

3.18   Performance testing

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ATTACHMENT A - WORK SCOPE

3.18.1   The AE-Constructor will be responsible for coordinating all AQC system performance test scheduling, procedure development and testing including tests to be provided by the OEM.

3.18.1.1   Performance testing, although coordinated by the AE-Constructor will be performed by an independent, third party as selected by FirstEnergy.

3.18.1.2   FirstEnergy will review all test procedures, witness all tests and review and release all test reports.

4.0 SCHEDULE

4.1   The AE-Constructor will support overall Project scheduling including the scheduling of various technology and design/construction options for each of the two Subprojects as required to determine the optimum Project schedule.

5.0 GENERAL REQUIREMENTS

5.1   Professional Standards & Sufficient Personnel

5.1.1   The AE-Constructor will be responsible to provide adequate and qualified resources in all disciplines required to define the tasks, gather all facts relating to the tasks and coordinate all permitting, engineering, procurement, construction, commissioning, startup and testing of each of the two Subprojects.

5.1.2   The AE-Constructor shall, at all times, keep sufficient personnel employed and dedicated to the Project so that the services to be performed by the AE-Constructor herein are completed on schedule and in an efficient, safe, economical and professional manner.

5.1.3   The AE-Constructor will provide adequate opportunity for FirstEnergy to examine all studies, reports, sketches, drawings, specifications, proposals and other documents presented by the AE-Constructor and submit written responses, as required within a reasonable time so as not to delay the services of the AE-Constructor.

5.1.4   The AE-Constructor will keep FirstEnergy's Project Team apprised of all work efforts, including third party meetings, status meetings, hiring of Subcontractors, etc.

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LIST OF EXHIBITS

Exhibit No.

3.4 (A)                                          Key Project Personnel

3.4 (D)                         FirstEnergy Generation Corp. Substance Abuse Testing Program

                 FirstEnergy Generation Corp. Employee Sign-Up & Substance Abuse Screening Process

3.4 (E)                                          Labor Requirements

3.5 (E)-1                       FirstEnergy Contractor Safety Program for Fossil Generation

3.5 (E)-2                                         OSHA Compliance and Safety

3.8 (E)-1                                         Asbestos Handling and Removal

3.8 (E)-2                                         Inorganic Arsenic

3.8 (E)-3                                         Lead Abatement Terms of Reimbursement

5.1                                                 AQC Systems, Pricing Methodology and Definitions

5.1 -1(A)Fee Adjustment

5.1 -1(B)    Payment Methodology Example

5.1 -2                                             Sample Scorecards

5.1 -3                                             Fee Table

5.1 -4                                             Sample Invoices

5.1 -5                                             U.S. National Temporary/Short Term Assignment Conditions to a Project Location

                                                     U.S. National Long Term Assignment Conditions to a Project Location

5.1 -6                                             Constituents of G & A (Overhead) Costs

5.1 -7                                             Constituents of Engineering Technology Charge

5.1 -8                                             Tool and Equipment Rates

5.1 -9                                             Job Supplies

5.1-10                                            2005 Rate Sheet for Engineering/Graphics Labor & Other Professional Labor (US Offices)

5.1-11                                            2005 Rate Sheet for Professional Construction Labor (US Offices)

5.1-12                                            AQC Systems Cost Reimbursable Work, Craft Labor

5.2 (C)                                           Contractor’s Interim Waiver and Release of Liens and Claims Upon Progress

                                                     Payment

                                                     Subcontractor’s Interim Waiver and Release of Liens and Claims Upon Progress

                                                     Payment

6.3 (A)                                           Contractor’s Final Lien Waiver

                                                     Subcontractor’s Final Lien Waiver

6.3 (C)                                           Final Completion Certificate

6.5                                                Schedule Liquidated Damages

7.2                                                Reliability Standard, Performance Guarantees and Performance Liquidated Damages

7.2 -1                                            Design Fuel

8.2                                                W.A. Sammis Plant AQC Projects Contracted Services Change Order and Pricing Sheet

CONFIDENTIAL TREATMENT REQUESTED

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EXHIBIT 3.4(A)

 KEY PROJECT PERSONNEL

Program Manager	******
Project Manager	******
Project Engineering Manager	******
Site Manager	******
Field Superintendent	******
Project Engineer	******
Mechanical EGS	******
Control System EGS	******
Electrical EGS	******
Civil EGS	******
Plant Design EGS	******
Project Controls Supervisor	******
Startup Manager
Project Field Engineer
Specialists - available as needed:
FGD Technology Specialists	******
FGD Technology Specialist	******
FGD Technology Specialist	******

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 CONFIDENTIAL TREATMENT REQUESTED

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EXHIBIT 3.4(D)

FIRSTENERGY GENERATION CORP.

SUBSTANCE ABUSE TESTING PROGRAM

In order to provide a drug and alcohol free workplace, FIRSTENERGY GENERATION CORP. (FirstEnergy) on behalf of its subsidiaries and affiliates, will require any Contractor or subcontractor working on FirstEnergy's property to have a substance abuse testing program in place.

MINIMAL REQUIREMENTS OF CONTRACTORS PROGRAM

The substance abuse testing program shall be the obligation and responsibility of the Contractor. The Contractor is expected to establish, administer and enforce its own program. The Contractor’s program for those locations listed under Article 16.b. herein shall conform with the requirements of the Northwest Ohio Great Lakes Construction Alliance Substance Abuse Policy. Prior to work commencement, at those locations listed under Article 16.a. herein Contractor must provide a copy of its policy to FirstEnergy or FirstEnergy’s THIRD PARTY ADMINISTRATOR (TPA). The Contractor’s program for those locations listed under Article 16.a. herein, must include the following minimum requirements:

1. a. the Contractor shall be reimbursed all actual costs by FirstEnergy under the FirstEnergy Generation Corp. Substance Abuse Testing Program as administered by United, Inc. for those locations listed under Article 16.a. on the estimated basis of [$*****] maximum per test. This allowance shall include, if applicable, the cost of the employee's time to take the test.

b. The Contractor shall be reimbursed all actual costs by FirstEnergy under the Northwest Ohio Great Lakes Construction Alliance Substance abuse Testing Policy for those locations listed under Article 16.b. on a basis of [$*****] maximum per test. This allowance shall include, if applicable, the cost of the employee’s time to take the test.

c It is the Contractors responsibility to ensure prompt payment to the appropriate program administrator for drug testing services under either a. or b. above. Failure to do so shall be considered as a material breach of the contract terms that could result in actions by FirstEnergy for enforcement of the Contract terms, up to and including termination (for cause) of the contract.

2. The substance abuse program will be conducted in keeping with the established testing procedures developed by the Department of Health and Human Services Scientific and Technical Guidelines dated April 11, 1988 and any subsequent amendments thereto. The testing laboratory shall be licensed or certified, by either The Substance Abuse And Mental Health Services Administration or The College Of American Pathologists.

3. The drug testing shall consist of screening of the ten substances listed below, plus alcohol. The table below lists the screening and conformation limits for Gas Chromatography/Mass Spectrometry (GC/MS) analysis for drugs and the breathalyzer limit for alcohol.

                                   Screening                                    Confirmation

            Drug Class                                             Cut-Off Limit                                 Cut-Off Limit

            Amphetamines                                      1000 ng/ml*                                       500 ng/ml*

            Barbiturates                                            300 ng/ml                                        200 ng/ml

            Benzoylecgonine                                     300 ng/ml*                                      150 ng/ml*

(Cocaine Metabolite)

            Cannabinoids (THC)                                   50 ng/ml*                                       15 ng/ml*

            Methaqualone                                          300 ng/ml                                      100 ng/ml

            Opiates                                                 2000 ng/ml                                     2000 ng/ml*

            Phencyclidine                                            25 ng/ml*                                      25 ng/ml*

            Benzodiazepines                                      300 ng/ml                                     300 ng/ml

            Methadone                                               300 ng/ml                                     300 ng/ml

            Propoxyphene                                          300 ng/ml                                     300 ng/ml

            Alcohol, Ethyl**                                            0.001%                                        0.001%

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EXHIBIT 3.4(D)

*  Cut-off limits are established by the Department of Health and Human Services in their mandatory guidelines for Federal Workplace Drug Testing Programs.

** Blood alcohol or equivalent, as indicated, saliva, breathalyzer or similar test. In the event of a positive screening result, the donor may request a confirmation blood test. The MRO (Medical Review Officer) will not normally participate in the alcohol testing process. FirstEnergy considers a 0% blood alcohol to be consistent with their no alcohol policy.

4.         CONDITIONS OF EMPLOYMENT TESTING:

a. The Contractor's employees may begin work pending the results of the testing. Specimen collection must be completed within forty-eight (48) hours of permitting the employee onto the jobsite. Once specimen collection is performed, the test results shall be available within five days following the specimen collection. A chain of custody receipt shall be issued to each employee tested and shall be required for access to the work site and shall be valid for those five days.

b. Specimen collection may be completed prior to and as a pre-condition of employment. The Contractor shall certify that each of their employees have provided a negative test result or valid chain of custody receipt prior to being permitted access on the work site.

c. In lieu of the above, The Contractor must certify the required negative test results as a condition of employment for each employee by providing proof that the employee has tested negatively through an annual screening program approved by FirstEnergy within the last twelve (12) months.

5.         RANDOM TESTING

Random testing will be conducted on a predetermined percentage by FirstEnergy, based on the total number of contract employees on site. FirstEnergy’s Third Party Administrator will make the random selections. The selection process will involve a computer program using the workers' Social Security Numbers. The Random Testing will be conducted without prior notice and shall be scheduled at the conclusion of the mid-shift meal break.

6.         TESTING FOR CAUSE

An employee shall be subject to drug or alcohol testing, for cause, for any of the following reasons:

a. Involvement in, or cause of, an incident or an accident while on FirstEnergy’s premises, which causes or could have caused injury to the employee or another individual, or which causes or could have caused destruction or damage to FirstEnergy’s property.

b. Based on observed behavior which is unusual to the circumstances, or the individual's normal behavior, which indicates or could indicate impairment or substance abuse.

c. If any contractor employee must be transported to an emergency care facility or hospital due to an accident, a specimen collection container and chain of custody form shall accompany the employee. Each plant will maintain a supply of forms and containers for such an emergency. The attending physician shall be instructed to obtain a urine specimen and forward it and the chain of custody form to the testing laboratory. A blood alcohol or breath alcohol test shall also be administered.

d. If the contractor employee does not require emergency off-site care, the THIRD PARTY ADMINISTRATOR will be dispatched to the site for sample collection and breath alcohol testing.

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EXHIBIT 3.4(D)

7. PROCEDURES FOR SUBSTANCE ABUSE TESTING ARE AS FOLLOWS:

a. A qualified health professional at the collection facility will require picture identification by all participants.

b. The qualified health professional will provide the participant the proper chain of custody form and specimen collection container.

c. The participant will provide the required urine specimen and sign the chain of custody form.

d. The qualified health professional will furnish the participant affirmation that specimen has been collected and forward the specimen and the chain of custody form to the testing laboratory.

e. The testing laboratory will forward the results ofthe analysis to a Medical Review Officer (MRO).

8. THE MEDICAL REVIEW OFFICER SHALL BE RESPONSIBLE FOR:

a.         Notifying the tested individual of a positive result.

b.         Reviewing and verifying a confirmed positive test result.

            c.         The participant will provide the required urine specimen and sign the chain of custody form.

d. Reviewing the individual's medical record as provided by or at the arrangement of the tested individual as appropriate.

e. Notifying the Contractor's contact person of all test results, positive and negative.

f. Notifying FirstEnergy of any positive test result.

g. Processing re-test requests.

h. Participating in return to duty decisions as required.

i. Referring individuals testing positive to the appropriate medical evaluation. The cost of the evaluation or services shall be the responsibility of the individual.

9. IN THE CASE OF "POSITIVE" RESULTS OF ANY TEST, THE PARTICIPANT:

a. Shall have the right to have the original sample independently re-tested by a qualified laboratory. If the re-test is "negative", the participant shall be allowed to resume work immediately and be reimbursed for the cost of the independent test.

b. Shall have the right to secure a copy of all data relating to the test procedures and results, providing the costs of same are paid in advance to the initial testing laboratory by the participant.

10. CONFIDENTIALITY

 All test results shall be treated in a confidential manner. Accordingly, the testing facility will disclose the results only to the employee via the MRO (Medical Review Officer) and the designated Contractor representative(s). The MRO shall then inform FirstEnergy that the employee has tested positive for drugs or alcohol (no specifics as to type of drug will be given).

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EXHIBIT 3.4(D)

11.       DISCIPLINARY ACTIONS:

a. Any applicant or employee who tests positive for drugs or for alcohol, equal to or in excess of 0.04% will be rejected or discharged.

b. Any applicant or employee who refuses to submit to testing will be rejected or discharged. The inability or refusal to provide an appropriate specimen within THREE HOURS of request; shall be considered the same as a refusal to submit to testing.

c. Each applicant or employee shall certify that the specimen provided is theirs. Any applicant or employee involved in sample switching, altering, or tainting will be rejected or discharged.

d. Any applicant or employee who tests positive for alcohol at a level less than 0.04% shall be prohibited from working on any of FirstEnergy’s locations for 30 calendar days. Prior to returning to work the applicant or employee must provide FirstEnergy’s MRO proof of testing negative for alcohol and drugs.

e. If the applicant or employee has tested positive, it is the responsibility of the Contractor to escort that employee SAFELY from FirstEnergy’s property.

12.       SUSPENSION PERIODS AND RE-EMPLOYMENT ELIGIBILITY

Individuals become rejected or discharged as described in items 11 a, b, or c may become eligible for re-employment by the following means:

a. The individual presents written certification of the successful completion of an MRO approved rehabilitation program and proof of testing negatively for alcohol and drugs.

b. The individual serves a one year suspension from working at FirstEnergy’s locations and provides proof of testing negatively for alcohol and drugs to FirstEnergy’s MRO.

c. A certified testing laboratory shall perform all re-tests. All costs associated with the any re-testing or rehabilitation program shall be the responsibility of that individual.

d. An employee who is employed after meeting the conditions specified in 12 a. and b. above will be subject to a follow-up random testing for drugs and alcohol, for a period of three years. This three-year period shall commence with the date of their actual return to work or the date of the acceptance of a negative test by FirstEnergy’s MRO. Such an employee shall be subjected to a drug and alcohol test at any time, without notice.

e. During this three-year period, a positive drug and / or alcohol test will permanently eliminate this employee from working at any of FirstEnergy’s locations.

13.       THIRD PARTY ADMINISTRATOR

An independent THIRD PARTY ADMINISTRATOR (TPA) has been selected to coordinate administration of the program between the Contractors and FirstEnergy.

a. All Contractors, prior to mobilizing on an FirstEnergy’s plant site, for FirstEnergy locations listed under Article 16.a. below must contact the TPA to verify valid pre-employment tests in accordance with this procedure. The TPA shall also verify the applicability of the Contractors’ SUBSTANCE ABUSE AND TESTING PROGRAM. For FirstEnergy locations listed under Article 16. b. below, Contractor shall follow the guidelines and instructions to verify pre-employment tests contained in The Northwest Ohio Great Lakes Construction Alliance Substance Abuse Policy.

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.

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EXHIBIT 3.4(D)

b. As a service to the Contractor, the TPA will provide for specimen collections and testing. The Contractor is not obligated to use this service for conducting its SUBSTANCE ABUSE TESTING PROGRAM. The use of the TPA’s services for off-site specimen collection should be coordinated between the TPA and the Contractor.

c. The TPA will coordinate with FirstEnergy for specimen collections at FirstEnergy’s locations as required.

d. Administer random selections and testing.

e. Collect and document results from the independent laboratory.

f. Consolidate results and provide statistics to FirstEnergy as requested.

g. Provide for the MRO services as described.

h. Issuing Drug Cards as needed. FirstEnergy shall bear the cost of any cards issued.

14.   a.  FirstEnergy’s independent Third Party Administrator for those locations listed under

Article 16.a. below is:

United Labs, Inc.

547 Keystone Dr

Suite 100

Warrendale, PA 15086-6502

Phone: (800) 437-8483

                                    Fax:(724) 772-0811

ATTN: Cindy Matykavisch

b. FirstEnergy’s independent Third Party Administrator for those locations listed under Article 16.b. below is:

                        M.O.S.T./NW Ohio GLCA

Attn: Becky Pietz

753 State Ave., Suite 800

Kansas City, KS 66101

Phone: (877) 522-6869

Fax: (913) 281-2505

Email: rpietz@mostprograms.com

The contact person is Becky Pietz

15. FIRSTENERGY RESERVES THE RIGHT TO AMEND OR CHANGE THESE PROCEDURES ESTABLISHED HEREWITH AT ANY TIME WITHOUT PRIOR NOTICE. CONTRACTOR SHALL BE PROVIDED NOTICE OF ANY SUCH CHANGE.

16. FIRSTENERGY GENERATION CORP. GENERATING PLANTS AND LOCATIONS

The following locations are covered under FirstEnergy’s SUBSTANCE ABUSE AND TESTING PROGRAM:

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EXHIBIT 3.4(D)

Bruce Mansfield Plant               Shippingport, PA

W. H. Sammis Plant                 Stratton, OH

R. E. Burger Plant                    Shadyside, OH

Edgewater Plant                       Lorain, OH

Mad River Plant                        Springfield, OH

Ashtabula Plant                        Ashtabula, OH

Eastlake Plant                          Eastlake, OH

Lake Shore Plant                      Cleveland, OH

            Toronto Plant                            Toronto, OH

            Gorge Plant                              Akron, OH

            West Lorain Plant                     Lorain, OH

            Seneca Pumped Hydro Plant     Near Warren, Pa

            Sumpter                                   Belleville, MI

b. The following locations are covered under the Northwest Ohio Great Lakes Construction Alliance Substance Abuse Testing Policy:

Bay Shore Station                     Oregon, OH

Richland                                   Defiance, OH

            Stryker                                     Stryker, OH

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EXHIBIT 3.4(D)

FIRSTENERGY GENERATION CORP. EMPLOYMENT SIGN-UP &

SUBSTANCE ABUSE SCREENING PROCESS

Instruction for Contractor Employment Eligibility Verification

(Excluding Bayshore, Richland, and Stryker Locations)

1. Employees are to be screened prior to the start of any a project/job on a plant site. The contractor shall complete the Eligibility Sign-Up form prior to the start of any work on FirstEnergy’s property. It is the responsibility of the Contractor to update the list as new employees are hired. For the Bayshore, Richland and Stryker, locations, see Item 10 below.

2. The Eligibility Sign-Up form must contain each employee’s name, social security number, and valid drug card information. Each employee must be able to produce two (2) valid forms of identification for verification.

3. The completed form(s) shall be faxed to FirstEnergy’s Third Party Administrator. For the Bayshore, Richland and Stryker locations, see Item 10. below prior to the start of the project and as new employees are hired. Please FAX to:

United Labs, Inc.

547 Keystone Dr

Suite 100

Warrendale, PA 15086-6502

Phone: (800) 437-8483

                                    Fax:(724) 772-0811

ATTN: Cindy Matykavisch

4. A copy of the Eligibility Sign-Up form should be forwarded to FirstEnergy’s designated representative.

5. The Contractor shall provide to FirstEnergy’s designated representative a list of all employees on site at the beginning of each shift. This list will contain the employee’s name and social security number.

6. The Third Party Administrator shall notify the contractor as soon as possible if any of the employees, listed on the Eligibility Sign-up Form are ineligible for employment on FirstEnergy’s property.

7. When the Contractor is notified that an employee is ineligible for employment, the Contractor shall immediately disqualify that employee from performing any work on FirstEnergy’s property; and shall require the employee to leave FirstEnergy’s property. FirstEnergy’s on-site security forces (if available), may assist in escorting the employee from FirstEnergy’s property.

8. FirstEnergy’s plant site coordinator shall be notified that an ineligible employee has been escorted from FirstEnergy’s property.

9.The Contractor is responsible for employee’s SAFE removal from FirstEnergy’s property.

10. For the Bayshore, Richland and Stryker locations, Contractor shall follow the guidelines and instructions contained in The Northwest Ohio Great Lakes Construction Alliance Substance Abuse Policy.

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EXHIBIT 3.4(D)

FirstEnergy Generation Corp.

CONTRACTOR NAME:__________________________________________________________

ADDRESS:__________________________________________________________________

___________________________________________________________________________

CITY:______________________________ STATE:_________ ZIP:______________________

CONTACTS: ___________________________________________________________________

PHONE:_________________________ EXT:_________

FAX:__________________________

FOR FirstEnergy LOCATION: _____________________

CONTRACTOR’S

SITE START

CONTACT: _______________________ P.O.#: ____________ DATE: _________________

PHONE: ________________________________ FAX: __________________________________________________________________

	EMPLOYEE NAME		VALID CARD		UNITED, INC. USE ONLY
NO.	(PRINT: Last, First, Initial)	SOC. SEC. #	TYPE	DATE	LU	A/N

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 CONFIDENTIAL TREATMENT REQUESTED

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EXHIBIT 3.4(E)

LABOR REQUIREMENTS

1. The Contractor is responsible for providing all labor personnel, both craft and non-craft, as required. The Contractor shall employ AFL-CIO skilled craftsmen who are members of local unions affiliated with the AFL-CIO building and construction trades unions for the performance of the Work that is normally and historically the jurisdiction of those trade unions for the location at which the Work is to be performed.

2. Craft labor Work shall be performed under the terms of the National Erectors Association National Maintenance Agreement and/or their equal under similar national maintenance agreements. For plants as designated below, the agreement shall include the wage rate modification granted by the National Maintenance Agreements Policy Committee. The Contract price shall be based on performing the Work under such agreement, and modifications as applicable. For other plants designated below also, there shall be no wage rate modification.

3. Contractors who are awarded Work are to conduct Pre-Job Conferences as stipulated in Article1 - Recognition, and assign work to the appropriate crafts according to the recognized and traditional jurisdiction.

4. Contractors are required to furnish a copy of the first and signature pages of such agreements with each craft prior to commencing the work.

5. FirstEnergy Generation Corp. shall pursue and anticipates receiving approval from the National Maintenance Agreements Policy Committee (NMAPC) for a wage rate site modification at the locations indicated below. The modification allows for the Work to be performed [*****%] of the wage rates contained in the local collective bargaining agreements and [*****%] of the fringe benefits listed in those agreements. The Contractor is responsible for applying for said agreements and must be in possession of them with permission from the appropriate international unions for requesting extension of the FirstEnergy National Maintenance Agreement to cover Work to be performed at these specific FirstEnergy Generation Corp. Plants: R. E. Burger, Edgewater, D. B. Mansfield, W. H. Sammis, and Seneca.

6. Plants which have not been granted a wage rate modification, but which require use of the National Maintenance Agreement with no modification (100%) to rates are: Ashtabula, Bayshore, Eastlake, Lakeshore, Mad River, Richland, Sumpter and West Lorain.

7. Failure to comply with the foregoing requirements shall be considered as a material breach of the terms of the contract, subject to termination for cause if such action is deemed necessary by FirstEnergy Generation Corp.

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EXHIBIT 3.5(E)-1

FIRSTENERGY CONTRACTOR SAFETY PROGRAM FOR FOSSIL GENERATION

     CONTRACTOR SUPERVISION                                                                                                1 

     SAFETY AND HEALTH OBLIGATIONS                                                                                     1

 1. DESIGNATION OF SAFETY SUPERVISOR                                                                      1

 2. GENERAL SITE RULES AND HOUSEKEEPING                                                               2

 3. PERSONAL PROTECTIVE EQUIPMENT                                                                          2

 4. EMERGENCIES                                                                                                             3

 5. FIRST AID                                                                                                                      3

 6. FIRSTENERGY GENERATION CORP. EQUIPMENT AND UTILITIES                                  3

 7. LOCKOUT/TAGOUT AND CONTROL OF HAZARDOUS ENERGY                                      3

 8. EXCAVATION AND TRENCHING                                                                                     3

 9. SCAFFOLDING AND FALL PROTECTION                                                                        4

10. ASBESTOS                                                                                                                  4

11. INORGANIC ARSENIC                                                                                                   4

12. LEAD                                                                                                                           4

13. HOT WORK                                                                                                                  4

         14. POWERED INDUSTRIAL TRUCKS, OTHER VEHICLES AND CRANES -

                   DRIVERS AND OPERATORS                                                                                    5

15. WRITTEN SAFE WORK PROCEDURES                                                                         5

16. EMPLOYEE TRAINING AND QUALIFICATIONS                                                               5

17. INCIDENT REPORTING                                                                                                  5

18. CONFINED SPACES                                                                                                     6

19. PERMITS, LICENSES AND INSPECTIONS                                                                      6

20. GENERAL RULES FOR HAZARDOUS MATERIALS AND EQUIPMENT                             6

21. FIRE EXTINGUISHERS AND FIRE WATCH                                                                      7

22. COMPLIANCE AUDITS                                                                                                   7

PROHIBIED ACTS                                                                                                                     7

SECURITY AND FACILITY ACCESS                                                                                           7 

CONTRACTOR SUPERVISION

Unless specified in this safety guide, the Contractor will at all times be solely responsible for all means, methods, techniques, and procedures for the work specified in the contract. The Contractor is responsible for all acts and omissions, of all their employees, subcontractors and agents, performing any of the contracted work. The Contractor will at all times maintain appropriate discipline among its employees, and will not employ any person unfit or unqualified in that portion of the contracted work assigned to them.

The Contractor has the authority and responsibility to control, and/or correct all safety and health hazards associated with the contracted work. If the Contractor becomes aware of a hazard which the Contractor contends was created or caused by FirstEnergy, the Contractor must notify the designated FirstEnergy contact person immediately in the case of an imminent hazard, or as soon as possible in all other cases.

SAFETY AND HEALTH OBLIGATIONS

1. Designation of Safety Supervisor

The Contractor must designate a responsible member of its organization at the job site, whose duty would include safety and health compliance, and the prevention of accidents. The name and position of any person designated must be reported in writing to FirstEnergy Site Safety Representative or other designated FirstEnergy representative.

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2.General Site Rules and Housekeeping

A. Portable ladders are to be tied or lashed to prevent the ladder from slipping and must have non-slip bases. Metal and any conductive ladders will not be permitted.

B. Hoses, welding leads and electrical cords generally will be run overhead to eliminate tripping hazards or damage by heavy equipment.

C. Temporary floor openings are to be barricaded and flagged as required by OSHA regulations.

D. Compressed or Plant air must not be used for cleaning clothing or shoes.

E. All equipment used in proximity to overhead lines must be properly grounded. Work near overhead lines must be communicated to FirstEnergy Site Safety Representative’s attention.

F. Extreme caution must be used when walking or driving near railroad tracks on plant property. Most locomotives are operated by remote control, and unmanned. Crossing a railroad track by crawling under or between railroad cars is forbidden.

G. Rigging and hoisting of material or equipment must be done in a manner to ensure safety to personnel and existing equipment in the hoisting area.

H. All posted signs must be observed.

I. Fire extinguisher, fire hoses, and other fire fighting equipment must not be moved from their designated locations, except in the event of a fire.

J. If a plant fire extinguisher is used, contact FirstEnergy Generation Corp. Site Safety Representative.

K. The contractor must also be aware of various hazards existing in and around an operating power plant and take appropriate steps to protect their employees. Hazards include, but are not limited to:

· Rotating equipment such as motors, fans, and air compressors

· High voltage switches, cables, and overhead lines

· High temperature/ high pressure steam piping and vessels

· Sensitive control equipment with associated tubing, piping and wiring

· Automatic safety valves and other power actuated valves

· High noise level areas

· Potential exposure to arsenic, asbestos and/or lead

3. Personal Protective Equipment

The Contractor must ensure that all its employees utilize all Personal Protective Equipment (PPE) required by applicable Occupational Safety and Health Administration (OSHA) laws and regulations. FirstEnergy will not provide safety equipment for the Contractor's work activities.

Hard hats, safety glasses, and hearing protection where appropriate must be worn at all times when on FirstEnergy power plant property. Proper sturdy footwear must be worn at all times.

Compliance will include, but not be limited to, the following:

A.Conducting a hazard assessment prior to job initiation, to determine what if any PPE is needed for their employees.

B.Conducting personal sampling if required by OSHA regulations.

1) If personal sampling is required, the Contractor will inform FirstEnergy Site Safety Representative, in writing, of the personnel and/or Subcontractor that will be performing the sample collection and/or analysis.

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2) FirstEnergy reserves the right to reject any/or all parties involved with the sample collection and/or analysis.

3) The Contractor will supply FirstEnergy with the results of all personal monitoring samples collected on FirstEnergy property.

FirstEnergy has determined that in any enclosed area that transports circulating water, there is a potential for the existence of common pathogenic organisms. The Contractor will be responsible for the proper protection of its employees and others in relation to the contracted work performed in these areas.

Unless told otherwise by FirstEnergy Representative, or determined by test results, contractors must assume that all insulating materials including Thermal System Insulation, surfacing materials, and other building materials such as floor tile, gaskets, old wire insulation, and transite board contain asbestos. Contract workers must be properly trained and wear the proper PPE while working with these materials.

4. Emergencies

The Contractor must be aware of and comply with any emergency action plans for the facility where contracted work is performed. The Contractor must develop a Site Specific Emergency Evacuation Plan that complements the Facility Emergency Evacuation Plan and inform their workers of the plan. The Site Specific Emergency Evacuation Plan shall be submitted to FirstEnergy for review and approval prior to the commencement of work.

In an emergency potentially threatening the safety of an employee’s life, the safety of the job site, or of adjoining property, the Contractor is permitted to act at its discretion to prevent property loss or personnel injury.

5. First Aid

First Aid services and provision for medical care are the responsibility of the Contractor. The Contractor must provide its own first aid supplies, emergency response equipment, and prompt medical attention in case of injury to its employees. Provisions must be made and in place prior to the commencement of the work. The Contractor is responsible for ensuring that personnel trained in first aid are available on site while work is occurring.

6. FirstEnergy Generation Corp. Equipment and Utilities

The Contractor is prohibited from starting, stopping, or otherwise operating FirstEnergy Generation Corp. owned or leased equipment and utilities, unless specifically authorized to do so in writing. The Contractor can not open or close any valves, breakers, or switches, enter into any equipment, or cut into any piping or structure, without first obtaining permission from the proper FirstEnergy contact designated by the facility’s management. (See section on Lockout/Tagout)

7. Lockout/Tagout and Control of Hazardous Energy

The Contractor shall develop a Site Specific Lockout/Tagout program. The Contractor’s Site Specific Lockout/Tagout program will be required to comply with FirstEnergy Generation Corp.’s Lockout/Tagout program. A copy of FirstEnergy Generation Corp.’s Lockout/Tagout program will be provided to the Contractor. The Contractor will be required to train their employees to comply with the Site Specific Lockout/Tagout program, with all training completed prior to commencement of the related work.

8. Excavation and Trenching

Any excavation and trenching activities and building demolition operations must comply with applicable state or federal standards pertaining to those activities. This includes trenches dug for access to utility piping and plumbing. The Contractor will obtain all appropriate permits prior to beginning work on-site. The Contractor will agree to comply with OSHA regulations that include but are not limited to:

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EXHIBIT 3.5(E)-1

A. Using shoring or sloping for evacuations five (5) feet or deeper

B. Having shoring inspected by trained “competent” person

C. Hazardous atmospheric testing where needed

D. Providing appropriate means of egress.

9. Scaffolding and Fall Protection

All scaffolding must be erected, inspected and maintained in accordance with the applicable state and/or federal standards pertaining to those activities. The Contractor must obtain all appropriate permits prior to beginning work on-site. The Contractor will be responsible to ensure that all employees working on scaffolding are properly trained to qualify them as either a competent person, erector/dismantler, or user. Scaffolding will be inspected and tagged by a “competent person”. All scaffolding will utilize a guardrail system and toeboards. The Contractor will supply an informational copy of all scaffold inspection documents to the appropriate FirstEnergy Representative.

Scaffolding design drawings are required for each major installation of scaffolding. A Registered Professional Engineer (PE), for the state jurisdiction in which the work shall be performed, must approve the scaffold design and indicate approval by the appropriate PE Stamp affixed to the design drawings.

100% Fall Protection must be utilized where personnel are exposed to a fall of six feet or more.

10. Asbestos

Unless communicated otherwise, all existing facility insulating materials including Thermal System Insulation, surfacing materials, and other building materials such as floor tile, gaskets, old wire insulation, and transite board must be considered by the contractor to contain asbestos.

The Contractor will be notified of the presence of any known or suspected asbestos-containing materials in its proposed work areas. Only a contractor with the required OSHA training, certification and permits for asbestos abatement and removal may handle these materials. All other Contractors are prohibited from working on or removing asbestos-containing materials.

11. Inorganic Arsenic

If the Contractor will be working in a regulated work area for inorganic arsenic, FirstEnergy Site Safety Representativeor appropriate plant management will notify the Contractor of such. The Contractor is responsible for ensuring that only employees with the required OSHA training enter and perform work in this area. Contractors working in regulated work areas for inorganic arsenic will be responsible for providing and maintaining step off exit areas from these regulated areas. Disposal of all protective coveralls, PPE, or any other items that become contaminated, is the responsibility of FirstEnergy. Use of the facility’s change area and shower is prohibited.

12. Lead

All materials that have the potential to contain lead must be tested prior to the Contractor performing any work that could create dust or fumes. If possible, all lead should be removed prior to the start of work. FirstEnergy shall remove all identified pre-existing lead materials as required to support the work. If the work to be performed will cause lead particles or fumes to become airborne, then proper containment and control, techniques and equipment, must be in place. The Contractor is responsible for ensuring that only properly trained employees will perform such work and that all workers will wear the proper PPE. Air monitoring must be conducted for work activities that create dusts or fumes with lead. (See section 3)

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EXHIBIT 3.5(E)-1

13. Hot Work

The Contractor is prohibited from welding, burning, cutting, brazing or performing other "hot work" without prior authorization from FirstEnergy management or designated representative. All hot work must comply with state and federal standards for these work activities, including those standards pertaining to hot work permits and safe handling of compressed gases.

A. Due to the increased risk of fire resulting from the performance of Hot Work operations in the plant, all Contractors are responsible for the implementation of a Hot Work permit procedure. This Hot Work permit procedure must identify the necessary precautions taken to prevent fires resulting from open flame operations (i.e. welding, cutting, grinding, brazing).

B. The Contractor will ensure that there are sufficient numbers of fire extinguishers, of the proper type, in the work area.

C. The Contractor must focus on the fire hazards associated with their work. It may be necessary to post a “fire watch”, depending on the nature and location of work.

D. The Contractor will provide protection to prevent welding and burning sparks from falling below the work level. Fire retardant material must be used for this purpose.

E. The Contractor will screen or shield welding activities to prevent welding flash injuries to other personnel.

F. Storage area for oxygen and acetylene tanks must be separated by 20 feet or by a non-combustible barrier at least 5 feet in height. Cylinder must be secured at all times and capped when not in use.

G. Empty cylinders must be removed from the work area to the designated storage facility at the site.

14. Powered Industrial Trucks, Other Vehicles and Cranes - Drivers and Operators

The Contractor's employees who drive vehicles or forklifts, or who operate heavy equipment on FirstEnergy project sites, must have a current driver's license. Prior to employment on FirstEnergy project sites, it is recommended that all Contractor Crane Operators be Certified through the National Commission For The Certification Of Crane Operators (NCCCO). The Contractor must retain documentation of appropriate training in accordance with state and federal OSHA standards, Department of Transportation, and Department of Motor Vehicles codes and standards. The Contractor is responsible to meet all OSHA regulation pertaining to powered industrial trucks, mechanized equipment, motor vehicles, cranes derricks and hoists.

Contractor shall have a written Critical Lift policy and procedure. The Contractor’s Critical Lift policy and procedure shall be submitted to FirstEnergy for review and approval prior to the commencement of work.

15. Written Safe Work Procedures

The Contractor must have a written Site Specific Safety Program, including safe work practices, procedures, and programs. FirstEnergy or designated representative is to be provided a copy of the written Site Specific Safety Program that will be used at FirstEnergy facility. If upon review, FirstEnergy or designated representative deems the Site Specific Safety Program not to be in compliance with appropriate FirstEnergy policy and/or OSHA regulations, the parties involved must resolve issues prior to the commencement of work.

16. Employee Training and Qualifications

Contractor will provide only properly trained and qualified personnel to perform work under the Contractor Agreement. The Contractor will provide only employees who are trained in both general safe work practices and all applicable specific hazards of the contracted work. The Contractor has the authority and responsibility to train its employees with regard to general and work-specific hazards and safe practices. The Contractor must certify that all of its employees, subcontractors and Vendors, have been fully informed of tasks and specific hazards and safety requirements before beginning work on-site.

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17. Incident Reporting

The Contractor will immediately notify FirstEnergy management or designated representative of any site occupational injury or illness, employee exposure to hazardous substances, vehicle accidents, property damage, fires, environmental spills or releases, and/or "near misses". The Contractor will provide a written incident notice to FirstEnergy management or designated representative within 24 hours of any such occurrence and a written report to follow. FirstEnergy reserves the right to review the Contractor's incident investigations and/or perform FirstEnergy’s own investigations, for the sole purpose of verifying facts, protecting FirstEnergy personnel and property, and limiting FirstEnergy liability.

18. Confined Spaces

The Contractor must have in place a permit required confined space program for the protection of its employees from the hazards associated with the entry into confined spaces. Contractors are required to perform the following activities:

A. Obtain any available information regarding permit space hazards and entry operations from the host employer, (FirstEnergy Generation Corp., or designated representative).

B. Coordinate entry operations with the host employer, when both host employer personnel and Contractor personnel will be working in or near permit spaces.

C. Inform the host employer of the permit space program that the Contractor will follow and of any hazards confronted or created in permit spaces, either through a debriefing or during the entry operation.

FirstEnergy reserves the right to require the Contractor to follow FirstEnergy’s Confined Space Program. If FirstEnergy decides to require the Contractor to follow FirstEnergy’s Confined Space Program, a copy of FirstEnergy Generation Corp.’s confined space program will be given to the Contractor. An agreement to train contractor employees to FirstEnergy Generation Corp.’s confined space program must be in place, with training completed, prior to the commencement of work.

19. Permits, Licenses and Inspections

As defined in Section 3.6 of the Contract, the Contractor will secure and pay for all required licenses, permits and inspections necessary for performance and completion of the work. Within 5 working days of receiving such documents, the Contractor will deliver to FirstEnergy or designated representative copies of all permits, written approvals, licenses and inspections.

20. General Rules for Hazardous Materials and Equipment

When the use of hazardous materials (as defined by 29CFR 1910.1200) or equipment is necessary for the work being performed, the Contractor must exercise the highest care and must perform such activities under the supervision of properly qualified personnel. All applicable laws, rules, regulations and ordinances must be followed. The Contractor is responsible to comply with the OSHA Hazard Communication Standard. It is the Contractors responsibility to maintain an MSDS file of all hazardous substances and chemicals that the contractor has brought onto the site. Where and when a hazardous material will be used must be communicated to FirstEnergy site representative or designated representative, prior to commencing work.

The Contractor will be responsible for removing and properly disposing of all empty, partially full, or full containers of chemicals or chemical substances that were brought on site by the Contractor or its Subcontractors as part of its demobilization. All products and materials brought on site by a Contractor must be removed by that Contractor upon its departure. Do not put chemical containers into company trash containers. Failure to adhere to this provision will result in FirstEnergy disposing of the same and recovering the costs from the contractor. Also, all appropriate regulatory agencies will be notified of any non-compliance with any applicable regulations.

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Explosives of any description are not permitted to be stored on the Project Site. If the Contractor wishes to use explosives of any description, the Contractor must first provide written notice to, and receive written approval from FirstEnergy Representative and obtain the approval of all appropriate authorities having jurisdiction over the use of such explosives.

21. Fire Extinguishers and Fire Watch

The Contractor will work with FirstEnergy safety representative to ensure that there are sufficient numbers of fire extinguishers, of the proper type, in the work area. The Contractor will be responsible for providing a fire watch for periods during which its personnel may be engaged in activities constituting a fire hazard, or as otherwise required by law. Prior to engaging in any activities that could ignite a fire, the Contractor must ensure that all flammable material has been cleared from the affected area. See section on Hot Work.

22. Compliance Audits

Any contractor performing work at a FirstEnergy facility may be subject to compliance audits, which includes Safety as well as all other compliance documentation mentioned in this document, whether announced or unannounced, at FirstEnergy’s discretion.

PROHIBITED ACTS

The Contractor's and Subcontractor’s employees are prohibited from bringing firearms, knives, and weapons of any kind onto a FirstEnergy site or FirstEnergy facility, unless specifically authorized to do so in written contractual documents.

No one under the influence of any narcotics, drugs, controlled substances or alcoholic beverages is permitted on FirstEnergy property.

The illegal use, sale, or possession of narcotics, drugs, controlled substances or alcoholic beverages while on the job is strictly prohibited.

Contractor's employees and Subcontractors are permitted to smoking in designated areas only.

SECURITY AND FACILITY ACCESS

The Contractor will comply with FirstEnergy Generation Corp. security and access procedures for entry onto a FirstEnergy Generation Corp. controlled property, worksite, or facility. The Contractor's employees are authorized to enter only those work areas and structures specific to its contractual scope of the contracted work. Site specific security requirements will be distributed and reviewed with the contractor prior to mobilization.

The Contractor will maintain a daily log of all employees present on-site. This log is to be used in an emergency to identify missing personnel. The Contractor's employees must be logged in and out of the site each day in accordance with FirstEnergy Generation Corp. security procedures.

A visitor is defined, as any person not covered by contractual agreements with FirstEnergy Generation Corp. Visitors may include Vendors, tour groups or guests of the Contractor’s management. All visitors to FirstEnergy project sites or facilities must have prior authorization from FirstEnergy. Visitors shall wear all required PPE and must be escorted by the Contractor's supervisor or manager, or by its designated personnel, at all times while on-site. Visitors are prohibited from areas where contact with hazardous substances or materials is possible and are also prohibited from entering any area of the work site that requires respirators, or specialized medical monitoring or safety training.

The Contractor will immediately notify FirstEnergy management or designated representative of any regulatory agency inspectors or compliance personnel who request information about on-site activities or who request entry to the work site. This includes personnel from city, county, state or federal government agencies. Regulatory and government personnel must provide appropriate identification prior to entering the work site.

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EXHIBIT 3.5(E)-2

OSHA COMPLIANCE AND SAFETY

The Contractor represents and warrants that all articles, including but not limited to materials, equipment, protective clothing, scaffolding, walkways, ladders, etc. furnished, meet or exceed all specifications promulgate for safety and health standards under the Occupational Safety and Health Act of 1970 (29 U.S.C. 691 et. seq. 1970) and all regulations in effect as of the date of this Contract. The Contractor agrees that all labor furnished as part of this Contract is performed in accordance with all applicable OSHA requirements and all other applicable local, state, and federal regulations.

1. FirstEnergy has established designated areas for contaminants that may include, depending on the location at which work is to be performed, but are not limited to inorganic arsenic, lead, asbestos, hydrogen sulfide and sulfur dioxide. Exposure to any of these contaminants may be above certain OSHA limits when working in any of these designated areas.

2. The Contractor shall be responsible for the interpretation and compliance with all applicable OSHA regulations including, but not limited to the regulations related to the contaminants.

3. OSHA compliance shall include, but not be limited to, the following:

A. Conducting personal sampling if required by OSHA regulations.

1. If personal sampling is required, the Contractor shall inform FirstEnergy, in writing, of the personnel and/or Subcontractor that will be performing the sample collection and/or analysis.

2. FirstEnergy reserves the right to reject all parties involved with the sample collection and/or analysis.

3. The Contractor shall supply FirstEnergy with the results of all personal monitoring samples collected on FirstEnergy's property.

B. Supplying personal protective equipment and other related equipment if required by OSHA regulations.

4. The Contractor shall comply with all requirements of OSHA CFR 1910.1200, and any applicable state Right To Know Acts, including but not limited to the labeling of containers, proper handling of applicable materials, proper training and protection of employees and others, and the securing and implementing of Material Safety Data Sheets.

5. FirstEnergy has determined that in any enclosed area that transports circulating water, there is a potential for the existence of common pathogenic organisms. The Contractor shall be responsible for the proper protection of its employees and others in relation to Work performed in these areas.

6. For Work performed at FirstEnergy’s D. Bruce Mansfield Plant in the event of any emergency situation, specifically an emergency condition at FirstEnergy Beaver Valley Power Station, it may become necessary to notify and/or possibly shelter or evacuate all onsite personnel. FirstEnergy has developed The Bruce Mansfield Plant Emergency Preparedness Plan for emergency situations. The Contractor shall adhere to and participate in the plan if an emergency situation should occur.

The Work shall comply with the State(s) of Ohio, Michigan and/or Commonwealth of Pennsylvania, depending on the locations at with Work is performed, local codes and standards.

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EXHIBIT 3.8(E)-1

ASBESTOS HANDLING AND REMOVAL

The parties agree that asbestos handling and removal is not anticipated or intended to be part of the scope of this Contract. Contractor shall not in any way handle or remove asbestos without FirstEnergy’s permission. Contractor shall promptly advise FirstEnergy’s Superintendent in the event he discovers any material which may be composed of asbestos. FirstEnergy will make arrangements to test the material and should it be confirmed to be asbestos, take appropriate action to have the asbestos removed and disposed of in compliance with applicable rules and regulations.

However, should the Contractor handle or remove asbestos knowingly, in addition to fully indemnifying FirstEnergy pursuant to the Article entitled "INDEMNITY" of this Contract, the following requirements shall be applicable:

Contractor shall be responsible for compliance with 29 CFR 1910.1001 and 1926.1101, 40 CFR Part 61 Subparts A and M, and 49 CFR Part 173 Subparts A and M, and any other applicable rules and regulations and amendments thereto promulgated by OSHA, EPA or state and local governmental authorities. Contractor's requirements include but are not limited to:

1. Assignment to the plant site of a "competent person" as defined by applicable rules and regulations listed above.

2. Establishment of regulated areas pursuant to 29 CFR 1926.1101.

3. Supplying for all of it's employees and agents all respirators, protective clothing or other protective equipment utilized to comply with 29 CFR 1926.1101.

4. Contractor's employees and agents are to be properly trained in asbestos handling procedures, consistent with the aforementioned regulations, and licensed or certified by the Ohio Department of Health.

5. The Contractor, where necessary, is to build an enclosure to meet all applicable standards listed above. In addition, Industrial Hygiene Monitoring will be performed in accordance with the above regulations.

6. Supervision of on-site storage and handling of asbestos containing waste.

7. All shipments of asbestos shall be manifested, utilizing Purchaser's forms, initiated on Contractor's request by Purchaser's Authorized Representative. Purchaser's copies of completed manifest shall be returned to Purchaser's Authorized Representative.

8. All asbestos hazard abatement project clearance levels shall be in accordance with the following:

a. All clearance air-sampling to be analyzed by phase contrast microscopy (PCM) shall be conducted in accordance with the National Institute of Occupational Safety and Health (NIOSH) method 7400 entitled “Fibers” published in the NIOSH manual of analytical methods, 3^rd edition, second supplement, August 1987. A minimum of three samples shall be taken and show that the concentration of fibers for each sample is less than or equal to a limit of quantitation for pcm (0.01 fibers per cubic centimeter of air); and

b. All clearance air-sampling to be analyzed by Transmission Electron Microscopy (TEM) shall be conducted in accordance with the regulations established by the United States Environmental Protection Agency, 40 C.F.R. Part 763, Subpart E, Appendix A.

9. All clearance air sampling shall be conducted by an asbestos hazard abatement air-monitoring technician, or asbestos hazard evaluation specialist certified by the department, or a certified industrial hygienist or industrial hygienist in training as certified by the American Board of Industrial Hygiene.

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10.       Contractor shall provide regulatory permits, licenses, certificates and notices.

All requirements outlined above are to protect the health of Purchaser's employees outside the regulated area. Contractor is solely responsible for protecting the health of the Contractor's employees, agents, or subcontractors working with asbestos, recognizing that Purchaser is not responsible for supervising Contractor's personnel.

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EXHIBIT 3.8(E)-2

INORGANIC ARSENIC

Contractor shall satisfy itself in accordance with 29 CFR 1910.1018, that none of its employees are exposed to inorganic arsenic in concentrations greater than the permissible exposure limit contained therein. It shall be Contractor's responsibility and obligation to properly inspect the facilities of FirstEnergy where Contractor's employees will be performing the work, in particular but not limited to work in, about or around boilers and their associated ducts, tubing, and appurtenances. Contractor shall comply with all of the requirements of 1910.1018 CFR, including but not limited to initial and any additional exposure monitoring, establishment of regulated areas, and the provision of respirators to Contractor's employees if needed. Contractor shall immediately notify FirstEnergy if the presence of inorganic arsenic is detected at the permissible exposure limit set forth in 1910.1018.

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EXHIBIT 3.8(E)-3

LEAD ABATEMENT TERMS OF REIMBURSEMENT

Contractor is advised that the handling, removal and disposal (other than the potential for labor force exposure) of lead or lead containing materials or materials coated with lead containing material, including but not necessarily limited to lead containing paint, is not included as part of Contractor's scope of Work. However, the cost for labor force exposure for lead or lead containing materials or materials coated with lead containing materials shall be limited to monitoring results under OSHA requirements. In the event that monitoring results indicate a lead problem, the Contractor shall immediately notify FirstEnergy. At that point, documentation of any lead impacted activities shall be identified to FirstEnergy and all lead related Work timesheet information shall be provided. In addition, FirstEnergy shall perform intensive surveillance on the affected Work. Contractor shall support all administrative activities under FirstEnergy's direction. FirstEnergy shall reimburse Contractor for costs associated with lead abatement activities/affected Work as follows:

1. Fixed costs shall be reimbursed at actual cost and shall include:

a. All equipment and consumables used solely for lead abatement shall be billable to FirstEnergy. Equipment includes respirators, negative air machines, HEPA filters, pre-filters, secondary filters and flex hose. Consumables include respirator filters, suits/gloves, respirator wipes, towels and soap.

b. Labor hours incurred by craft employees for blood testing, respirator fit tests, pulmonary function tests, lead abatement training and maintenance for negative air machines.

2. Inefficiency of labor costs shall be provided for as follows:

a. Contractor shall notify FirstEnergy daily of all Work activities involving lead abatement and shall submit timesheets for this Work to FirstEnergy for approval.

b. FirstEnergy shall perform surveillance on those activities and utilize the results to approve Contractor's lead abatement related Work timesheets. FirstEnergy agrees to provide Contractor with copies of its daily surveillance reports for its use in preparing lead abatement related Work timesheets.

            c.         Contractor shall invoice FirstEnergy for approved lead abatement related Work timesheets.

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EXHIBIT 5.1

AQC SYSTEMS, PRICING METHODOLOGY AND DEFINITIONS

The Project, AQC Systems, will be composed of various Subprojects. Phases of the Project will include development, engineering, design, fabrication, procurement, construction, startup and commissioning.

The Professional Costs portion for this Project will include the Engineering and Graphics Labor (including Specialist Labor), Other Professional Labor, Professional Construction Labor, the Engineering Technology Charge, G&A, Engineering Subcontracts and Travel and Living Expenses as defined herein. For clarity, Engineering and Graphics Labor and Other Professional Labor performed by BAPC Ohio shall be compensated in the same manner as the Contractor, including rates, Engineering Technology Charge, G&A, and Fee.

All Engineering/Graphics Labor and Other Professional Labor will be performed by resources located in the Unites States and billed per Exhibit 5.1-10 ("Rate Sheet for Engineering/Graphics Labor and Other Professional Labor") unless otherwise agreed between FirstEnergy and Contractor. If requested by FirstEnergy, the Contractor will fully cooperate with FirstEnergy to utilize Contractor’s offshore or overseas Engineering/Graphics Labor and Other Professional Labor and FirstEnergy will be billed by Contractor at rates appropriate for that country of origin.

Two commercial options exist for this work. Commercial option number 1 is the “FE Vendor Arrangement”. Commercial option number 2 is the “Wrap Arrangement”.

The following is to be applied to the commercial options number 1 and number 2 as described herein, for conventional wet or dry FGD technology, including in duct application of dry FGD technology.

The "Target Construction Cost" of each Subproject, as defined during the Development Phase, will include the Professional Construction Labor (and associated G&A and Engineering Technology Charge), Purchased Equipment and Materials, Fabricated Items, Freight, Craft Labor, Consumables, Major Equipment & Tool Rental, Temporary Facilities, Subcontractors, builder risk insurance, bonds, taxes and any other expenditures deemed to be appropriate by FirstEnergy (as mutually agreed during the Development Phase of the Subproject). The “Target Construction Cost” excludes Professional Engineering and Graphics labor and Other Professional labor (with the associated Engineering Technology Charge and G&A), travel and living expenses, and Engineering Subcontracts. Each Subproject or combination thereof, will have a “Target Construction Cost” established once sufficient engineering and procurement is completed. The "Target Construction Cost" will include all estimated costs for the Subproject as well as all costs mutually agreed upon between the Contractor and FirstEnergy, and authorized by FirstEnergy using partial Notices To Proceed, up to the time the “Target Construction Cost” is established. The “Target Construction Cost” shall be exclusive of any Fee.

For Powerspan ECO ®, the “Target Construction Cost” will be established after sufficient design to establish quantities and construction plans, selection of sub-suppliers and resolution of any issues relating to the technology are made available by Powerspan.

Each Subproject will be performed on a cost reimbursable basis plus a Fee, with Contractor to be paid for all work performed by Contractor to meet its obligations under the Agreement, except as provided therein [e.g. warranty]. The Fee will be adjusted based upon the Incentive Scorecard results as described below, and further adjustments to the Fee payment will be made based upon the Subproject(s) over and underruns of the “Target Construction Costs” outside of the agreed to Deadband. Fee payments for the “Target Construction Cost” will be based on construction progress as compared to the construction schedule (see Exhibit 5.1. -1 (A), “Fee Adjustment”).

The verification of the “Target Construction Cost” will be based upon an “open book” review and audit of the estimated costs and any expenditures to date. At FirstEnergy’s option, a mutually agreed to third party may be used to review and evaluate the “Target Construction Cost” as provided by the Contractor.

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The Contractor’s Fee is profit only and does not contain any General & Administrative overheads. The Contractorwill place [*****%] of the ******at risk as further described herein. ****** Rates will be applied as stated herein (See “Pricing Rates and Summary Sheets”). A [******] Rate will be applied as stated herein to the Engineering and Graphics Labor, Other Professional Labor and Specialist rates, and a separate [******] Rate will be applied to Professional Construction Labor rates.

AQC SYSTEMS, PROJECT FEE AND FEE ADJUSTMENT

Except for Change Orders that increase or decrease the Target Construction Cost, once a Subproject’s “Target Construction Cost” is established during the Development Phase, that portion of the Fee will be fixed and will only be adjusted by two (2) mechanisms as follows:

1. INCENTIVE SCORECARDS

An outline of the Contractor Sample Scorecards, which are used to adjust the Contractor's ******, are as shown in Exhibit 5.1-2 “Sample Scorecards”.

Two Scorecards exist. A Scorecard exists for Engineering & Planning, and a separate Scorecard exists for Professional Construction Labor.

The Engineering & Planning Scorecard is used to adjust the ****** associated with the Engineering/Graphics Labor and Other Professional Labor. The Incentive Scorecard includes the following categories:

· Schedule

· Project Administration

· Quality

· Innovation

The Professional Construction Scorecard is used to adjust the ****** associated with the Professional Construction Labor. The Incentive Scorecard includes the following categories:

· Schedule

· Safety

· Quality

· Project Administration

· Cashflow

Each individual category shall have an associated weighted value, which total 100% for each Scorecard. On a periodic basis, but not longer than every six (6) months, and, as agreed to by both parties, a rating will be established for each category on the Scorecards using a combination of subjective and objective criteria as defined on the Scorecards. Those scores will be compared to the “Threshold”, “Target” and “Maximum” values. A percentage multiplier corresponding to the weighted average score will be applied to the ****** paid or due to the Contractor for the period being rated. Reconciliation for any over payment or underpayment will be made at that point in time for the rating period.

Some portions of the Sample Scorecards shown in Exhibit 5.1-2 are not currently defined. Scorecards will be finalized and agreed to by both parties during the Project Development Phase.

2. TARGET CONSTRUCTION COST

A “Target Construction Cost” will be established for each Subproject. A Deadband above and below the “Target Construction Cost” has been established within which no adjustment will be made to the AE Constructor’s Fee. The ****** will be adjusted for Final Construction Cost above or below [*****%] deadband in accordance with Exhibit 5.1-3, “Fee Table”. If the Final Construction Cost exceeds the “Target Construction Cost”, the Contractor's ****** will be reduced on a preset percentage of every dollar above the Deadband upper limit ("Contractor Fee Reduction Percentage"). Likewise, if the Final Construction Cost is less than the “Target Construction Cost”, the Contractor's ****** will be increased according to a preset percentage of every dollar below the Deadband lower limit ("Contractor Fee Increase Percentage") as shown in Exhibit 5.1-3, “****** Table”.

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Examples:

The examples shown below are for both the “Wrap Arrangement” and “FE Vendor Arrangement” where the Fee percent would be changed to be in agreement with the set value described herein.

If the Final Construction Cost exceeds the “Target Construction Cost”, but the Final Construction Cost is within the upper limit of the Deadband (within [*****%] of the Target Construction Cost, or less than [*****%] of the Target Construction Cost), then the Fee will not be adjusted based upon this adjustment mechanism.

If the Final Construction Cost exceeds the “Target Construction Cost”, and the Final Construction Cost is above the upper limit of the Deadband and greater than [*****%] of the “Target Construction Cost” then the Fee will be adjusted based on the Final Construction Cost. Therefore, if the Final Construction Cost is [*****%] higher than the “Target Construction Cost,” or [*****%] of the “Target Construction Cost”, then the final Fee in this example would be reduced by [*****%] of the Target Construction Cost in the “FE Vendor Arrangement” (or for the “Wrap Arrangement”, the Fee would be reduced by [*****%]).

If the Final Construction Cost is below the “Target Construction Cost”, but the Final Construction Cost is within the lower limit of the Deadband (within [*****%] of the Target Construction Cost, or greater than [*****%] of the “Target Construction Cost”), then the Fee will not be adjusted based on this adjustment mechanism.

If the Final Construction Cost is below the “Target Construction Cost”, and the Final Construction Cost is below the lower limit of the Deadband (less than [*****%] of the “Target Construction Cost”), then the Fee will be adjusted based on the Final Construction Cost. Therefore, if the Final Construction Cost is [*****%] lower than the Target Construction Cost or [*****%] of the Target Construction Cost, then the final Fee in this example would be increased by [*****%] of the Target Construction Cost in the “FE Vendor Arrangement” (or for the “Wrap Arrangement,” the Fee would be increased by [*****%]).

Approved Changes to the Work Scope (Attachment “A”) may occur during the duration of the Subprojects. Any changes to the Work Scope must be by Change Order, as provided in the Agreement. When the Subproject Work Scope is modified, FirstEnergy will work with the Contractor to determine the cost increase or decrease associated with the Work Scope change and include the cost increase or decrease in the "Target Construction Costs" by modifying the "Target Construction Cost" by the estimated amount. Fees of the same percentages used to establish the original "Target Construction Cost" Fee will be applied to the Work Scope change.

While the Contractor is executing the Work Scope at a FirstEnergy plant, FirstEnergy also may request the Contractor perform additional work outside of the Work Scope at the respective FirstEnergy plant. In such case, FirstEnergy and the Contractor shall mutually agree to the scope of the additional work to be performed. FirstEnergy shall pay for the additional work in the same manner as provided in this Contract. However, such additional work shall be its own Subproject and the Fee (equal to the percentage value for the “Target Construction Cost” in accordance with the “FE Vendor Arrangement”) associated with those costs will not be subject to either the Scorecard or "Target Construction Cost" adjustments provided herein.

I. PRICING FOR ENGINEERING, PROFESSONAL SERVICES, MATERIALS, FABRICATED ITEMS, AND OTHER PRICING INFORMATION

PROFESSIONAL COSTS (excluding G&A and Fee) shall be reimbursed as follows:

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1. Engineering and Graphics Labor

Engineering and Graphics Labor includes Project Management, Project Engineering (mechanical, electrical, civil, controls, I&C, performance, and other engineering disciplines), Drafting Specialists, and other engineering and design personnel required for the Subproject. The labor costs shall be determined by multiplying the direct time charging personnel hours assignable to the Subproject by the current applicable billing rate as stated herein (Exhibit 5.1-10, “Rate Sheet for Engineering/Graphics Labor, Other Professional Labor and Specialists”). The initial billing rates shall be in effect for the period January 1, 2005 through December 31, 2005. Commencing January 1, 2006, the billing rates will increase [*****%] per year on [*****%] of the billing rate, and be adjusted per the annual Consumer Price Index - Urban Wage Earners and Clerical Workers, Washington - Baltimore, DC-MD-VA-WV (Nov. 96 =100), as defined herein as the “Professional Labor Index”, for [*****%] of the billing rate. The Professional Labor Index for the average of the twelve months preceding each October will be used as part of next year’s escalation. For example, the rate for a Supervising Designer, Pay Grade [*****] is $[*****]/Hr. in 2005. The escalation on this rate would be ($[*****] x [*****%] x [*****] = $[*****]) + ($[*****] x [*****%] x [*****] [if the average Index for the 12 months proceeding October 2005 were [*****%]] =$[*****]) = a revised rate of $[*****]/Hr. effective January 1 - December 31, 2006. Chargeable hours shall be identified in the Project estimating process and approved by FirstEnergy. Hours documented by timesheets or acceptable electronic representations shall be submitted with a summary invoice for FirstEnergy approval and payment. A Professional Cost Fee will be applied to Engineering and Graphics Labor and to its associated G&A. The Rates provided do not include [******].

2. Other Professional Labor

Other Professional Labor includes Procurement Specialists, Cost Estimating Specialists, Office Managers, Scheduling Specialists, Constructability Specialists, Accounting/Cost Specialist, Timekeepers and other non-Engineering, non-Field Project support personnel. The labor costs shall be determined by multiplying the direct time charging personnel hours assignable to the Subproject by the current applicable billing rate as stated herein (Exhibit 5.1-10, “Rate Sheet for Engineering/Graphics Labor Other Professional Labor and Specialists”). The initial billing rates shall be in effect for the period January 1, 2005 through December 31, 2005. Commencing January 1, 2006, the billing rates will increase [*****%] per year on [*****%] of the billing rate, and be adjusted per the Professional Labor Index, as defined above, for [*****%] of the billing rate. For example, the rate for a Senior Project Controls Engineer, Pay Grade 25 is $[******]/Hr. in 2005. The escalation on this rate would be ($[******] x [******]% x [******] = $[******]) + ($[******] x [******]% x [******] [if the average Index for the 12 months preceding October 2005 were [******]%] = $[******] = a revised rate of [$*****]/Hr. effective January 1 - December 31, 2006. Chargeable hours shall be identified in the Project estimating process and approved by FirstEnergy. Hours documented by timesheets or acceptable electronic representations shall be submitted with a summary invoice for FirstEnergy’s approval and payment. A Professional Cost Fee will be applied to Other Professional Labor and to its associated G&A. The Rates provided do not include [******].

3. Professional Construction Labor

Professional Construction Labor includes Field Procurement Specialists, Project Superintendents, Project Field Engineer, Construction Management personnel, Startup and Testing Specialists, Safety Managers, QA/QC Specialists, Field Scheduling Specialists, Materials Handling Specialists, Rigging Specialists, Field Constructability Specialists, Timekeepers and other non-engineering Project field support personnel. The labor costs shall be determined by multiplying the direct time charging personnel hours chargeable to the Subproject by the current applicable billing rate as stated herein (Exhibit 5.1-11 “Rate Sheet for Professional Construction Labor”). The initial billing rates shall be in effect for the period January 1, 2005 through December 31, 2005. Commencing January 1, 2006, the billing rates will increase [*****%] per year on [*****%] of the billing rate, and be adjusted per the Professional Labor Index, as defined above, for [*****%] of the billing rate. For example, the rate for a Safety Person, Pay Grade 25 is $[*****]/Hr in 2005. The escalation on this rate would be ($[******] x [******]% x [******] = $[******]) + ($[******] x [******]% x [******] [if the average Index for the 12 months preceding October 2005 were [******]%] = $[******] = a revised rate of [$*****]/Hr. effective January 1 - December 31, 2006. Chargeable hours shall be identified in the Project estimating process and approved by FirstEnergy. Hours documented by timesheets or acceptable electronic representations shall be submitted with a summary invoice for FirstEnergy’s approval and payment. A Professional Construction Cost Fee will be applied to Professional Construction Labor and to its associated G&A. The Rates provided do not include [******].

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4. Engineering Technology Charge:

The Engineering Technology Charge includes reproduction costs, telecommunication costs, computer costs, postage, office supplies, etc. as listed in Exhibit 5.1-7 “Constituents of Technology Charge” and see “Pricing Rates and Summary Sheets”. The Engineering Technology Charges shall be determined by multiplying the direct time charging personnel hours assignable to the Subproject by the current applicable charge rate, [$*****] per billable hour for Engineering/Graphics Labor & Other Professional Labor, and [$*****] per billable hour for Professional Construction Labor, as stated herein The Engineering Technology Charge Rates are applied to the straight time hours, and applied to overtime hours up to and including [*****%] of straight time hours on an annual basis; and at a reduced rate of [*****%] of the respective Engineering Technology Charge ([$*****] per billable hour for Engineering/Graphics Labor & Other Professional Labor and Specialists; and [$*****] per billable hour for Professional Construction Labor) for overtime in excess of [*****%] of straight time hours, on an annual basis. An annual reconciliation of any over or under charges for the overtime Technology Charge is required. The initial Charge Rates shall be in effect for the period January 1, 2005 through December 31, 2005. Commencing January 1, 2006, the initial Charge Rates will be adjusted annually per the annual Consumer Price Index - Urban Wage Earners and Clerical Workers, Washington - Baltimore, DC-MD-VA-WV (Nov. 96 =100). For example, if the average Index for the 12 months preceding October 2005 were [*****%], the 2006 rates effective for January 1, 2006 through December 31, 2006, would be [$*****] and [$*****]/Hr., respectively. The reduced rate for overtime in excess of [*****%] of straight time hours would be [$*****] per billable hour and [$*****] per billable hour, respectively. Chargeable hours shall be identified during the Development Phase of the Subproject and approved by FirstEnergy. Hours documented by timesheets or acceptable electronic representations shall be submitted with a summary invoice for FirstEnergy approval and payment. [******] and [******] are not applied to the Engineering Technology Charges (See Exhibit 5.1-4, “Sample Invoices”).

5. Engineering Subcontracts:

Engineering Subcontracts (excluding Contractor affiliates) include any Engineering and Graphics costs which are billed directly to the Contractor associated with the Project. Engineering Subcontracts (excluding Contractor affiliates) will not have any A-E Constructor Fee, G&A, Engineering Technology Charge or markup applied.

6. Travel & Living Expenses:

Costs associated with relocation, travel and living expenses for the purpose of jobsite, Vendor visits or any visits or travel required for the performance of this Contract shall be billed at actual costs (see Exhibit 5.1-5, “U.S. National Temporary/Short Term Assignment Conditions to a Project Location” and “U.S. National Long Term Assignment Conditions to a Project Location”). Said costs shall be applicable to Contractor’s home office personnel as well as site personnel who are on temporary assignment away from their regular work site. Travel and living costs shall be documented on expense account forms accompanied by receipts or other documentation as required by FirstEnergy. Fee and or any markups shall not be applied to the travel & living expenses, and the travel & living expense shall not be included in the “Target Construction Cost”.

MATERIALS, EQUIPMENT, AND FABRICATED ITEMS SHALL BE REIMBURSED AS FOLLOWS:

7. Purchased Equipment and Materials

Contractor shall purchase certain equipment and materials for the Project. Procurement of goods shall occur by either competitive bidding including electronic reverse auctions, sole source commodity purchases, or sole source negotiated contracts. In the event of commodity purchases, the use of historical pricing trends shall be used for justification of the purchase. The costs for all purchased goods shall be identified by Vendor invoice as well as appropriate supporting information. Equipment and materials specified by the Contractor and purchased on the Contractor’s purchase order will be part of the "Target Construction Costs". Purchased equipment and materials shall be billed at the actual amount as identified by invoice. Equipment and materials supplied by an FE Vendorshall not be billed by the Contractorand will not be part of the "Target Construction Costs". However, the price of such equipment supplied by an OEM specified by FirstEnergy and purchased on FirstEnergy’s purchase order shall be included in the total amount used to establish the “Target Construction Cost” Fee, described below.

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8. Fabricated (Non Contractor):

Costs for fabricated material by a subcontractor shall be procured by either competitive bidding including electronic reverse auctions, sole source commodity purchases, or sole source negotiated contracts. The costs for all fabricated materials shall be identified by Vendor invoice as well as appropriate supporting information, if any, bill of materials or invoices. Fabricated materials shall be billed at the actual amount as identified by invoice and shall be included in the “Target Construction Cost”.

9. Fabricated (at Contractor’s Shop if applicable):

In the event the Contractor acquires fabrication facilities, competitive pricing for fabricated items shall occur and comparison pricing shall be performed with the Contractor’s shop. FirstEnergy will have final approval of materials fabricated by the Contractor’s shop and the cost of such material. Costs for the Contractor’s fabricated material shall be determined by multiplying the applicable fabrication charge rate times the direct labor hours chargeable to the Project. Fabrication charge rates shall be as defined and based on the actual Contractor’s shop utilized in the fabrication process. Material costs shall be determined by use of material invoices or appropriate inventory charge-out cost if material is sourced from Contractor’s inventory. Weld consumables and standard shop tasks (such as Radiographic Testing) shall be billed as defined and based on the actual Supplier’s shop utilized in effect at the time the invoice is issued. The costs associated with the fabricated materials shall be included in the “Target Construction Cost”. [******] shall not be applied to these costs.

10. Freight:

The costs for all freight shall be identified by Vendor invoice. Freight shall be billed at the actual amount as identified by invoice. Prior to expediting, FirstEnergy shall approve any expediting costs. At FirstEnergy’s option and in agreement with the Contractor, the Contractor may be directed to use FirstEnergy’s Freight Program. All Freight costs shall be included in the “Target Construction Cost” and shall be billed at direct cost. [******] is not applied to the Freight costs. Freight shall be invoiced separately from the equipment and materials purchased.

FIELD CONSTRUCTION (excluding G&A and Fee) shall be reimbursed as follows:

11. Craft Labor, Consumables, Tools, and Temporary Facilities as part of the Project Costs (See Exhibit 5.1-12):

All Field Construction Costs shall be paid for by FirstEnergy in accordance herein “Cost Reimbursable Work, Craft Labor”, using the actual craft-hours, defined as those hours that craft are paid in accordance with the National Maintenance Agreement as applied at the Site. The data provided in the example of Labor Costs attached as Exhibit 5.1-12 for specific craft (i.e., Boilermakers, Pipefitters and Electricians) is representative of those craft only and included for purposes of establishing examples of the methodology of costs for cost reimbursable work for craft labor. Before work commences at the Sammis Plant, the Contractor shall provide the same information for all craft to be employed by the Contractor in execution of the Project or any Subproject.

Field Construction Costs shall include, but shall not be limited to:

A. Wages and benefits of all Craft Labor engaged in the Work, including operating, unloading and loading of construction equipment.

B. Other labor costs when required by union contract or approved by FirstEnergy Owner.

C. Payments for all taxes and insurance related to the Craft Labor required to perform the work, including, but not limited to, public liability, workmen’s compensation, FICA, state and federal unemployment insurance.

D. Major Equipment and Tools (>[$*****]).

E. Small tools (<[$*****]) provided for Project use and expendables/consumables/job supplies.

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F. Facilities: Supplier’s charges for rented or leased field facilities, such as but not limited to offices, change shacks, portable toilets, etc, shall be billed at actual rental/lease invoice.

G. Field Purchased Materials shall be reimbursed as defined herein.

12. Subcontractors:

Contractor may subcontract certain field construction as provided in the General Terms and Conditions. Procurement of subcontracted services shall occur by either competitive bidding including electronic reverse auctions, sole source contracting, or sole source negotiated contracts. All Subcontractors costs shall be supported by invoices, as well as appropriate supporting information. Subcontractors shall be billed at the actual amount as identified by invoice. The Subcontractor costs are to be included in the "Target Construction Cost" of each Subproject.

   In the event that FirstEnergy direct hires and manages subcontractors, the Contractor will not receive any [******] on these subcontracts.

II. FEE AND G&A

FEE

1. Professional Cost Fee

The Contractor will be paid a Fee on Engineering and Graphics Labor and Other Professional Labor as stated herein (see Exhibit 5.1 -10, ("Rate Sheet for Engineering/Graphics Labor andOther Professional Labor"). The Fee represents [******]% profit and includes no G&A or other costs or overheads. The Fee will be applied to both the Engineering and Graphics Labor, and Other Professional Labor, as listed herein, and to the appropriate G&A. Fee is not applied to the Engineering Technology Charge (see Exhibit 5.1-4, “Sample Invoices”). The Fee is subject to periodic Scorecard Adjustments. The timing of the periodic adjustments shall be agreed by both parties, but at least every six (6) months. All of the Professional Cost Fee will be paid as part of the Professional Costs invoices. The amount of Professional Cost Fee will be adjusted by the Scorecard.

The Contractor will be paid a Fee on Professional Construction Labor as stated herein (see Exhibit 5.1 -11, “Rate Sheet for Professional Construction Labor”). The Fee represents [******]% profit and includes no G&A or other costs or overheads. The Fee will be applied to both the Professional Construction Labor and the appropriate G&A. Fee is not applied to the Engineering Technology Charge (see Exhibit 5.1-4, “Sample Invoices”). The Fee is subject to periodic Scorecard Adjustments. The timing of the periodic adjustments shall be agreed by both parties, but at least every six (6) months. The amount of Professional Construction Labor Cost Fee will be adjusted by the Scorecard, variance from the "Target Construction Cost" and Change Orders. The Fee for the Professional Construction Labor Cost will be fixed and will be subject to a payment schedule based on construction progress as compared to the construction schedule (see Exhibit 5.1-1 (A), ”Fee Adjustment”).

2. “Target Construction Cost” Fee

The Contractor’s [******] is the Fee, and Fee is a percentage of "Target Construction Costs" as stated herein (see “Pricing Rates and Summary Sheets”, below). Although shown as a percentage of "Target Construction Costs", the Fee will be fixed as a dollar value for a Subproject at the time the "Target Construction Cost" for that Subproject is established. The “Target Construction Cost” excludes Professional Engineering and Graphics labor and other Professional labor (and the associated Engineering Technology Charge and G&A), travel and living expenses, and Engineering Subcontracts. The amount of Fee will be adjusted by the Scorecard, variance from the "Target Construction Cost" and Change Orders. Payment of the Fees associated with the construction will be based on construction progress as compared to the construction schedule (see Exhibit 5.1-1 (A), “Fee Adjustment”).

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GENERAL AND ADMINISTRATIVE COSTS

3. G&A

G&A consists of overhead costs of the Contractor (see Exhibit 5.1-6,”Constituents of G&A (Overhead) Costs”). These costs do not include any direct-billed personnel or overheads directly associated with direct-billed personnel that are included in the rates provided for those individuals. The Contractor’s G&A rate is a percentage of the Professional Labor costs. G&A is charged to all straight time hours and to overtime hours up to and including [*****%] of straight time hours on an annual basis. G&A is not applied to overtime hours exceeding [*****%] of the straight time hours on an annual basis. Two separate G&A rates exist (see “Pricing Summary Sheet”). The G&A rate for Engineering/Graphics Labor and Other Professional Labor is [*****%] of the Engineering/Graphics Labor and Other Professional Labor rate. The G&A rate for Professional Construction Labor is [*****%] of the Professional Construction Labor Rate. These percentages are fixed for the duration of the contract.

VARIOUS COMMERCIAL OPTIONS EXIST WITH THE CONTRACTOR FOR THE AQC SYSTEMS. These options are delineated herein.

Commercial Option #1: “FE Vendor” Arrangement

Fee rates are the following:

The Engineering/Graphics & Other Professional & Specialists Labor Cost Fee rate is [*****%];

The Professional Construction (Field Non Manual) Labor Fee rate is [*****%];

The Target Construction Cost Fee rate is [*****%].

Commercial Option #2: “Wrap” Arrangement (Applicable to Sammis 5, 6, & 7 or Sammis 6 and 7)

The Fee rates are the following:

The Engineering/Graphics & Other Professional & Specialists Labor Cost Fee rate is [*****%];

The Professional Construction (Field Non Manual) Labor Fee rate is [*****%];

The Target Construction Cost Fee rate is [*****%].

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PRICING RATES AND SUMMARY SHEETS

I.SUMMARY OF PRICING FOR ENGINEERING, PROFESSINAL SERVICES, MATERIALS, FABRICATED ITEMS, AND OTHER PRICING INFORMATION

A.Professional Costs (Excluding G&A and Fee)

FeeIncluded

Applied?in Target?

1. Engineering/Graphics Labor                                                    {*****]                [*****]       Rate Sheet (Exhibit 5.1-10),

2. Other Professional Labor                                                        {*****]                 [*****]      Rate Sheet (Exhibit 5.1-10),

3. Professional Construction Labor                                              {*****]                 [*****]      Rate Sheet (Exhibit 5.1-11),

4. Engineering Technology Charge                                                                                      ($Below)/ Professional MH

    a. Engineering/Graphics/Other Professional                             {*****]                  [*****]      As defined in Exhibit 5.1-7

    b. Professional Construction Labor                                          {*****]                  [*****]     $[*****]/ Home Office MH

                                 [$*****]/Professional Construction MH

5. Engineering Subcontracts

      a. BAPC Ohio, and Nexant                                                   {*****]                  [*****]      Rate Sheet (Exhibit 5.1-10),

b. All other Engineering Subcontracts                                    {*****]                  [*****]     At Direct Cost

6. Travel & Living Expenses                                                        {*****]                  [*****]     At Direct Cost, as per Exhibit 5.1-5

B. Materials, Equipment and Fabricated Items

                                                                                             Fee                  Included

                                                                                         Applied?1in Target?2

1. Purchased Equipment and Materials                                       {*****]                 [*****]       At Direct Cost

2. Fabrication (Non-AE-Constructor Shop)                                   {*****]                 [*****]       At Direct Cost

3. Fabrication (at AE-Constructor Shop)                                      {*****]                 [*****]      Shop Rates, where appropriate 

4. Freight                                                                                  {*****]                 [*****]       At Direct Cost

C. Field Construction

                                                                                             Fee                   Included

Applied?1          in Target?2

1. Craft Labor, Consumables,                                                     {*****]                 [*****]        Exhibit 5.1-12, 5.1-8, 5.1-9,

    Major Eq. & Tools and Temporary Facilities   

2. Subcontractors                                                                      {*****]                 [*****]       At Direct Cost

II.FEE AND G&A

A.Fee

      1a. Engineering/Graphics Labor & Other Professional Cost Fee                       [*****%] of Home Office Professional

                  Billing Rate  (Items IA 1, & 2, &

                  IA 5(a) above, and G&A, IIB 1, below)

      1b. Professional Construction Labor Cost Fee                                                 [*****%] of Professional Construction

                  Billing Rate (Item IA 3 above, and

                  G&A, IIB 2, below) 

2. Target Construction Cost Fee - “FE Vendor Arrangement”                             [*****%] of Construction Cost

   (Items IB 1 & 2 & IC 1 & 2 above)

3. Target Construction Cost Fee - “Wrap Arrangement”                                     [*****%] of Construction Cost

   (Items IB 1 & 2 & IC 1 & 2 above)

_____________________

1 This indicates which items will have [*****] assocated with them.

2 This indicates wehich items will be included in the "Target Construction Cost" and are therefore subject to adjustment based on actual cost verses the "Target Construction Cost".

Page 9 of 10

 CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1

PRICING RATES AND SUMMARY SHEETS

B. G & A

1.  G&A (Engineering/Graphics and Other Professional Labor)         [*****] % of Labor Eng./Graphics &

                                                                                                           Other Prof. Labor Rates

2. G&A (Professional Construction Labor)                                      [*****] % of Professional Construction

                                                                                                            Construction Labor Rates

Page 10 of 10

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-1(A)

FEE ADJUSTMENT (On a Subproject basis)

Target Construction Cost Estimate

Target Construction Cost

Fixed Fee

Target Construction Cost excluding Prof. Const. Labor, Freight & Fabrication (at Contractor Shop)

(A) = Estimated Construction Cost excluding Prof. Const. Labor, Freight & Fabrication (at Contractor Shop)

(F) = A x [*****#] (for the FE Vendor Approach) or; (F) = A x [*****#] (for the Wrap Approach)

Fabrication (at Contractor Shop)

(B) = Estimated Subproject Cost for Fabrication (at Contractor Shop)

(G) = $0

Freight

(C) = Estimated Subproject Cost for Freight

(H) = $0

Professional Construction Labor Target (includes G&A)

(D) = Estimated Subproject Cost for Professional Construction Labor Target (includes G&A)

(I) = D x [*****#]

Total Target Construction Cost/Fee

(E) = A + B + C + D

(J) = F + G + H + I

Project Month ($000)

Cost Category

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

Subproject Total

I.    Engineering, Professional Services, Materials, Fabricated Items, and Other

A.      Professional Costs (Excluding G & A and Fee)

1.     Engineering/Graphics Labor

(K) = Actual Engineering/Graphics Labor Cost for the Month

K

K

K

K

K

K

K

K

K

K

K

K

K

K

K

K

K

Sum of all Monthly K for the Subproject

2.     Other Professional Labor

(L) = Actual Other Professional Labor Cost for the Month

L

L

L

L

L

L

L

L

L

L

L

L

L

L

L

L

L

Sum of all Monthly L for the Subproject

3.     Professional Construction Labor

(M) = Actual Professional Construction Labor Cost for the Month

M

M

M

M

M

M

M

M

M

M

M

M

M

M

M

M

M

Sum of all Monthly M for the Subproject

4.     Engineering Technology Charge (Home Office)

(N) = (Actual Engineering/Graphics Labor Hours + Other Professional Labor Hours for the Month) x 12.40

N

N

N

N

N

N

N

N

N

N

N

N

N

N

N

N

N

Sum of all Monthly N for the Subproject

4a.   Engineering Technology Charge (Prof. Const.)

(O) = Actual Professional Construction Labor Hours for the Month x 10.90

O

O

O

O

O

O

O

O

O

O

O

O

O

O

O

O

O

Sum of all Monthly O for the Subproject

5.     Engineering Subcontracts

(P) = Actual Engineering Subcontracts Cost for the Month

P

P

P

P

P

P

P

P

P

P

P

P

P

P

P

P

P

Sum of all Monthly P for the Subproject

6.     Travel & Living Expenses

(Q) = Actual Travel & Living Expenses Cost for the Month

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Sum of all Monthly Q for the Subproject

B.    Materials, Equipment and Fabricated Items

1.     Purchased Equipment and Materials

(R) = Actual Purchased Equipment and Materials Cost for the Month

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

R

Sum of all Monthly R for the Subproject

2.     Fabrication (Non-AE/Constructor Shop)

(S) = Actual Fabrication (Non-AE/Constructor Shop) Cost for the Month

S

S

S

S

S

S

S

S

S

S

S

S

S

S

S

S

S

Sum of all Monthly S for the Subproject

3.     Fabrication (at AE/Constructor Shop)

(T) = ActualFabrication (at AE/Constructor Shop) Cost for the Month

T

T

T

T

T

T

T

T

T

T

T

T

T

T

T

T

T

Sum of all Monthly T for the Subproject

4.     Freight

(U) = Actual Freight Cost for the Month

U

U

U

U

U

U

U

U

U

U

U

U

U

U

U

U

U

Sum of all Monthly U for the Subproject

C.    Field Construction

1.      Craft Labor, Consumables, Major Equ. & Tools and Temporary Facilities

(V) = Actual Craft Labor, Consumables, Major Equ. & Tools and Temporary Facilities Cost for the Month

U

U

U

U

U

U

U

U

U

U

U

U

U

U

U

U

U

Sum of all Monthly V for the Subproject

2.      Subcontractors

(W) = Actual Subcontractors Cost for the Month

W

W

W

W

W

W

W

W

W

W

W

W

W

W

W

W

W

Sum of all Monthly W for the Subproject

Project Status

Construction Progress (Cumulative Percent Complete)

(X) = Percent Project Complete shown in Bechtel 's Monthly Progress Report

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

Actual Construction Cost

(Y) = M + O +R + S + T + U + V + W + DD

Y

Y

Y

Y

Y

Y

Y

Y

Y

Y

Y

Y

Y

Y

Y

Y

Y

Sum of all Monthly Y for the Subproject

II.  Fee and G&A

A.  Fee

1.      Unadjusted Professional Cost Fee

(Z) = [*****#] x (K + L + CC)

Z

Z

Z

Z

Z

Z

Z

Z

Z

Z

Z

Z

Z

Z

Z

Z

Z

Sum of all Monthly Z for the Subproject

1a.     Unadjusted Professional Construction Labor Fee

(AA) = I x X

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

Sum of all Monthly AA for the Subproject

2.      Unadjusted Target Construction Cost Fee

(BB) = F x X

BB

BB

BB

BB

BB

BB

BB

BB

BB

BB

BB

BB

BB

BB

BB

BB

BB

Sum of all Monthly BB for the Subproject

B.  G & A

1. G & A (Engineering/Graphics and Other Professional Labor)

(CC) = [*****#] x (K+ L)

CC

CC

CC

CC

CC

CC

CC

CC

CC

CC

CC

CC

CC

CC

CC

CC

CC

Sum of all Monthly CC for the Subproject

2. G & A (Professional Construction Labor)

(DD) = [*****#] x M

DD

DD

DD

DD

DD

DD

DD

DD

DD

DD

DD

DD

DD

DD

DD

DD

DD

Sum of all Monthly DD for the Subproject

C.  Incentive

Engineering/Graphics Labor and Other Professional Labor Fee Scorecard

(EE) = Engineering & Planning Scorecard Results (Completed periodically and applied to the months since the last Scorecard results)

EE

EE

EE

EE

EE

EE

EE

EE

EE

EE

EE

EE

EE

EE

EE

EE

EE

Professional Construction Labor Fee Scorecard

(FF) = Professional Construction Labor Scorecard Results (Completed periodically and applied to the months since the last Scorecard results)

FF

FF

FF

FF

FF

FF

FF

FF

FF

FF

FF

FF

FF

FF

FF

FF

FF

1.      Professional Cost Fee Adjustment

(GG) = (EE-1) x Z for each month to which the scorecard applies

GG

GG

GG

GG

GG

GG

GG

GG

GG

GG

GG

GG

GG

GG

GG

GG

GG

Sum of all Monthly GG for the Subproject

1a.    Adjusted Professional Cost Fee (Paid Fee)

(HH) = Z + GG

HH

HH

HH

HH

HH

HH

HH

HH

HH

HH

HH

HH

HH

HH

HH

HH

HH

Sum of all Monthly HH for the Subproject

2.      Professional Construction Labor Fee Adjustment

(II) = (FF-1) x AA for each month to which the scorecard applies

II

II

II

II

II

II

II

II

II

II

II

II

II

II

II

II

II

Sum of all Monthly II for the Subproject

2a.    Adjusted Professional Construction Labor Fee (Paid Fee)

(JJ) = AA + II

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

JJ

Sum of all Monthly JJ for the Subproject

Actual Construction Cost %under(-)/%over(+) Target Construction Cost

(KK) = (Sum of all monthly Y for the Subproject - E) / E

Construction Cost Fee Adjustment

(LL) = Adjustment from Applicable Column on Exhibit 5.1 (D), FEE TABLE based on KK

Adjusted Construction Cost Fee

(MM) = Sum of all monthly BB for the Subproject + LL

Earned Fee

Professional Cost Fee

(NN) =Sum of all monthly HH for the Subproject

Professional Construction Labor Fee

(OO) = Sum of all monthly JJ for the Subproject

Target Construction Cost Fee

(PP) = MM

Total Earned Fee

(QQ) = NN + OO + PP

NOTE: See Exhibit 5.1 - (B) for a detailed example of Payment Methodology based on this Exhibit 5.1 - 1 (A)

Page 1 of 1

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-1(B)

PAYMENT METHODOLOGY EXAMPLE (On a Subproject basis)

Target Construction Cost Estimate	TCC	Fixed Fee
Target Construction Cost (excluding Prof. Const. Labor)	[$*****]	[$*****]
Fabrication (at AE/Constructor Shop)	[$*****]	[$*****]
Freight	[$*****]	[$*****]
Professional Construction Labor Target (includes G&A)	[$*****]	[$*****]
Total Target Construction Cost/Fee	[$*****]	[$*****]

 

Project Month ($000)

Cost Category

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

Subproject Total

I.  Engineering, Professional Services, Materials, Fabricated Items, and Other

A.    Professional Costs (Excluding G & A and Fee)

1.     Engineering/Graphics Labor

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

2.     Other Professional Labor

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

3.     Professional Construction Labor

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

4.     Engineering Technology Charge (Home Office)

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

4a.   Engineering Technology Charge (Prof. Const.)

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

5.     Engineering Subcontracts

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

6.     Travel & Living Expenses

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

B.    Materials, Equipment and Fabricated Items

1.     Purchased Equipment and Materials

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

2.     Fabrication (Non-AE/Constructor Shop)

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

3.     Fabrication (at AE/Constructor Shop)

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

4.     Freight

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

C.    Field Construction

1.     Craft Labor, Consumables, Major Equ. & Tools and Temporary Facilities

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

2.     Subcontractors

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

Project Status

Construction Progress (Cumulative Percent Complete)

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

Actual Construction Cost

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

II.  Fee and G&A

A.    Fee

1.     Unadjusted Professional Cost Fee

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

1a.   Unadjusted Professional Construction Labor Fee

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

2.     Unadjusted Target Construction Cost Fee

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

B.    G & A

1.     G & A (Engineering/Graphics and Other Professional Labor)

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

2.     G & A (Professional Construction Labor)

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

C.    Incentive

Engineering/Graphics Labor and Other Professional Labor Fee Scorecard

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

Professional Construction Labor Fee Scorecard

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

[*****%]

1.     Professional Cost Fee Adjustment

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

1a.   Adjusted Professional Cost Fee (Paid Fee)

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

2.     Professional Construction Labor Fee Adjustment

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

2a.   Adjusted Professional Construction Labor Fee (Paid Fee)

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

[$*****]

Actual Construction Cost %under(-)/%over(+) Target Construction Cost

[*****%]

Construction Cost Fee Adjustment

[$*****]

Adjusted Construction Cost Fee

[$*****]

Earned Fee

Professional Cost Fee

[$*****]

Professional Construction Labor Fee

[$*****]

Target Construction Cost Fee

[$*****]

Total Earned Fee

[$*****]

Page 1 of 1

 CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-2

SAMPLE SCORECARDS

Scorecard - Assessed on a Subproject by Subproject Basis

Engineering & Planning - PHASE 1

POSSIBLE FEE: $******¹ 

Value
******%	Schedule				All Relationship Curves TBD
$******	******%	Major Milestones and Key Activities (Phase 1) 2	******% Fee Criteria	Actual	Fee Earned %	Fee Earned $
		Subproject 1 and Common
		Unit 1 - 4 Conceptual Design Drawings Issued for FE Review	15-Jul-05 3	2 days late
		Issue Units 1 - 4 Performance Specifcation for Quote	15-Jul-05	3 days early
		Unit 1 - 4 Technical Bid Evaluation Issued	15-Jul-05	on time
		Unit 5 Conceptual Design Drawings Issued for FE Review	15-Jul-05	on time
		Issue Unit 5 Performance Specification for Quote	15-Jul-05	2 days early
		Unit 5 Technical Bid Evaluation Issued	15-Jul-05	6 days late
			Target is on time	3 days late	******% 4	$******5

1 For illustrative purposes only, we will use a potential fee for the reporting period of $******, to show how the actual fee is calculated.

2 These are representative milestones, as an example of Phase 1 deliverables. Actual critical milestones to be selected based on Engineering Phase 1 schedule.

3 Actual dates established based upon Engineering Phase 1 schedule

4 Fee earned to be calculated on a subproject basis, based on the cumultive performance of milestones within the subproject

5 $******x ******% x ******% = $******

Graph  (redacted plot lines)

- Schedule Fee Earned

- Percent Fee Earned

Calendar Days Late/Early

******%	Schedule Performance Index (SPI) 1	******% Fee Criteria	Actual	Fee Earned %	Fee Earned $
	Subproject 1 and Common	Target is ******	.******	******%
	Overall	Target is ******	.******	******% 2	$******
				Total Schedule:	$******3

1 SPI is calculated using the following formula: "Hours Scheduled to be Earned" divided by "Budget Hours Earned". A result less than 1 reflects performance ahead of schedule. That is, you have earned more schedule hours than planned at the data date.

2 Fee assessed at subproject level for SPI. Another alternative would be to assess fee on a total project SPI.

3 $******+ $******= $****** which would be the total fee for schedule performance

Graph (redacted plot lines)

- SPI Fee Earned

- Fee Earned

- SPI

******%	Project Administration		******% Fee Criteria	Actual	Fee Earned %	Fee Earned $
$******	******%	Communications Responsiveness	******	******
	******%	Project Status Reporting	******	******
	******%	Problem Resolution	******	******
	******%	Proper Communication with Plant Personnel	******	******
		Overall	Target is ******	****** 1

Information provided by FirstEnergy via customer survey

Responsiveness (Customer Survey)

Based on a scale of:

1: Unsatisfactory (does not meet requirements)

2: Minimal (meets some of the requirements)

3: Adequate (meets most of the requirements)

4: Satisfactory (meets the requirements)

5: Outstanding (exceeds requirements)

1 Scale is based on the scoring suggested to the left of this comment. Actual questions to be established during team building, based on sample to be provided by FirstEnergy.

Graph - (redacted plot lines)

- Responsiveness Fee Earned

- Percent Fee

- Responsiveness Rating

******%	OEM Oversight
$******		(Details to be finalized during the Development Phase)	100% Fee Criteria	Actual	Fee Earned %	Fee Earned $

Note: Scorecards to be finalized during the Development Phase of the Project.

PAGE 1 OF 6

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-2

SAMPLE SCORECARDS

Scorecard - Assessed on a Subproject by Subproject Basis

		Phase 1 Quality Program Established	*****% Fee Criteria	Actual	Fee Earned %	Fee Earned $
		Phase 1 Project Execution Plan Issued	15-Jul-05	1 days late
_________	_________	Project Quality Plan Issued	15-Jul-05	3 days early
		Project Procedures Manual Issued	15-Jul-05	on time
******%	Quality	Project Engineering Prccedures Manual Issued 1	15-Jul-05	on time
$******		Site Interface Procedures Manual Issued	15-Jul-05	2 days early
		Communication Plan Issued	15-Jul-05	6 days late
		Lessons Learned Plan Issued	15-Jul-05	on time
		Project Automation Plan	16-Jul-05	on time
			Target is on time	2 days late	******% 2	$******

1 For phase 1, the quality portion of the fee to be established based on the succesful setup of the project's quality program. This involves creating all of the necessary procedures and plans that integrate with FirstEnergy and Sammis plant requirements and protocols, including establishment of the management information system plan.

2 Fee earned to be calculated based on same basis as schedule milestones above.

Graph - (redacted plot lines)

- Quality Program Deliverables Fee Earned

- Percent Fee

- Calendar

Phase 2 Quality Items	****% Fee Criteria 1	Actual	Fee Earned %	Fee Earned $
Major Technical Specifications		******%
Single Line Diagrams		******%
Piping & Instrumentation Diagrams		******%
Piping Isometric Drawings		******%
Electrical Raceway Drawings		******%
Foundation Drawings		******%
Duct Support Steel Drawings		******%
Overall	******% for Revs	******% 2		$******3
Information provided by A - E Constructor

1 An example of what could be used during the detailed engineering design phase. Final list of deliverables TBD.

2 Yield calculation is: (number of rev 1 or higher issued - number issued due to Engineering Error) / (number of rev 1 or higher issued). This can be calculated on a drawing type basis (e.g. the yield for single line drawings), or overall for drawings within the fee criterial. It is proposed it be calculated for fee purposes on an overall basis.

3 $******x ******% x ******% = $******

Graph - (redacted plot lines)

- Quality Fee Earned

- % Fee Earned

- Percent of Revised Drawings Engineering Error Free

The following reason codes would be used to categorize reasons for drawing revisions of Revision 1 and higher. Only the first would impact

the yield calculation ("Significant Design Error or Deficiency")

> Significant Design Error or Deficiency (impacts design adequacy or contruction effort)

> Design Development/Planned Revision

> Construction Request / Contruction Preference

> Supplier Fabrication Error

> Supplier Request

> Client Request

> Approved Scope Change

> Other (Explain)

******%	Innovation	Phase 1 Innovation Items (Development Phase) 1	100% Fee Criteria	Actual	Fee Earned %	Fee Earned $
$******		Score Based on Survey Results

1 For Phase 1, it was agreed to include Innovation as one of the subjective assessment questions within the customer survey in lieu of specific items.

Note: Scorecards to be finalized during the Development Phase of the Project.

PAGE 2 OF 6

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EXHIBIT 5.1-2

SAMPLE SCORECARDS

Scorecard - Assessed on a Subproject by Subproject Basis

	Phase 2 Innovation Items (Post NTP) 1 2	100% Fee Criteria	Actual	Fee Earned %	Fee Earned $
******%	Schedule
	Reducd Enginering Critical Path Activity durations
******%	Modularization
	Optimize Shipping Configurations
******%	Constructability
	Underground Interference Targets (of zero)
******%	Six Sigma
	Improvement in Supplier Drawing Review Rate
	Reduction in Engineering JobHours
	Optimize Material Handling Interfaces with multiple users
	Reduction in SubProject Cost from Estimate
	Overall

1 To be established during Phase 1 based on stretch targets that impact TCC and schedule. Typical examples are provided.

2 The specific categories are less important than the actual fee item. For instance, Sigma can be used to help improve schedule, modularizatio, or constructability, as well as individual or overall cost components. Specific items should be established based on stretch targets set during development of TCC and schedule.

Graph (redacted plot lines)

- Innovation Fee Earned

- Percent of Fee Earned

- Percent of Target Dollars Saved

Interpolate Between Values Where Appropriate

Note: Scorecards to be finalized during the Development Phase of the Project.

PAGE 3 OF 6

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EXHIBIT 5.1 -2

SAMPLE SCORECARDS

Scorecard - Assessed on a Subproject by Subproject Basis

The comments below were made to address the need for better schedule definitions. Also the value of each schedule item should be weighted differently as it relate to the severity of it impact to subproject completion.

There should be a process to adjust the schedule as the work progresses. These adjustment would have to be jointly agreed to before the start of the activity.

Professional Construction Labor

POSSIBLE FEE: $******¹

Value						Activities on Schedule
******%	Schedule	Major Milestones and Key Activities 2	100% Fee Criteria	Actual	Fee Earned %	Fee Earned $
$******	******%	Subproject 1 and Common
		Place Srubber Foundation	15-Jul-05 3	2 days late
		Start Structural Steel Erection	15-Jul-05	3 days early
		Complete Vessel Erection	15-Jul-05	on time
		Start Raceway Installation	15-Jul-05	on time
		Complete Gas Path	15-Jul-05	2 days early
		Complete Fan Modifications	15-Jul-05	6 days late
		Complete Underground Ductbanks	15-Jul-05	on time
		Set Up Off Site Fabruication Yard	15-Jul-05	4 days late
		Start Vessel Ring Installation	15-Jul-05	2 days late
		Install DCS	15-Jul-05	3 days early
		Complete Stack	15-Jul-05	on time
		Energize 5 KV System	15-Jul-05	on time
		Complete Fan Mechanical Installation	15-Jul-05	1 day early
			Target is on time	5 days late	******%	$******4

1 For illustrative purposes only, we will use a potential fee for the reporting period of $******, to show how the actual fee is calculated.

2 These are representative milestones, as an example of Phase 1 deliverables. Actual critical milestones to be selected based on Engineering Phase 1 schedule.

3 Actual dates established based upon Engineering Phase 1 schedule

4 $******x ******% x ******% = $******

Graph - (redacted plot lines)

- Schedule Fee Earned

- Percent Fee Earned

- Calendar Days Late/Early

$******	******%	System Turnover Performance	100% Fee Criteria 1	Actual	Fee Earned %	Fee Earned $ 2
		Subproject 1	100% Fee equals Zero days variance. 150% Fee equals 20 days earlier variance. 50% Fee equals 20 days later variance.	5 Days Ahead	******%	$******
		Total

1 Fee is based on turning over subproject systems on time based on a cumulative count of days ahead or behind the scheduled turn over date.

2 $******x ******% x ******% = $******

Graph (redacted plot lines)

- Construction System Turnover Performance

- Percent of Fee Earned

- System Turnover Work Days

$******	******%	Outage Performance	100% Fee Criteria 1	Actual	Fee Earned %	Fee Earned $ 2
		Subproject 1	Fee equals Zero days variance. 150% Fee equals 10 days earlier variance. 50% Fee equals 10 days later variance.	5 Days Ahead	******%	$******

1 Fee is based on outage durations in subprojects based on a cumulative count of days ahead or behind the scheduled outage duration.

2 $******x ******% x ******% = $******

Graph (redacted plot lines)

- Outage Fee Earned

- Outage Fee

- Outage Days

Note: Scorecards to be finalized during the Development Phase of the Project.

PAGE 4 OF 6

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EXHIBIT 5.1-2

SAMPLE SCORECARDS

Scorecard - Assessed on a Subproject by Subproject Basis

******% Safety Any Fatality during any period will result in zero ($******) FEE payment for Safety for that Subproject.

			(******% of FEE)	(******% of FEE)	(******% of FEE)
$******	******%	OSHA Recordable Incident Rate	******	******	******	Actual Recordable
		Calculated using OSHA formula. This is on an annual basis for the duration of the project. Any lost Fee for an evaluation period can be recovered if the rate is reduced below the fee threshold during a later evaluation period. Fee is calculated on a sliding linear scale.

$******	******%	Lost Work Day Case Rate	******	******	******	Actual LWD
		Calculated using OSHA formula. This is on an annual basis for the duration of the project. Any lost Fee for an evaluation period can be recovered if the rate is reduced below the fee threshold during a later evaluation period. Fee is calculated on a sliding linear scale.

$******	******%	Up Stream Process Control	******	******	******	Actual Score
		Calculated using the percentage score of implementation of the attributes of the ES&H Core Processes from the Core Process CP-111 - Site Assessment Scorecard for the period. A site assessment will be performed on anannual basis or as agreed to by First Energy and Bechtel.

******%	OEM Oversight
$******		(Details to be finalized during the Development Phase)	100% Fee Criteria	Actual	Fee Earned %	Fee Earned $

Note: Scorecards to be finalized during the Development Phase of the Project.

PAGE 5 OF 6

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EXHIBIT 5.1-2

SAMPLE SCORECARDS

Scorecard - Assessed on a Subproject by Subproject Basis

******%	Quality
$******	******%
	_________		(******% of FEE)	(******% of FEE)	(******% of FEE)	Actual Rate	Fee Earned
	******%	Concrete Cylinders Passing 28 Day Compression Test Passing Cylinders versus total 28 Day Cylinders	******% Passing	******% Passing	******% Passing
	******%	Structural Steel Bolt Torque - Percentage of Bolts Torqued Correctly Number of structural steel bolts required to be re-torqued versus total installed	******%	******%	******%
	******%	Anchor Bolt Locations - Number of Bolts on Location based on as-built surveys Number of bolts reworked versus total bolts installed	******%	******%	******%
_________	******%	TBD	TBD	TBD	TBD
	******%	Correct Electrical Terminations Number Terminations Re-Terminated during Loop Check versus Total Electrical Terminations Installed	******%	******%	******%

Information provided by A - E Constructor

		(******% of FEE)	(******% of FEE)	(******% of FEE)	Actual Rate	Fee Earned
_________		> ******%	>****% and <****%	<******%
******%	Percent of Rework based on the number of hours charged to rework cost codes to correct a completed installation. The measurement is the manual rework hours charged versus total manual hours charged to the project. This is a cumulative number for the duration of the Subproject. Any lost fee for an evaluation period can be recovered if the number is reduced below the fee threshold during a later evaluation period.

Interpolate between values where appropriate.

******%	Project Administration		100% Fee Criteria	Actual	Fee Earned %	Fee Earned $
$******	******%	Responsiveness / Communications	******	******
	******%	Project Reporting	******	******
	******%	Subcontract Coordination; Need to discuss Plant Commun.	******	******
	******%	Work Sampling	******	******
	******%	Problem Resolution	******	******
		Overall	Target is ******	****** 1		$******

Information provided by FirstEnergy via customer survey

Project Administration (Customer Survey)

Based on a scale of:

1: Unsatisfactory (does not meet requirements)

2: Minimal (meets some of the requirements)

3: Adequate (meets most of the requirements)

4:Satisfactory (meets requirements)

5: Outstanding (exceeds requirements)

Information provided by A - E Constructor

1 Scale is based on the scoring suggested to the left of this comment. Actual questions to be established during team building, based on sample to be provided by FirstEnergy.

Graph - (redacted plot lines)

- Responsiveness Fee Earned

- Percent Fee

- Responsiveness Rating

******%	Cashflow	Projected semi-annually, based on Target Construction Cost	(******% of FEE)	(******% of FEE)	(******% of FEE)	Actual Rate	Fee Earned
$******		Price establishment, on subproject basis.
		Accuracy of Cashflow Projection, based on all Subproject Costs	+/- ******%	+/- ******%	+/- ******%
		The above accuracy calculations are with respect to the previous year's one year forecast of cash flow.

Note: Scorecards to be finalized during the Development Phase of the Project.

PAGE 6 OF 6

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EXHIBIT 5.1-3

FEE TABLE

The Fee associated with the Target Construction Cost will be adjusted according to the table below:

 Actual CostWrap Arrangement Fee AdjustmentFE Vendor Arrangement Fee Adjustment

(% of Target Construction Cost)(% of Target Construction Cost)(% of Target Construction Cost)

  [*****%][*****%][*****%]

  [*****%][*****%]                                  & #160;       [*****%]

[*****%]                                                         [*****%]                                                                      [*****%]

                                        [*****%]                                                         [*****%]                                                                     [*****%]

                                        [*****%]                                                         [*****%]                                                                     [*****%]

                                        [*****%]                                                         [*****%]              0;     [*****%]

                                        [*****%]                                                         [*****%]                                                                       [*****%]

                                        [*****%]                                                         [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                      [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

Dead Band                       [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

                                        [*****%]                                                          [*****%]                                                                       [*****%]

The maximum [*****] adjustment is equal to the original Target Construction Cost Fee.

Values on the table shall be interpolated for actual costs between those shown on the table.

Page 1 of 1

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EXECUTION COPY

EXHIBIT 5.1-4

SAMPLE INVOICES

FIRSTENERGY SAMPLE INVOICES SCHEDULES

PAGE #	Explanation of Schedules:
0	Made up a "Statement of Cost 0" for example purposes, so there would be a (over)/under to reflect on AFR604xxxA.
1	Invoices ending with the letter "A" are reconciled to the prior month. Any over/under is adjusted on this invoice PLUS any bills received in the current month. This invoice requests *******% of the forecast funds for the following month . "A" invoices request funds by the ******th of the same month. In this "sample" invoice 25XXX-AFR604xxxA is a cumulative invoice for the first 9 invoices. The (Over)/Under recovery is from STMT of Cost 0, added this issue, for example purposes. FEE has been separated for forecast.
2	Invoices ending with the letter "B" are the balance of the forecast ******% of future cost. "B" invoices request funds by the ******th of the following month. FEE has been separated for forecast.
3A	This is a Statement of Cost & is not a request for funds. This invoice trues up actual cost with funds received on Invoices "A" and "B" of $******, reflecting the under-recovery of $****** on the A invoice. This is an invoice summarization of pages 3B, 3C, 3D, 3E, 3F & 3G.
3B	Summary of Direct & Indirect Expenses by category, and ties back to 3A.
3C	Summary (Sample) of Professional Labor Abstract, support to 3B
3D	Summary (Sample) of Professional Construction Labor Abstract, support to 3B
3E	Summary (Sample) of Specialist Labor Abstract, support to 3B
3F	Summary (Sample) of Craft Labor Abstract, support to 3B
3G	Summary (Sample) of Other Direct Cost Abstract, support to 3B
4	Invoices ending with the letter "A" are reconciled to the prior month. Any over/under is adjusted on this invoice. This invoice requests ******% of the forecast funds for the following month . "A" invoices request funds by the ******th of the same month. In this "sample" invoice 25XXX-AFR605xxxA is a cumulative invoice for the first 10 invoices. The (Over)/Under recovery of $******is on the A invoice.
5	Invoices ending with the letter "B" are the balance of the forecast ******% of future cost. "B" invoices request funds by the ******th of the following month. This requests the remaining balance of forecast cost for month 11 of $******.

Example shown on all sheets is for "FE Vendor Arrangement"

PAGE 1

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EXECUTION COPY

EXHIBIT 5.1 -4

BECHTEL POWER CORPORATION

5275 WESTVIEW DRIVE

FREDERICK, MD 21703

NEW THIS ISSUE TO REFLECT "PREVIOUS MONTH" STMT OF COST (OVER)/UNDER RECOVERY

TO: FIRSTENERGY GENERATION CORP.

ATTN: RAYMOND REINHART

76 SOUTH MAIN STREET

AKRON, OH 44308

INVOICE NUMBER	DATE	JOB NUMBER		CONTRACT	ACCOUNT
25XXX-XXXxxx	4/10/2006		25XXX	X

STATEMENT OF COST through MARCH 2006 for the Sammis Project.

COST DESCRIPTION
UNIT RATE LABOR, Engineering/Graphics Labor & other Professional Labor	$	******
UNIT RATE LABOR, Professional Construction Labor		******
UNIT RATE LABOR, Specialist		******
CRAFT LABOR		******
MATERIALS & OTHER COST		******
SUB-TOTAL STATEMENT OF COST THROUGH MARCH 2006:	$	******
FEE:		******
TOTAL STATEMENT OF COST & FEE:	$	******
FUNDING PREVIOUSLY RECEIVED, INVOICE AFR603XXXA&B:		******
(OVER)/UNDER RECOVERY:	$	******

THIS IS A STATEMENT OF COST. DO NOT PAY.

PAGE 0

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EXECUTION COPY

EXHIBIT 5.1-4

BECHTEL POWER CORPORATION

5275 WESTVIEW DRIVE

FREDERICK, MD 21703

TO:	FIRSTENERGY GENERATION CORP.	Please wire transfer to:
	ATTN: RAYMOND REINHART	The Bank of New York
	76 SOUTH MAIN STREET	New York, NY
	AKRON, OH 44308	Account # ******
		ABA # ******
		Credit: BECHTEL POWER CORPORATION
		Job Number: ******
		INVOICE #	25XXX-AFR604xxxA

INVOICE NUMBER	DATE	JOB NUMBER	CONTRACT	ACCOUNT
25XXX-AFR604xxxA	4/10/2006	25XXX	X	******

Funds request for the Sammis Project.

Payment due by APRIL 25, 2006.

	Current Month
FORECAST FOR ******% of MONTH #10 EXPENSES:	$	******
FEE FORECAST ON HOME OFFICE:		******
TOTAL AMOUNT DUE	$	******
(OVER)/UNDER RECOVERY FROM MARCH STMT OF COST:		******
TOTAL AMOUNT DUE	$	******

	Inception to Date
BALANCE FORWARD INVOICES (MONTH 1 - 9)	$	XXX
BILLED THIS INVOICE		******
CUMULATIVE INVOICED TO DATE:	$	XXX

(***) Value is prior month's one through 9 activity, billed and reconciled on prior month's statement of cost.

PAGE 1

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EXECUTION COPY

EXHIBIT 5.1-4

BECHTEL POWER CORPORATION

5275 WESTVIEW DRIVE

FREDERICK, MD 21703

TO:	FIRSTENERGY GENERATION CORP.	Please wire transfer to:
	ATTN: RAYMOND REINHART	The Bank of New York
	76 SOUTH MAIN STREET	New York, NY
	AKRON, OH 44308	Account # ******
		ABA # ******
		Credit: BECHTEL POWER CORPORATION
		Job Number: ******
		INVOICE #	25XXX-AFR604xxxB

INVOICE NUMBER	DATE	JOB NUMBER	CONTRACT	ACCOUNT
25XXX-AFR604xxxB	4/10/2006	25XXX	X	******

Funds request for the Sammis Project.

Payment due by MAY 25, 2006.

FORECAST FOR ******% of MONTH #10 EXPENSES:	$	******
FEE FORECAST ON HOME OFFICE:		******
TOTAL AMOUNT DUE	$	******

	Inception to Date
BALANCE FORWARD INVOICES (MONTH 1 - 9)	$	XXX
BILLED THIS INVOICE		******
CUMULATIVE INVOICED TO DATE:	$	XXX

PAGE 2

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EXECUTION COPY

EXHIBIT 5.1-4

BECHTEL POWER CORPORATION

5275 WESTVIEW DRIVE

FREDERICK, MD 21703

TO: FIRSTENERGY GENERATION CORP.

ATTN: RAYMOND REINHART

76 SOUTH MAIN STREET

AKRON, OH 44308

INVOICE NUMBER	DATE	JOB NUMBER		CONTRACT	ACCOUNT
25XXX-XXXxxx	5/10/2006		25XXX	X

STATEMENT OF COST through APRIL 2006 for the Sammis Project.

COST DESCRIPTION

UNIT RATE LABOR, Engineering/Graphics Labor & other Professional Labor	$	******
UNIT RATE LABOR, Specialist		******
UNIT RATE LABOR, Professional Construction Labor		******
CRAFT LABOR		******
MATERIALS & OTHER COST		******
SUB-TOTAL STATEMENT OF COST THROUGH APRIL 2006:	$	******
FEE:		******
TOTAL STATEMENT OF COST & FEE:	$	******
FUNDING PREVIOUSLY RECEIVED, INVOICE AFR604XXXA&B:		******
(OVER)/UNDER RECOVERY:	$	******

THIS IS A STATEMENT OF COST. DO NOT PAY.

PAGE 3A

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EXECUTION COPY

EXHIBIT 5.1-4

SCHEDULE OF DIRECT & INDIRECT EXPENSES

OFFICE:	1A	SAMMIS PROJECT
COMPANY:	E8	BECHTEL POWER CORP
SECTION:	0B		INV NO:	25XXX-XXXXXX

April, 2006
DESCRIPTION	HOURS		AMOUNT		FEE		TOTAL
ENGINEERING, GRAPHICS, OTHER PROFESSIONAL AND SPECIALIST LABOR
UNIT RATE LABOR, Engineering/Graphics Labor & other Professional Labor		******	$	******			$	******
G&A @ ******% for Home office cost:				******				******
Fee on Engineering Labor and G&A @ ******%:						******		******
				******				******
			$	******	$	******	$	******
UNIT RATE LABOR, Specialist		******	$	******			$	******
G&A @ ******% for Home office cost				******				******
Fee on Specialist Labor and G&A @ ******%:						******		******
Engineering Technology Charge @ $******/ hr.				******				******
			$	******	$	******	$	******
SUB-TOTAL PROFESSIONAL COST LABOR AND FEE		******	$	******	$	******	$	******

PERCENT COMPLETE

HOURS

AMOUNT

FEE

TARGET CONSTRUCTION COST

UNIT RATE LABOR, Professional Construction Labor

******

$

******

G&A @ ******% for Field NonManual cost:

******

Engineering Technology Charge @ $******/ hr.

******

$

******

CRAFT LABOR

******

$

******

TRAVEL ORDINARY BUSINESS

$

******

SUBCONTRACTS

******

MATERIALS

******

FREIGHT

******

ENGINEERING SUBCONTRACT

******

EQUIPMENT RENTAL

******

MATERIALS & OTHER COST

$

******

SUB-TOTAL BECHTEL TARGET CONSTRUCTION COSTS

******

$

******

TARGET CONSTRUCTION COST

$

******

TCC FEE

$

******

******

%

$

******

TOTAL BECHTEL COSTS AND TAX ( WITH FEE):

$

******

TOTAL APRIL, 20056			$	******	$	******	$	******
TCC FEE TO DATE
FEE @ $ ******
Prior Invoices	******	%			$	******
Current Invoice (April 2006)	******	%			$	******
Cumulative	******	%			$	******

PAGE 3B

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EXECUTION COPY

EXHIBIT 5.1-4

FirstEnergy - Job 25xxx

Engineering, Graphics and Other Professiional Labor

P/E 04/24/06

Org Code	Employee Number		Name	SubJob		Cost Code	Activity	ST Hours		OT Hours		Grade		ST Rate		OT Rate		Dollars
CNC-XXXX		111111	Employee		XXX				160				21	$	******			$	******
CNC-XXXX		111112	Employee		XXX				160				21	$	******			$	******
CNC-XXXX		111113	Employee		XXX				160				22	$	******			$	******
CNC-XXXX		111114	Employee		XXX				160				22	$	******			$	******
CNC-XXXX		111115	Employee		XXX				160				23	$	******			$	******
CNC-XXXX		111116	Employee		XXX				160				23	$	******			$	******
CNC-XXXX		111117	Employee		XXX				160		20		24	$	******	$	******	$	******
CNC-XXXX		111118	Employee		XXX				160				24	$	******			$	******
CNC-XXXX		111119	Employee		XXX				160				24	$	******			$	******
CNC-XXXX		111120	Employee		XXX				160				24	$	******			$	******
CNC-XXXX		111121	Employee		XXX				160		20		25	$	******	$	******	$	******
CNC-XXXX		111122	Employee		XXX				160				25	$	******			$	******
CNC-XXXX		111123	Employee		XXX				160				25	$	******			$	******
CNC-XXXX		111124	Employee		XXX				160				25	$	******			$	******
CNC-XXXX		111125	Employee		XXX				160				25	$	******			$	******
CNC-XXXX		111126	Employee		XXX				160		40		26	$	******	$	******	$	******
CNC-XXXX		111127	Employee		XXX				160				26	$	******			$	******
CNC-XXXX		111128	Employee		XXX				160				26	$	******			$	******
CNC-XXXX		111129	Employee		XXX				160				26	$	******			$	******
CNC-XXXX		111130	Employee		XXX				160				27	$	******			$	******
CNC-XXXX		111131	Employee		XXX				160				27	$	******			$	******
CNC-XXXX		111132	Employee		XXX				160				27	$	******			$	******
CNC-XXXX		111133	Employee		XXX				160				28	$	******			$	******
CNC-XXXX		111134	Employee		XXX				160				28	$	******			$	******
CNC-XXXX		111135	Employee		XXX				160				28	$	******			$	******
CNC-XXXX		111136	Employee		XXX				160				29	$	******			$	******
CNC-XXXX		111137	Employee		XXX				160				29	$	******			$	******

SUBTOTAL LABOR	4,320	80	$	******
G&A @ ******% for Home Office Labor Cost				******
SUBTOTALS			$	******
Fee on Engineering @ ******% (Labor and G&A)				******
Engineering Technology Charge @ $******/Hour				******
TOTALS			$	******

PAGE 3C

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EXECUTION COPY

EXHIBIT 5.1-4

FirstEnergy - Job 25xxx

Professional Construction Labor

P/E 04/25/06

Org Code	Employee Number								OT Rate	Dollars
CNC-XXXX		111138	Employee	XXX	160	Letter	$	******		$	******
CNC-XXXX		111139	Employee	XXX	160	21	$	******		$	******
CNC-XXXX		111140	Employee	XXX	160	22	$	******		$	******
CNC-XXXX		111141	Employee	XXX	160	22	$	******		$	******
CNC-XXXX		111142	Employee	XXX	160	23	$	******		$	******
CNC-XXXX		111143	Employee	XXX	160	23	$	******		$	******
CNC-XXXX		111144	Employee	XXX	160	24	$	******		$	******
CNC-XXXX		111145	Employee	XXX	160	24	$	******		$	******
CNC-XXXX		111146	Employee	XXX	160	25	$	******		$	******
CNC-XXXX		111147	Employee	XXX	160	25	$	******		$	******
CNC-XXXX		111148	Employee	XXX	160	25	$	******		$	******
CNC-XXXX		111149	Employee	XXX	160	26	$	******		$	******
CNC-XXXX		111150	Employee	XXX	160	26	$	******		$	******
CNC-XXXX		111151	Employee	XXX	160	26	$	******		$	******
CNC-XXXX		111152	Employee	XXX	160	27	$	******		$	******
CNC-XXXX		111153	Employee	XXX	160	27	$	******		$	******
CNC-XXXX		111154	Employee	XXX	160	28	$	******		$	******
CNC-XXXX		111155	Employee	XXX	160	28	$	******		$	******
CNC-XXXX		111156	Employee	XXX	160	29	$	******		$	******
			SUBTOTALS		3,040					$	******
			G&A @ ******% for Professional Construction Labor Cost								******
			SUBTOTALS							$	******
			Engineering Technology Charge @ $******/Hour								******
										$	******

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EXHIBIT 5.1-4

Org Code

Employee Number

Name

SubJob

Cost Code

Activity

ST Hours

OT Hours

Grade

ST Rate

OT Rate

Dollars

CNC-XXXX

111157

Employee

XXX

160

27

$

******

$

******

CNC-XXXX

111158

Employee

XXX

160

28

$

******

$

******

CNC-XXXX

111159

Employee

XXX

160

29

$

******

$

******

SUBTOTAL

480

$

******

G&A @ ******% for Specialist Labor Cost

******

SUBTOTALS

$

******

Fee on Specialist @ ******% (Labor and G&A)

******

Engineering Technology Charge @ $******/Hour

******

TOTALS

$

******

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EXHIBIT 5.1-4

CRAFT LABOR

BECHTEL POWER CORPORATION

CRAFT LABOR

Pay ID Key

ST = Straight Time

OT = Overtime

DT = Double Time

MM = Meal Allowance

JU = Jury Duty

Job	25XXX-XXX
Week Ending	4/24/2006
WBS Code	(All)

Craft Description	Pay ID		Shift		Hours		Bare Labor		Employer Fringes		Insurance & Taxes		Total Dollars
BOILERMAKERS					5,000.0		******		******		******		******
@ $******/hr		ST		1		5,000.0		******		******		******		******
		OT		1		-		-		-		-		-
		DT		1		-		-		-		-		-
PIPEFITTER						5,000.0		******		******		******		******
@ ******/hr		ST		1		5,000.0		******		******		******		******
		OT		1		-		-		-		-		-
		DT		1		-		-		-		-		-
ELECTRICIANS						5,000.0		******		******		******		******
@ ******/hr		ST		1		5,000.0		******		******		******		******
		OT		1		-		-		-		-		-
		DT		1		-		-		-		-		-
Total Craft						15,000.0		******		******		******	$	******
					Overhead (Rate is $******/hour, not a percentage)									******
					Small Tools @ $******/hour									******
					Consumables @ $******/hour									******
					SUBTOTAL								$	******
					TOTALS									******

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DETAIL SCHEDULE OF CHARGES

OTHER DIRECT COSTS

OFFICE:	1A
COMPANY:	E8	JOB-SUB:	25XXX-XXX
REGION:	CN	INV NO:	XXXXX-XXXXXX
SECTION:	0B

SOURCE

MONTH

SOURCE

PERFORM

NAT

REFERENCE

CYCLE

DATE

OFC

CO

REG

CLS

DESCRIPTION

COST

049591852 008430568

0402

4/4/2005

1W

E8

8N

660

TRAVEL, EMPLOYEE 1

$

******

049591853 008430569

0402

4/8/2005

1W

E8

8N

830

CONSTRUCTION SUBCONTRACTOR

******

049591852 008430569

0402

4/6/2005

1W

E8

8N

310

CONSTRUCTION MATERIALS & SUPPLIES

******

049591853 008430570

0402

4/15/2005

1W

E8

8N

321

FREIGHT FORWARDING SERVICES

******

049591853 008430571

0402

4/26/2005

1W

E8

8N

870

ENGINEERING SUBCONTRACT

******

049591852 008430570

0402

4/28/2005

1W

E8

8N

422

AUTOMOTIVE & CONSTRUCTION EQUIPMENT

******

Truck, Pickup, 1/2 ton 4x2 GAS @ $******

Dump Truck, 13/15 CY Diesel @ $******

Crane, Crawler, 100T Diesel @ $******

Welder, 400 amp Diesel, TRL. MTD. Diesel @ $******

Welder, 200 amp ELEC. 8 Station @ $******

TOTAL MATERIAL

$

******

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EXHIBIT 5.1-4

BECHTEL POWER CORPORATION

5275 WESTVIEW DRIVE

FREDERICK, MD 21703

TO:	FIRSTENERGY GENERATION CORP.	Please wire transfer to:
	ATTN: RAYMOND REINHART	The Bank of New York
	76 SOUTH MAIN STREET	New York, NY
	AKRON, OH 44308	Account # ******
		ABA # ******
		Credit: BECHTEL POWER CORPORATION
		Job Number: 25XXX
		INVOICE #	25XXX-AFR604xxxA

INVOICE NUMBER	DATE	JOB NUMBER	CONTRACT	ACCOUNT
25XXX-AFR604xxxA	5/10/2006	25XXX	X	******

Funds request for the Sammis Project.

Payment due by MAY 25, 2006.

	Current Month
FORECAST FOR ******% of MONTH #11 EXPENSES:	$	******
FEE FORECAST ON HOME OFFICE:		******
TOTAL AMOUNT DUE	$	******
(OVER)/UNDER RECOVERY FROM APRIL STMT OF COST	$	******
TOTAL AMOUNT DUE	$	******

	Inception to Date
BALANCE FORWARD INVOICES (MONTH 1 - 10)	$	XXX
BILLED THIS INVOICE		******
CUMULATIVE INVOICED TO DATE:	$	XXX

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EXHIBIT 5.1-4

BECHTEL POWER CORPORATION

5275 WESTVIEW DRIVE

FREDERICK, MD 21703

TO:	FIRSTENERGY GENERATION CORP.	Please wire transfer to:
	ATTN: RAYMOND REINHART	The Bank of New York
	76 SOUTH MAIN STREET	New York, NY
	AKRON, OH 44308	Account # ******
		ABA # ******
		Credit: BECHTEL POWER CORPORATION
		Job Number: 25XXX
		INVOICE #	25XXX-AFR604xxxB

INVOICE NUMBER	DATE	JOB NUMBER	CONTRACT	ACCOUNT
25XXX-AFR604xxxB	5/10/2006	25XXX	X	******

Funds request for the Sammis Project.

Payment due by JUNE 25, 2006.

FORECAST FOR ******% of MONTH #11 EXPENSES:	$	******
FEE FORECAST ON HOME OFFICE:		******
TOTAL AMOUNT DUE	$	******

	Inception to Date
BALANCE FORWARD INVOICES (MONTH 1 - 10)	$	XXX
BILLED THIS INVOICE		******
CUMULATIVE INVOICED TO DATE:	$	XXX

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EXHIBIT 5.1-5

U.S. NATIONAL TEMPORARY/SHORT TERM ASSIGNMENT CONDITIONS TO A

PROJECT LOCATION

These assignment conditions apply to temporary assignments to a project location which is more than 50 miles from their current U.S. residence. Temporary assignments are defined as assignments expected to be more than ******months but not more than ******months. If these conditions are silent, the Manual of Personnel Policies - U.S. will prevail.

1.0 SHIPMENT/STORAGE OF HOUSEHOLD EFFECTS

a)For assignments of ****** months or less:

  No shipment or storage of household effects is authorized.

b)For assignments longer than ****** months:

1. Single status employees are authorized shipment, including packing, crating and unpacking.

2. Family status employees are authorized shipment, including packing, crating and unpacking.

c)  For assignments longer than****** months:

In addition to the shipment allowances, the cost of storage will be reimbursed. The combined weights of shipment and storage are not to exceed the    maximums, including packing, crating and unpacking.

d)   Storage in Transit:

It is recommended that employees who have a minimal amount of personal household effects (e.g. 200 lbs. or less) ship their goods via UPS or Class “C” air freight when possible to avoid the 1,000 lbs. minimum charge imposed by professional moving companies. Employees with applicable receipts will be reimbursed by expense report.

2.0SHIPMENT OF AUTOMOBILE

a) No automobile shipment costs are reimbursed for assignments of ****** months or less. For assignments of more than 3 months, costs for shipment of an auto will be reimbursed, provided the assigned location is more than ****** miles from point of departure.

b) For family status assignments, if an automobile is shipped, costs for a second automobile driven to the location will be reimbursed at the second auto ratevia the most direct route.

c) No reimbursement will be made for storage charges.

d) Reimbursement for the cost of transporting vehicles to and from terminal facilities is authorized when the terminal facility is greater than ****** miles to the work location.

3.0EN ROUTE EXPENSES

a) Transportation via public carrier will be reimbursed up to the equivalent of least cost economy air fare plus actual and reasonable expenses to and from the terminal. One travel day is authorized.

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EXHIBIT 5.1-5

b) For single status assignments when an automobile is not shipped, mileage costs via the most direct route will be reimbursed. No reimbursement will be provided for a second automobile.

c) For family status assignments, mileage costs via the most direct route will be reimbursed for the first auto and for the second if applicable.

d)   Whether single or family status, tolls will be reimbursed in addition to the mileage.

e) Actual and reasonable lodging costs, plus a daily allowance for actual meals and incidentals will be reimbursed. Meals and incidentals include food, laundry, and phone calls. Reporting a flat rate is unacceptable.

f) For those employees who drive to the new assignment location, the number of authorized travel days will be determined based upon traveling 500 miles the first day and 350 miles for each day thereafter via the most direct route.

4.0AUTOMOBILE RENTAL

Actual and reasonable rental costs, excluding mileage, gasoline and insurance, will be reimbursed while awaiting the arrival of a shipped automobile. Insurance coverage is automatically provided when the rental is through a Contractor rental car company account.

5.0EXPENSES AT TEMPORARY LOCATION

a) For assignments of ****** months or less:

Actual and reasonable itemized lodging costs will be reimbursed. Meals and incidental expenses will be reimbursed for employee only.

Meals and incidentals include food, laundry and personal phone calls. Reporting a flat rate is unacceptable. The actual daily meals and incidentals cost may be above or below the daily rate, however, the total cost for the reported period (not to exceed ****** months) must not exceed the sum of the reported expense days times the daily rate.

b) For assignments longer than ****** months:

1) Actual and reasonable lodging costs, plus a daily allowance for meals and incidentals will be reimbursed for the first ****** days or until long term lodging is obtained, whichever occurs first.

2) Employees who are transferring from one temporary assignment to a subsequent temporary assignment may be authorized to use up to ****** of the ******days of settling-in at the pre-transfer location.

3) After the settling-in period, a per diem will be provided for employee only; receipts not required. Lodging includes lodging, furniture rental, utility hook-up/installation and basic monthly service costs. Meals and incidentals include meals, laundry, phone calls, and cable TV installation and basic monthly service charge.

4) Interruption of Per Diem: During the per diem period, the meals and incidentals portion is forfeited in the following circumstances:

·Saturday and Sunday of a scheduled monthly trip home

·When PTO is taken in excess of two consecutive workdays for reasons other than illness.

·When PTO is taken for more than two consecutive days in conjunction with a weekend (e.g., Thursday, Friday, Weekend, Monday).

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EXHIBIT 5.1-5

5) The per diem is reduced by the meals and incidentals portion whenever the employee is away from the assignment location in connection with reimbursed business travel, monthly trips home, PTO other than illness, and other absences.

6.0VISITS HOME

a) Employees on single status assignments of three months or more are authorized trips home, provided that a minimum of ******days remain in the assignment. Transportation will be reimbursed up to the least cost of ******-day advanced purchase economy airfare plus reasonable expenses to and from airport. Receipts must be furnished.

If an employee elects to travel to a location other than his/her home base, the maximum reimbursement allowed will be the actual or equivalent cost of the round trip airfare from the temporary assignment location to the employee's home base, whichever is lower. The purpose of these trips is to reunite families or conduct personal business that a temporary assignment might prohibit. If an alternate location is selected, it must be noted on the PAN prior to the assignment start date and must have a Category II approval. Receipts must be furnished.

b) Spouse/Registered Domestic Partner/Family Visit - In lieu of the employee’s trip home, reimbursement for round trip airfare to the temporary assignment location only may be granted to the employee’s spouse or registered domestic partner, and/or children up to the amount equal to one adult economy class 14-day advanced purchase round trip airfare. Other costs such as transportation to and from airports and motels or meal expenses for the family member will not be reimbursed. The employee’s next authorized trip home will be four weeks after family member has returned home. Any expenses reimbursed under this alternative will be considered taxable income.

7.0HOLIDAY SCHEDULE

a)The following holidays are observed:

New Year’s Day

Martin Luther King Day

President’s Day

Memorial Day

Independence Day

Labor Day

Thanksgiving Day

Day after Thanksgiving

Christmas Day

b) When an approved holiday falls on Saturday, the preceding Friday will be recognized as a holiday. When an approved holiday falls on Sunday, the following Monday will be recognized as a holiday. Employees must be in a salaried status to be eligible for paid holidays.

8.0LEASE CANCELLATION

Employees on temporary assignments are expected to negotiate short-term leases or leases containing cancellation clauses. Reimbursement for unrecoverable costs due to rental lease termination may be made with Category II approval when such costs result from an unexpected reduction in the assignment period. Maximum reimbursement for lease cancellation is the equivalent of two months rent plus security deposit.

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EXHIBIT 5.1-5

9.0TAXES

Tax information, including an Employee Tax Statement, is to be provided to employees prior to going on temporary assignments.

10.0CONVERSION FROM TEMPORARY TO PERMANENT STATUS

a)Employees whose assignments change from temporary to permanent status at the same location will be reimbursed for relocation costs on an itemized basis only.

b)Employees are normally authorized a trip to home base if family or residence is being maintained at home base; three day settling-out expenses may be authorized, usually scheduled around a weekend; rental car may be authorized for up to three days, excluding gas, and additional insurance, plus mileage reimbursement to and from home and airport terminal; parking at the airport will be authorized for the duration of the settling-out period.

c)Settling-in is not normally authorized.

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EXHIBIT 5.1-5

U.S. NATIONAL LONG TERM ASSIGNMENT CONDITIONS TO A

PROJECT LOCATION

These assignment conditions apply to long-term assignments to a U.S. project location. Long-term assignments are defined as assignments of more than 12 months, and the assignment location does not become the employee’s point of origin. If these conditions are silent, the Manual of Personnel Policies - U.S. will prevail. These conditions apply to transfers, new/rehires and college hires; however, they do not apply to employees undertaking international assignments in the U.S.A. For more details on the specific policies/allowances, contact your Human Resources Representative. These conditions may or may not be applicable to BSII - check with BSII HR prior to applying these conditions.

1.0HOUSE HUNTING TRIPS

a.) House hunting trips may be authorized for employees and their spouses or registered domestic partners provided the objective is to purchase a home. This allowance is not available to employees already resident in the area.

b.) Transportation via public carrier will be reimbursed up to the equivalent of least cost economy air fare plus actual and reasonable expenses to and from the terminal.

c.) If a private automobile is used, mileage costs via the most direct route will be reimbursed.

d.) Actual and reasonable lodging costs, plus a daily allowance for actual meals and incidentals will be reimbursed for a maximum period of ****** days, which is to include a weekend.

e.) Car rental (compact size with Bechtel discount excluding gas and mileage), airport parking, sitter for small children and other justifiable expenses will be reimbursed.

2.0SHIPMENT/STORAGE OF HOUSEHOLD EFFECTS

a.) Costs for shipment and storage, not to exceed the stated maximums include packing, crating and unpacking. Storage in-transit is authorized.

b.) Storage at point of departure is authorized.

3.0SHIPMENT OF AUTOS, HOUSE TRAILERS & MOBILE HOMES

a.) Costs for shipment by freight forwarder of an auto for new/re-hires or college hires and for transferring employees will be reimbursed as follows:

1.) Vehicles must be in operating condition.

2.) Assignment location must be more than ****** miles from point of departure.

3.) No reimbursement will be made for storage charges at point of origin, departure or destination locations.

4.) Reimbursement will be made for the cost of transporting vehicles to and from terminal facilities.

b.) Shipment by a licensed commercial carrier and where allowed by state law, of a single-unit house trailer or mobile home to a maximum size of 14 feet by 70 feet and used as the principal residence is authorized. The employee is responsible for the provision of insurance.

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EXHIBIT 5.1-5

4.0EN ROUTE EXPENSES

a.) Transportation via public carrier will be reimbursed up to the equivalent of least cost economy air fare plus actual and reasonable expenses to and from the terminal. One travel day is authorized.

b.) If a private automobile is used, mileage costs via the most direct route will be reimbursed for the first auto and second auto (if applicable). The second auto rate also applies when one auto is shipped and a second is driven. For a private auto used to tow a house trailer or for a mobile home, the mileage costs via the most direct route will be reimbursed. Tolls will be reimbursed in addition to the mileage rate. The number of authorized travel days for which expenses will be reimbursed is determined based upon the approved mileage from authorized point of departure to new assignment location as follows:

                                                                      Approved MileageAuthorized Travel Days

                      ******miles                                  ****** day

                     ******miles                                   ****** days

                     ******miles                                   ****** days

                     ******miles                                   ****** days

                     ******miles                                   ****** days

                     ******miles                                   ****** days

                    ******                                            ****** days

c.) Actual and reasonable lodging costs, plus a daily allowance for actual meals and incidentals will be reimbursed.

d.) Meals and incidentals include food, laundry, and phone calls.

5.0SETTLING-IN ALLOWANCES

a.) The maximum reimbursement period is ****** days. Up to ****** days (expenses only) may be used at the pre-departure location. Dependents must arrive within ****** months of the employee’s date of arrival to qualify for reimbursement.

b.) Actual and reasonable lodging costs, plus a daily allowance for actual meals and incidentals will be reimbursed. Meals and incidentals include food, laundry, and phone calls.

c.) Alternative (Transfers Only)

As an alternative to settling-in on an itemized basis, transferring employees may elect a lump sum settling-in amount (subject to taxes; no tax reimbursement). This option is not applicable when returning to point of origin or when converting from temporary to long-term at the same location. New hires and College hires are not eligible for this alternative allowance.

6.0AUTOMOBILE RENTAL

a.) Actual and reasonable rental costs, excluding mileage, gasoline and insurance, will be reimbursed while awaiting the arrival of a shipped automobile. Insurance coverage is automatically provided when the rental is through a Bechtel rental car company account.

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EXHIBIT 5.1-5

7.0RESIDENCE RELOCATION ASSISTANCE

a.) A lump sum residence relocation allowance is authorized for employees. The allowance is intended to assist employees with the incidental costs incurred in relocation. This payment is subject to federal, state and local taxes. Bechtel will provide tax assistance. See Section 11.0.

b.) A retiring employee returning to point of origin is not eligible for this allowance.

8.0REAL ESTATE COMMISSION EXPENSE

This allowance does not normally apply to long-term assignments of less than three years. However, for assignments of ****** months or longer, this allowance may be made available with the approval of the Business Unit/Region/CentralFunction/Service Manager to employees permanently transferring between two locations which have been identified as “long term” locations, but which are not permanent offices. For more details, contact your Human Resources Representative.

9.0DUPLICATE HOMEOWNER EXPENSE

a.) Duplicate housing costs for a pre-transfer residence, which is being offered for sale, will be reimbursed.

b.) Reimbursable receipted expenditures include: interest on mortgage, taxes, insurance, and mandatory expenses such as maintenance fees and homeowners association dues, where such fees and dues are a condition of ownership of the property. Expense Reports typically include the following documentation:

1.) A copy of the amortization schedule or monthly slip from the lending financial institution delineating the principal, interest, insurance, taxes and other mandatory expenses, if applicable.

2.) A copy of the canceled checks or receipts for expenses for both residences.

3.) A copy of the agreement with the real estate company. (Proof of previous residence being offered for sale.)

4.) Rental documentation or closing statement for the new residence (properly signed).

c.) New hires/re-hires and college hires and transferring employees who maintain pre-transfer residences that are being offered for sale and incur duplicate housing costs are eligible for certain receipted expenses. Employees who are attempting to rent their pre-transfer residence are not eligible.

10.0TAX ASSISTANCE

Transferring employees, new employees and college hires who are placed on long-term assignments at a location in the United States, which is more than ****** miles from their current U.S. residence, are eligible for reimbursement of certain relocation expenses. Contractor will provide employees tax assistance reimbursements to offset taxes withheld on relocation expenses. The reimbursement payment will be based upon standard reimbursement rates and, therefore, will not be an exact match of actual taxes withheld.

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EXHIBIT 5.1-5

11.0HOLIDAY SCHEDULE

a)The following holidays are observed:

New Year’s Day

Martin Luther King, Jr.’s Birthday

President’s Day

Memorial Day

Independence Day

Labor Day

Thanksgiving Day

Day after Thanksgiving

Christmas Day

b) When an approved holiday falls on Saturday, the preceding Friday will be recognized as a holiday. Employees must be in a salaried status to be eligible for paid holidays.

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EXHIBIT 5.1-6

CONSTITUENTS OF G&A (OVERHEAD) COSTS

The G & A and overhead allocation includes the cost for:

Costs for [*****] at Bechtel Fossil Power ([*****], Bechtel Fossil Power) and above, including cost for the Bechtel corporate and fossil business unit overhead allocated to Bechtel Power Corporation, including their respective costs for:

·   Furniture and equipment rental, lease, purchase, depreciation, and operating expenses

·   Office facility charges

·   Telephone, telegraph, cable, and facsimile

·   Mail and courier services

·   Reproduction services and supplies

·   Communications and communications equipment

·   Travel and temporary living expenses

·   Corporate licenses

·   Computer services (hardware and software, including computer-aided design [CAD])

·   Automation (local and wide area network, maintenance, and support)

Page 1 of 1

EXECUTION COPY

EXHIBIT 5.1-7

CONSTITUENTS OF ENGINEERING TECHNOLOGY CHARGE

For Contractor HOME OFFICE:

Contractor includes the following items in the Engineering Technology Charge rates quoted in the PRICING SUMMARY SHEET below:

(i) Standard engineering supplies used or consumed in the performance of the Services or provision of Deliverables at Contractor’s home offices.

(ii) Costs of reproduction of standard plans, specifications, reports and other data regularly generated at Contractor home offices.

(iii) Charges for use of Contractor desktop, laptop, and CADD computers at Contractor home offices for those personnel billable to the project

(iv) Charges for phones, to include cell phones and pagers and faxes originating from Contractor’s home offices, and Contractor’s actual costs for all other communication services specifically identifiable to the performance of the Services and provision of the Deliverables

(v) Charges for Contractor’s permanent office facilities and associated utilities.

Contractor EXCLUDES the following items in the Engineering Technology Charge rates quoted in the PRICING SUMMARY SHEET below: Each of these items will be charged at cost.

(iii) Actual expenses of travel, subsistence, relocation, and return of personnel engaged in the performance of the Services and Deliverables, including relocation and return expenses of families of such personnel

(viii) Costs associated with consultants, subcontracts, and other outside services and facilities.

(xii) All federal, state and local taxes, assessments, levies, imposts, duties, excises, permits, and licenses directly and solely identifiable to the Services and Deliverables, excepting only payroll taxes included in the Personnel Costs and taxes levied solely on Contractor’s net income

(ix) Costs of insurance premiums and any deductibles for the insurance required by this Contract, other than the insurance included in the Personnel Costs.

(x) Other costs and expenses incurred by Contractor in connection with the Professional Services that are not specifically set forth herein.

For PROJECT (SITE) OFFICE:

Contractor INCLUDES the following items in the Engineering Technology Charge rates quoted in the PRICING SUMMARY SHEET:

(i) Standard engineering supplies used or consumed in the performance of the Services or provision of Deliverables at Contractor’s Project site.

(ii) Costs of reproduction of plans, specifications, reports and other data at the Project site.

(iii) Charges for use and maintenance of Contractor central infrastructure and standard application computer systems, other existing Contractor technical programs, and links to the home office.

Page 1 of 2

EXECUTION COPY

EXHIBIT 5.1-7

(xi)Charges for cell phones and pagers originating in Contractor’s home offices.

(xii) Charges for Contractor’s permanent office facilities and associated utilities, including office space and utilities maintained as permanent base for Contractor’s Professional Construction Labor.

Contractor EXCLUDES the following items in the Engineering Technology Charge rates quoted in the PRICING SUMMARY SHEET: Each of these items will be charged at cost.

(xiii) Actual expenses of travel, subsistence, relocation, and return of personnel engaged in the performance of the Services and Deliverables, including relocation and return expenses of families of such personnel

(xiv) Costs associated with consultants, subcontracts, and other outside services and facilities.

(xii) All federal, state and local taxes, assessments, levies, imposts, duties, excises, permits, and licenses directly and solely identifiable to the Services and Deliverables, excepting only payroll taxes included in the Personnel Costs and taxes levied solely on Contractor’s net income

(xv) Costs of insurance premiums and any deductibles for the insurance required by this Contract, other than the insurance included in the Personnel Costs.

(xvi) Costs of purchased or leased desktop, laptop, and CADD computers at the Project Site and associated software.

(xvii) Charges for Contractor supplied temporary office facilities and associated utilities.

(xviii) Charges for site vehicles, including fuels and other operating costs.

(xix) Other costs and expenses incurred by Contractor in connection with the Professional Services that are not specifically set forth herein.

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EXHIBIT 5.1-8

TOOL AND EQUIPMENT RATES

AE-Contractor's Major Equipment Internal Rate Schedule effective 3/20/05

SAMPLE

CONSTRUCTION EQUIPMENT & VEHICLES DESCRIPTION	Monthly Bare Rate	Monthly Maintenance	State & Local Tax @ 8%	Total Monthly
CLASS 02 [TRUCKS - LIGHT DUTY]
PICKUP, 1/2 TON 4X2 GAS	******	******	******	******
PICKUP, 1/2 TON 4X4 GAS	******	******	******	******
SUV, UTILITY MEDIUM 4X4 GAS	******	******	******	******
CLASS 03 [ TRUCKS - HEAVY DUTY]
TRUCK, DUMP 13/15 CY DIESEL	******	******	******	******
TRUCK, FLATBED, HYD BOOM 11-15 TON CRANE DIESEL	******	******	******	******
TRUCK, STAKEBED 1 TON DIESEL	******	******	******	******
TRUCK, FUEL /LUBE COMBINATION 1,500 GAL DIESEL	******	******	******	******
TRUCK, MECHANICS SERVICE 1TON W/ BOOM, COMPRESSOR, WELDER DIESEL	******	******	******	******
TRUCK, WATER, 4,000G 6X6 PWR SPRAY, W/ WATER CANNON DIESEL	******	******	******	******
TRUCK, TRACTOR W/ 5th WHEEL 385 HP DIESEL	******	******	******	******
CLASS 04 [TRAILERS]
TRAILER, LOWBOY, 50-60 TON	******	******	******	******
TRAILER, FLATBED, HIGHBOY, 40-48 FT.	******	******	******	******
CLASS 11 [EARTHMOVER]
EXCAVATOR, CRAWLER, 60,700# DIESEL	******	******	******	******
MOTOR GRADER, 185HP, 32,460# W/ RIPPER SCARIFIER DIESEL	******	******	******	******
LOADER, BACKHOE, 78 HP DIESEL	******	******	******	******
LOADER, TOOL CARRIER 125 HP, 2.25 CY, W/ FORKS, BUCKET & BOOM DIESEL	******	******	******	******
LOADER, SKID STEER 60HP 5,808# DIESEL	******	******	******	******
LOADER, WHEEL 4YD 180HP W/FORKS DIESEL	******	******	******	******
CLASS 12 [PIPELAYING/TRENCHING/TUNNELING)
TRENCHER, CHAIN, 6"-16" x 6', 51HP DIESEL	******	******	******	******
CLASS 13 [COMPACTION]
COMPACTOR, SOIL, SD-DD WALK BEHIND, 29.9" DIESEL	******	******	******	******
COMPACTOR, SOIL, VIBRATORY, SMOOTH DRUM 66" 14,000# DIESEL	******	******	******	******
CLASS 14 [CRANES]
CRANE, CRAWLER 100T DIESEL	******	******	******	******
CRANE, CRAWLER 200T DIESEL	******	******	******	******
CRANE, CRAWLER 230T DIESEL	******	******	******	******
CRANE, CRAWLER 300T DIESEL	******	******	******	******
CRANE, CRAWLER 440T W/SUPERLIFT DIESEL	******	******	******	******
CRANE, ROUGH TERRAIN 28-30T DIESEL	******	******	******	******
CRANE, ROUGH TERRAIN 50T DIESEL	******	******	******	******
CRANE, ROUGH TERRAIN 65T DIESEL	******	******	******	******
CRANE, ROUGH TERRAIN 100T DIESEL	******	******	******	******
CLASS 15 [FORKLIFTS]
FORKLIFT, WAREHOUSE PNEU 6,000# GAS/LPG	******	******	******	******
FORKLIFT, TELE-BOOM, 8,000# DIESEL	******	******	******	******
CLASS 17 [ AIR COMPRESSORS]
AIR COMPRESSOR, 185 CFM DIESEL	******	******	******	******
AIR COMPRESSOR, 750 CFM DIESEL	******	******	******	******
CLASS 18 [ CRANE ACCESSORIES ]
CRANE, ATTACHMENT M250 LUFFING JIB	******	******	******	******
CRANE, ATTACHMENT, 300T 225 MAXER	******	******	******	******
CRANE, ATTACHMENT, RINGER 300T	******	******	******	******
CLASS 19 [ GANTRYS ]
STRAND JACK LIFT SYSTEM PSC L180-40, L180-60	******	******	******	******
GANRTY - JACKING FRAME 450-700T J&R L1402-4-39	******	******	******	******
CLASS 52 [WELDERS]
WELDER, 400AMP DIESEL, TRL. MTD. DIESEL	******	******	******	******
WELDER, 200AMP ELEC. 8 STATION	******	******	******	******
CLASS 53 [GENERATORS/LIGHT PLANTS/DISTRIBUTION]
GENERATOR, DIESEL 60KW, TRL. MTD.	******	******	******	******
LIGHT PLANTS, 6KW 4 X 1,000 WATT LAMPS, DIESEL	******	******	******	******
CLASS 54 [MANLIFTS/SCISSORLIFTS/ELEVATORS]
CONSTRUCTION ELEVATOR, MATERIAL HOIST, 150' 6,200#	******	******	******	******
MANLIFT, ARTICULATING BOOM 66' DIESEL	******	******	******	******
MANLIFT, ARTICULATING BOOM 86' DIESEL	******	******	******	******
MANLFIT, TELESCOPIC BOOM 120' DIESEL	******	******	******	******

The monthly bare rental rate is for “dry-hire only” and excludes operator, sales/use tax and mobilization/demobilization.

Actual Pricing will be confirmed at time purchase order

Maintenance includes labor, fuel, lubricants, spare parts, tires, and insurance

PAGE 1 OF 3

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-8

TOOL AND EQUIPMENT RATES
AE-Constructor's Major Equipment Internal Rate Schedule - AED GREEN BOOK ANALYSIS effective 3/20/05
SAMPLE	Over / Under BEO =	******%
	******	******

CONSTRUCTION EQUIPMENT & VEHICLES DESCRIPTION	Monthly Bare Rate	AED Rental Rate	Regional Multiplier	AED Regional Rental Rate
		Ohio Region 2 Multiplier
CLASS 02 [TRUCKS - LIGHT DUTY]
PICKUP, 1/2 TON 4X2 GAS		Not in AED	******	******
PICKUP, 1/2 TON 4X4 GAS		Not in AED	******	******
SUV, UTILITY MEDIUM 4X4 GAS		Not in AED	******	******
CLASS 03 [ TRUCKS - HEAVY DUTY]
TRUCK, DUMP 13/15 CY DIESEL		Not in AED	******	******
TRUCK, FLATBED, HYD BOOM 11-15 TON CRANE DIESEL	******	******	******	******
TRUCK, STAKEBED 1 TON DIESEL		Not in AED	******	******
TRUCK, FUEL /LUBE COMBINATION 1,500 GAL DIESEL		Not in AED	******	******
TRUCK, MECHANICS SERVICE 1TON W/ BOOM, COMPRESSOR, WELDER DIESEL		Not in AED	******	******
TRUCK, WATER, 4,000G 6X6 PWR SPRAY, W/ WATER CANNON DIESEL		Not in AED	******	******
TRUCK, TRACTOR W/ 5th WHEEL 385 HP DIESEL		Not in AED	******	******
CLASS 04 [TRAILERS]
TRAILER, LOWBOY, 50-60 TON		Not in AED	******	******
TRAILER, FLATBED, HIGHBOY, 40-48 FT.		Not in AED	******	******
CLASS 11 [EARTHMOVER]
EXCAVATOR, CRAWLER, 60,700# DIESEL	******	******	******	******
MOTOR GRADER, 185HP, 32,460# W/ RIPPER SCARIFIER DIESEL	******	******	******	******
LOADER, BACKHOE, 78 HP DIESEL	******	******	******	******
LOADER, TOOL CARRIER 125 HP, 2.25 CY, W/ FORKS, BUCKET & BOOM DIESEL	******	******	******	******
LOADER, SKID STEER 60HP 5,808# DIESEL	******	******	******	******
LOADER, WHEEL 4YD 180HP W/FORKS DIESEL	******	******	******	******
CLASS 12 [PIPELAYING/TRENCHING/TUNNELING)
TRENCHER, CHAIN, 6"-16" x 6', 51HP DIESEL	******	******	******	******
CLASS 13 [COMPACTION]
COMPACTOR, SOIL, SD-DD WALK BEHIND, 29.9" DIESEL	******	******	******	******
COMPACTOR, SOIL, VIBRATORY, SMOOTH DRUM 66" 14,000# DIESEL	******	******	******	******
CLASS 14 [CRANES]
CRANE, CRAWLER 100T DIESEL	******	******	******	******
CRANE, CRAWLER 200T DIESEL	******	******	******	******
CRANE, CRAWLER 230T DIESEL		Not in AED	******	******
CRANE, CRAWLER 300T DIESEL		Not in AED	******	******
CRANE, CRAWLER 440T W/SUPERLIFT DIESEL		Not in AED	******	******
CRANE, ROUGH TERRAIN 28-30T DIESEL	******	******	******	******
CRANE, ROUGH TERRAIN 50T DIESEL	******	******	******	******
CRANE, ROUGH TERRAIN 65T DIESEL	******	******	******	******
CRANE, ROUGH TERRAIN 100T DIESEL	******	******	******	******

PAGE 2 OF 3

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-8

TOOL AND EQUIPMENT RATES
AE-Constructor's Major Equipment Internal Rate Schedule - AED GREEN BOOK ANALYSIS effective 3/20/05
SAMPLE	Over / Under BEO =	******%
	******	******

CONSTRUCTION EQUIPMENT & VEHICLES DESCRIPTION	Monthly Bare Rate	AED Rental Rate	Regional Multiplier	AED Regional Rental Rate
CLASS 15 [FORKLIFTS]
FORKLIFT, WAREHOUSE PNEU 6,000# GAS/LPG	******	******	******	******
FORKLIFT, TELE-BOOM, 8,000# DIESEL	******	******	******	******
CLASS 17 [ AIR COMPRESSORS]
AIR COMPRESSOR, 185 CFM DIESEL	******	******	******	******
AIR COMPRESSOR, 750 CFM DIESEL	******	******	******	******
CLASS 18 [ CRANE ACCESSORIES ]
CRANE, ATTACHMENT M250 LUFFING JIB		Not in AED	******	******
CRANE, ATTACHMENT, 300T 225 MAXER		Not in AED	******	******
CRANE, ATTACHMENT, RINGER 300T		Not in AED	******	******
CLASS 19 [ GANTRYS ]
STRAND JACK LIFT SYSTEM PSC L180-40, L180-60		Not in AED	******	******
GANRTY - JACKING FRAME 450-700T J&R L1402-4-39		Not in AED	******	******
CLASS 52 [WELDERS]
WELDER, 400AMP DIESEL, TRL. MTD. DIESEL	******	******	******	******
WELDER, 200AMP ELEC. 8 STATION		Not in AED	******	******
CLASS 53 [GENERTORS/LIGHT PLANTS/DISTRIBUTION]
GENERATOR, DIESEL 60KW, TRL. MTD.	******	******	******	******
LIGHT PLANTS, 6KW 4 X 1,000 WATT LAMPS, DIESEL	******	******	******	******
CLASS 54 [MANLIFTS/SCISSORLIFTS/ELEVATORS]
CONSTRUCTION ELEVATOR, MATERIAL HOIST, 150' 6,200#		Not in AED	******	******
MANLIFT, ARTICULATING BOOM 66' DIESEL	******	******	******	******
MANLIFT, ARTICULATING BOOM 86' DIESEL	******	******	******	******
MANLFIT, TELESCOPIC BOOM 120' DIESEL	******	******	******	******

Page 3 of 3

EXECUTION COPY

EXHIBIT 5.1-9

JOB SUPPLIES

Barrels (water, Trash, etc.)

Bits, Rock

Bits, Wood & Steel

Bolts (Temp. Use)

Boots

Brooms

Brushes

Cable, Wire Rope (except on power equip.)

Cable Welding

Carborundum Blocks

Chalk, Carpenters'

Checks, Brass

Clamps, Cable (except on power equip.)

Cleaning Compounds, Solvents, Rags & Waste

Coats, Rain

Crayon, Lumber

Cups, paper

Dies

Disposal, Protective Clothing

Drift pins

Drills, Star

Drills, Twist

Electric Light Bulbs

Electrical Fittings (temp. power and light)

Employee Protective Equipment/Gear

Extension Cords

Files

Film

Fire Extinguishers (temporary)

Flashlights & Batteries

Form Lubricants

Form Materials, Misc. Forms

Gas & Oxygen for Cutting, etc. (Incl. Bulk

Supply)

Gloves, Canvas or Other

Goggles & Safety Lenses

Handles (All)

Hats, Safety

Helmets, Sleeves, Gloves (Welder's

Protection)

Holders, Electrode

Hose, Air & Accessories

Hose, Fire (temporary)

Hose, Water

Janitor's Supplies

Lanterns & Similar Devices

Manifolds, all temp. services

Mops

Pails & Containers

Paint (for use Temp. Struct., etc.)

Paper (Sand-Emery)

Points, Moil, Chipping, etc.

Reamers

Respirators

Rollers, Wood or Steel

Rope, Manilla or Other Fiber

Runaways, Screens, etc. for Concrete Placing

Saw Blades, Power

Saw Blades, Hack, Coping, etc.

Screens, Sand

Slag, etc. (Temp. Use)

Slings, 1-1/4" dia. and under

Solder

Steel Plate & Shapes for Temp. Supports, etc.

Supplies (All Office)

Supplies & Equip. (First Aid & Safety)

Tape, Rubber & Friction, etc. (Temp. Use)

Taps

Tips, Cutting & Welding

Timber Mats, Cribbing, Blocking, etc.

Tarpaulins, Visqueen, etc.

Towels

Water Dispensers (Portable)

Weld Test Specimens

Wheels, Burrs, etc., for Grinding

Wire for Temp. Construction

Page 1 of 1

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-10

2005 RATE SHEET ENGINEERING / GRAPHICS LABOR & OTHER PROFESSIONAL LABOR (US OFFICES)
Bechtel Grade	Classification	ST	OT
Letter	Administrative, Clerical Support, Accounting	[$*****]	[$*****]
21	Senior Secretary, Administrator, Drafter, Project Controls Technician, Assistant Engineer, Accounting	[$*****]	[$*****]
22	Engineer, Drafter, Designer, Project Controls Engineer, Accounting, Procurement	[$*****]	[$*****]
23	Engineer, Drafter, Senior Designer	[$*****]	[$*****]
24	Engineer, Project Controls Engineer, Senior Designer, Contract Administrator, Proposal Coordinator, Automation Support, Procurement	[$*****]	[$*****]
25	Senior Engineer, Senior Project Controls Engineer, Supervising Designer, Contract and Project Administrators, Automation Support, Procurement	[$*****]	[$*****]
26	Engineering Supervisor, Senior Engineer, Design/Drafting Supervisor, Senior Contract Administrator, Project Controls Supervisor, Accounting Supervisor, Procurement	[$*****]	[$*****]
27	Project Engineer, Project Estimator, Engineering Supervisor, Design/Drafting Supervisor, Project Controls Manager	[$*****]	[$*****]
28	Project Engineer, Project Estimator, Engineering Supervisor, Design/Drafting Supervisor, Project Controls Manager	[$*****]	[$*****]
29	Project Engineer, Department Manager, Project Manager, Chief Engineer	[$*****]	[$*****]
30	Senior Project Engineer, Senior Manager, Department Manager, Project Manager, Chief Engineer	[$*****]	[$*****]
31 & Up	Manager of Operations, Manager of Services, Regional Manager, Department Manager, Project Manager, Chief Engineer	[$*****]	[$*****]
	Specialist
25	Home Office Rigging Engineer, Laser Mapping Specialist, Environmental Permitting Specialist	[$*****]	[$*****]
26	Home Office  Rigging Engineer, Laser Mapping Specialist, Environmental Permitting Specialist	[$*****]	[$*****]
27	Home Office  Rigging Engineer, Laser Mapping Specialist, Environmental Permitting Specialist, FGD Technology Specialist, Financial Analyst	[$*****]	[$*****]
28	Environmental Permitting Specialist, FGD Technology Specialist, Financial Analyst	[$*****]	[$*****]
29	Environmental Permitting Specialist, FGD Technology Specialist, Financial Analyst	[$*****]	[$*****]
30	Environmental Permitting Specialist, FGD Technology Specialist, Financial Analyst	[$*****]	[$*****]
31 & Up	Environmental Permitting Specialist, FGD Technology Specialist, Financial Analyst	[$*****]	[$*****]

Page 1 of 2

EXECUTION COPY

EXHIBIT 5.1-10

Classifications provided are typical but not all-inclusive. All personnel supporting the Work are billable, including technical and Management oversight (i.e., project management, project controls quality assurance, contract formation, construction administrative, and technical support services) and financial services specifically requested for the project (such as audit support and special reports).

Page 2 of 2

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-11

2005 RATE SHEET Professional Construction Labor (US Offices)
Bechtel Grade	Classification	ST	OT
Letter	Administrative, Clerical Support, Accounting	[$*****]	[$*****]
21	Senior Secretary, Administrator, Drafter, Project Controls Technician, Assistant Engineer, Accounting	[$*****]	[$*****]
22	Engineer, Drafter, Designer, Project Controls Engineer, Accounting, Procurement	[$*****]	[$*****]
23	Engineer, Drafter, Senior Designer, Construction Supervision, Safety	[$*****]	[$*****]
24	Engineer, Project Controls Engineer, Senior Designer, Contract Administrator, Proposal Coordinator, Automation Support, Safety, Construction Supervision, Procurement	[$*****]	[$*****]
25	Senior Engineer, Senior Project Controls Engineer, Supervising Designer, Contract and Project Administrators, Automation Support, Safety, Procurement	[$*****]	[$*****]
26	Engineering Supervisor, Senior Engineer, Design/Drafting Supervisor, Senior Contract Administrator, Project Controls Supervisor, Accounting Supervisor, Safety, Procurement	[$*****]	[$*****]
27	Project Engineer, Project Estimator, Engineering Supervisor, Design/Drafting Supervisor, Project Controls Manager	[$*****]	[$*****]
28	Project Engineer, Project Estimator, Engineering Supervisor, Design/Drafting Supervisor, Project Controls Manager, General Superintendent	[$*****]	[$*****]
29	Project Engineer, Department Manager, Project Manager, Chief Engineer	[$*****]	[$*****]
30	Senior Project Engineer, Senior Manager, Department Manager, Project Manager	[$*****]	[$*****]
31 & Up	Manager of Operations, Manager of Services, Senior Construction Manager, Department Manager, Project Manager	[$*****]	[$*****]
	Classifications provided are typical but not all-inclusive. All personnel supporting the work are billable, including technical and management oversight (i.e., project management, project controls, quality assurance, contract formation, construction administrative, and technical support services) and financial services specifically requested for the project (such as audit support and special reports).

Page 1 of 1

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-12

AQC SYSTEMS COST REIMBURSABLE WORK

CRAFT LABOR

The AE-Constructor shall be paid an amount to be determined by the following methods:

A. Payment for authorized Subcontracts (a subsidiary or company which is in any way associated with the AE-Constructor is not considered a Subcontractor) at AE-Constructor's direct cost (Invoice). For permanent materials furnished by a Subcontractor, such materials shall be furnished at Subcontractor's direct cost (Invoice). AE-Constructor shall include with invoices, receipts for all such materials furnished by Subcontractor.

B. Payment for permanent materials furnished by AE-Constructor at AE-Constructor's direct cost (Invoice). AE-Constructor shall include with invoice receipts for all such materials furnished.

C. Payment for major construction and maintenance tools and equipment that have an original cost greater than [$*****] each (MAJOR EQUIPMENT), by one or more of the following methods as determined by FirstEnergy and/or as dictated by ownership of equipment:

1.      For AE-Constructor-owned MAJOR EQUIPMENT, the AE-Constructor shall be reimbursed in accordance with the AE-Constructor's Internal Rate Schedule, Exhibit 5.1-8, and as noted below or at mutually agreed upon rates.

a. AE-Constructor’s Internal Rate Schedule shall constitute full compensation for the use of this equipment, including fuel, lubricants, taxes and including compensation for all labor, material and other costs incurred in the repair and maintenance of said equipment.

b. Rental rates shall be charged at the lowest rates considering the duration of time

that the equipment or tools are required. Rental rates shall be per calendar day, Week and Month with billing as follows:

· Beginning on the first day required, a daily rate during that Week (7-day period beginning on the day of the week the equipment is first required or for subsequent months, the first day of accrual for that month), but not to exceed the Weekly rate for that Week.

· The second Week of a rental again begins with the daily rate during the Week but not to exceed the Weekly rate for that Week.

· Further Weeks of rental again begin as above, but once the monthly rate is accrued, the monthly rate is used. The equipment is then available for a Month (beginning on the day of the month first used and until reaching the same day of the following month, at which time the cycle of accrual begins again.

c. If the physical use of the equipment in operating hours dictates required maintenance for the equipment including major overhauls (as designated in Exhibit 5.1-8 by AE-Constructor), for continuous use of the equipment for two shifts in one calendar day, Week, Month, AE-Constructor shall be reimbursed as if there were two pieces of equipment in use during that day, Week, Month.

d. If the physical use of the equipment in operating hours dictates required maintenance for the equipment including major overhauls (as designated in Exhibit 5.1-8 by AE-Constructor), for intermittent use of the equipment for two shifts in one calendar day, Week, Month, AE-Constructor shall be reimbursed as follows:

For second shift work (after the first shift has been reimbursed based on Article C.1.a. and b. above) rental rates shall be at half of the hourly rental rate (the hourly rental rate is determined using the monthly rental rate from Exhibit 5.1-8 divided by 176 hours) times the actual hours of use on second shift. Therefore as examples (For these examples, assume equipment rates are [$*****]/day, [$*****]/week, [$*****]/month, and hourly rental rate is [$*****]):

· Working 6 days per week, with actual work on second shift averaging 6 hours per day, (36 hours/week), reimbursement for a week would be [$*****] plus 36 hours times [$*****] times 50% or [$*****].

e. AE-Constructor shall document actual billable time and appropriate billing rates for purposes of determining actual cost to FirstEnergy, including daily, weekly or monthly

Page 1 of 9

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EXECUTION COPY

EXHIBIT 5.1-12

documentation, as appropriate, signed by FirstEnergy’s Superintendent. If no pre-planned written agreement is reached relative to the appropriate documentation, then daily documentation (such as supplemental documentation incorporated with signed daily time sheets) is required. AE-Constructor shall maintain documentation acceptable to FirstEnergy’s Superintendent indicating equipment usage and idle time and/or equipment required to be on-site. This documentation shall be a minimum of daily, or as indicated in above referenced pre-planned written agreement.

2. For AE-Constructor owned electrical tools meeting the requirements of this paragraph, not listed in Exhibit 5.1-8, or as determined by FirstEnergy, AE-Constructor shall be reimbursed at [*****%] of the daily, weekly and monthly rates contained in the latest edition of the"NECA Tool and Equipment Rental Schedules” (A Guide for Electrical Contractors or A Guide for Line Contractors), administered as in C.1.a., b., c., and d. above.  

3. For AE-Constructor owned construction equipment meeting the requirements of this paragraph, not listed in Exhibit 5.1-8 , or as determined by FirstEnergy, AE-Constructor shall be reimbursed at competitive regional rates no more than [*****%] of the AED Green Book of the daily, weekly and monthly rates contained in the latest edition of “The AED Green Book” published by Primedia Information Inc., San Jose, California (Refer to Exhibit 5.1-8) administered as in C.1.a.,b.,c., and d. above.

       4. For rented MAJOR EQUIPMENT from a third party, not a subsidiary or company which is in any way associated with the AE-Constructor, the AE-Constructor will be reimbursed at the direct cost (Invoice). No addidtional markup of the invoice cost for engine-driven equipment shall be allowed; with added mark-up (to be determined) to cover fuels and lubricants if such costs are not included in the equipment rental price. AE-Constructor shall endeavor to engage such third party rental company in the same form and manner as 2 above.

a. AE-Constructor’s primary source for third party reimbursable rented or leased MAJOR EQUIPMENT should be with FirstEnergy’s “preferred supplier” United Rentals, under the Pantellos Collaborative Agreement for FirstEnergy. The AE-Constructor shall secure comparative rental rates whenever feasible. FirstEnergy’s “preferred supplier” shall be used unless the rental rate is, in the AE-Constructor’s opinion, not competitive or the “preferred supplier” is unable to satisfactorily supply the equipment. The AE-Constructor is to communicate these exceptions and the reasons to the Supply Chain Department representative in a reasonable time, but no later than 30 days after completion of the work.

Contact at United Rentals: Chris Britt, Branch Manager, cbritt@ur.com

Columbiana #A27East Liverpool #A28

44691 State Route 14                                    16695 Lisbon Street

Columbiana, Ohio 44408                                East Liverpool, Ohio 43920

Phone: 330-482-1100                                     Phone: 330-385-5381

FAX: 330-482-1182                                        FAX: 330-385-7304

Estimated Cost for MAJOR EQUIPMENT may be pre-determined for a Subproject, including both owned and third-party rentals. The Estimated Cost shall be agreed upon by the parties, and becomes part of the “Target Construction Cost”.

If the parties, prior to the start of a Subproject (with equipment use greater than a month), agree (in writing) upon a fixed rental period for the Subproject, the rental amount shall be determined based on use of fractional month’s rental for any period in excess of full months.

All MAJOR EQUIPMENT must be authorized by FirstEnergy prior to being delivered to the jobsite and in no event shall the rental rates be higher than the rates paid in the locality for similar equipment.

FirstEnergy reserves the right to provide any MAJOR EQUIPMENT at any time during the term of this Contract. If provided, FirstEnergy will either provide or pay for all necessary fuel, lubricants and maintenance.

Page 2 of 9

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 5.1-12

D.By payment for:

1. Wages and fringe benefits required by applicable union contract for craft labor up to and including the General Foreman.

2. Payroll taxes, contributions to Federal and State Unemployment and Worker's (Workmen's) Compensation funds required to be made by the AE-Constructor for craft labor and Comprehensive General Liability and Employer's Liability Insurance (burdens).

In lieu of invoicing actuals, such payroll taxes, Federal and State Unemployment, Worker's Compensation funds and Comprehensive General Liability and Employer's Liability Insurance as required by the Contract terms may be charged at the Cumulative Adjustable Rate (CAR), as defined below, of Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] (Ohio) or of Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] (Pennsylvania) of the Wages (up to and including General Foreman) and adjusted (periodic adjustments to be determined) to reflect actual costs. In the event that FirstEnergy elects for the Contractor to provide $[******] million excess liability insurance in accordance with Article 12 of the Agreement, the Cumulative Adjustable Rate (CAR), as defined below, will be of Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] (Ohio) or, of Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] (Pennsylvania) of the Wages. Pursuant to the provisions of the Contract terms allowing FirstEnergy's access to AE-Constructor's records to review Contract cost, FirstEnergy shall have the right of access to records substantiating the actual cost of the various portions of the Cumulative Adjustable Rate, and FirstEnergy and AE-Constructor agree to make adjustments to actual costs (periodic adjustments to be determined), subject to audit (FirstEnergy's access) under the provisions as allowed for herein.

The Cumulative Adjustable Rate (CAR) shall be comprised and represent the sum of the components listed below (a., b., and c. or d.) with some components, or portions thereof, reimbursable based on actual costs incurred by the AE-Constructor, and other portions, or portions thereof, reimbursable and shall be adjusted (periodic adjustments to bedetermined) during the term of the Contract.

a.      FICA, FUTA, and SUTA

FirstEnergy will reimburse the AE-Constructor for FICA, Federal (FUTA) and State (SUTA) Unemployment at the Rate of [*****%] (Ohio) or [*****%] (Pennsylvania) of Wages (up to and including General Foreman). Upon receipt of notification of statutory changes in these rates, AE-Constructor shall notify FirstEnergy within 10 days of receipt of this notification for consideration by the parties of making changes in the CAR. The AE-Constructor shall provide a report, which reconciles the difference between the amount billed for FICA, FUTA and SUTA with the actual amount paid therefor, whether charges or credits, which shall be submitted to FirstEnergy along with an invoice or a check, with proper reconciliation of adjustments (periodic adjustments to be determined). The breakdown for the FICA, FUTA and SUTA percentage listed above is FICA [*****%]; FUTA [*****%] and SUTA [*****%] (Ohio) and [*****%] (PA).

b. Comprehensive General Liability and Employer's Liability Insurance

The portion of the AE-Constructor's premiums that are directly related to the insurance required by FirstEnergy as per the Contract terms will be reimbursed to the AE-Constructor at [*****%] of the Wages; in the event that FirstEnergy elects for the Contractor to provide $[******] excess liability insurance, in accordance with Article 12 of the Agreement, the insurance required by FirstEnergy as per the Contract terms will be reimbursed to the AE-Constructor at [*****%] of the Wages. This percentage mark-up shall be adjusted (periodic adjustments to be determined) during the term of the contract. Premiums for additional insurance (other than as required by the Contract terms) as may be required by FirstEnergy and will be reimbursed at invoice cost.

Page 3 of 9

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EXECUTION COPY

EXHIBIT 5.1-12

c. Worker’s (Workmen’s) Compensation - State of Ohio

For work performed in the state of Ohio, the portion of the AE-Constructor's Workers' Compensation premiums that are directly related to the coverage required by FirstEnergy shall be reimbursed at of Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] (Ohio) of Wages. This percentage shall be based on the AE-Constructor’s actual premium rate in effect on July 1 immediately preceding the effective date of the Contract. The statutory percentage component of Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] for Ohio may be escalated/de-escalated, upon notification from the AE-Constructor, for any increase/decrease in the statutory Worker's Compensation (Manual Rate only) as modified by the AE-Constructor's Experience Modification Percentage (rate). The Experience Modification Rate, in effect on [*****] immediately preceding the effective date of the Contract shall be periodically adjusted during the term of the Contract. AE-Constructor shall provide evidence, acceptable to and agreed by FirstEnergy, of such escalation/de-escalation that directly affect such cost prior to such changes becoming effective. FirstEnergy shall be notified within 10 days of AE-Constructor’s receipt of Worker’s Compensation notice from the State of Ohio whether there is an increase, a decrease or no change. FirstEnergy and AE-Constructor shall then determine appropriate timing for adjustment of the CAR. The AE-Constructor shall provide a report, for any adjustments for past work (refunds/rebates/discounts/weekly wage caps/etc.), whether charges or credits, which shall be submitted to FirstEnergy along with an invoice or a check, with proper reconciliation of adjustments (periodic adjustments to be determined). The Manual rate and the Experience Modification Factor used to calculate the rate above are Manual Rate Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] for Ohio and Experience Modification Factor 1.00 for Ohio, plus statutory Administrative Costs and DWRF Costs of Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] for Ohio. Any escalation/de-escalation because of changes to the Experience Modification Factor shall be as mutually agreed by both FirstEnergy and AE-Constructor. Should the Manual Rate Code used as the Base Rate for premium cost calculation purposes be revised resulting in a lower Manual and total premium cost rate, the resulting change shall accrue to the benefit of FirstEnergy.

If AE-Constructor compliance for Workers' Compensation is provided under an acceptable (by the State Workers' Compensation Commission) self-insurance program, AE-Constructor shall submit evidence of such certification and the degree of self-insurance being undertaken. The effective rate as provided above for reimbursement under such self-insurance program shall be adjusted(periodic adjustments to bedetermined) during the term of the Contract.

If during the duration of the Contract the Contractor’s Ohio Worker’s Compensation status changes from the individual program to a group program, or from the group program to an individual program, then FirstEnergy shall be notified within 10 days of AE-Constructor’s receipt of such Worker’s Compensation notice from the State of Ohio. FirstEnergy and AE-Constructor shall then determine the necessary adjustments to the percentage markup for Ohio worker’s compensation and the appropriate timing for adjustment of the CAR.

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EXHIBIT 5.1-12

d.      Worker's (Workmen's) Compensation - Commonwealth of Pennsylvania

For work performed in the Commonwealth of Pennsylvania, the portion of the Contractor's Workers' Compensation premiums that are directly related to the coverage required by FirstEnergy shall be reimbursed at Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] (Pennsylvania) of Wages. This percentage shall be based on the AE-Constructor’s actual premium rate in effect on the first day of the month immediately preceding the effective date of the Contract. The statutory percentage component of Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] for Pennsylvania may be escalated/de-escalated, upon notification from the AE-Constructor, for any increase/decrease in the statutory Worker's Compensation (Manual Rate only) as modified by the AE-Constructor's Experience Modification Percentage (rate). The Experience Modification Rate in effect on the first day of the month immediately preceding the effective date of the Contract shall be adjusted (periodic adjustments tobe determined) during the term of the Contract. AE-Constructor shall provide evidence, acceptable to and agreed by FirstEnergy, of such escalation/de-escalation that directly affect such cost prior to such changes becoming effective. FirstEnergy shall be notified within 10 days of AE-Constructor’s receipt of Worker’s Compensation notice from the insurance underwriters of current statutory Worker’s Compensation rates whether there is an increase, a decrease or no change. FirstEnergy and AE-Constructor shall then determine appropriate timing for adjustment of the CAR. Within 45 days of such receipt by AE-Constructor and within 45 days of the end of the project, any adjustments for past work (refunds/rebates/discounts/etc.), whether charges or credits, shall be submitted to FirstEnergy in the form of an invoice or a check, with proper reconciliation of adjustments (periodic adjustments to be determined). The Manual rate and the Experience Modification Factor used to calculate the rate above are Manual Rate Boiler Maker [*****%], Pipe Fitter [*****%], Electrician [*****%] for Pennsylvania and Experience Modification Factor [*****] for Pennsylvania. Any escalation/de-escalation because of changes to the Experience Modification Factor shall be as mutually agreed by both FirstEnergy and AE-Constructor. Should the Manual Rate Code used as the Base Rate for premium cost calculation purposes be revised resulting in a lower Manual and total premium cost rate, the resulting change shall accrue to the benefit of FirstEnergy.

3. Overheads (excluding Fee/profit) include, but not limited to, offsite support personnel, automotive insurance premiums, home office expenses, transporting small tools and light construction equipment to and from the jobsite, etc. to be paid for at a rate of [$*****]/Hr of the Base Hourly Wages calculated as follows: the direct straight time labor rate per hour required by applicable labor contract for craft labor (up to and including General Foreman) multiplied by the number of hours worked, multiplied by [$*****]/Hr. , as noted above. The initial charge rate shall be in effect for the period January 1, 2005 through December 31, 2005. Commencing January 1, 2006, the initial charge rate will be adjusted annually per the annual Consumer Price Index - Urban Wage Earners and Clerical Workers, Washington - Baltimore, DC-MD-VA-WV (Nov 96 = 100). For example, if the average Index for the 12 months preceding October 2005 were [*****%], the 2006 rate effective for January 1, 2006 through December 31, 2006, would be [$*****]/Hr.

E. Payment for small tools (that have an original cost of less than or equal to [$*****]) by one of the following methods as determined by FirstEnergy:

1. [$*****] Craft Labor Hour Worked. (Does not include Superintendent, craft General Foreman and Foreman, office personnel time, and AE-Constructor’s other non-craft administrative personnel.)

2. Pricing for Small Tools shall be adjusted annually at an escalation rate determined by the Bureau of Labor Statistics (BLS) Producer Price Index for “Material and Components for Construction”, commodity code [*****] (“BLS Index”). In the event that commodity code [*****] is discontinued, the next higher level series as published by BLS shall be used for escalation. The initial charge rate shall be in effect for the period January 1, 2005 through December 31, 2005. Commencing January 1, 2006, the initial charge rates will be adjusted annually. The BLS Index for the average of the twelve months preceding each October shall be used to determine the next year’s escalation. For example, if the average Index for the 12 months preceding October 2005 were [*****%], the 2006 rate effective for January 1, 2006 through December 31, 2006, would be [$*****]/Hr.

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CONFIDENTIAL TREATMENT REQUESTED

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EXHIBIT 5.1-12

3.  FirstEnergy may opt to furnish small tools.

F. Payment for consumables (job supplies such as paper clips, tape, respirators, gloves, paper, soap, grinding wheels, saw blades, etc. as defined in Exhibit 5.1-9, Job Supplies) by one of the following methods as determined by FirstEnergy:

1. [$*****] Craft Labor Hour Worked. (Does not include Superintendent, craft General Foreman and Foreman, office personnel time, and AE-Constructor’s other non-craft administrative personnel.)

2. Pricing for Small Tools shall be adjusted annually at an escalation rate determined by the Bureau of Labor Statistics (BLS) Producer Price Index for “Material and Components for Construction”, commodity code [*****] (“BLS Index”). In the event that commodity code [*****] is discontinued, the next higher level series as published by BLS shall be used for escalation. The initial charge rate shall be in effect for the period January 1, 2005 through December 31, 2005. Commencing January 1, 2006, the initial charge rates will be adjusted annually. The BLS Index for the average of the twelve months preceding each October shall be used to determine the next year’s escalation. For example, if the average Index for the 12 months preceding October 2005 were [*****%], the 2006 rate effective for January 1, 2006 through December 31, 2006, would be [$*****]/Hr.

3. FirstEnergy may opt to furnish small tools.

The payment for such items of Work as covered above shall be made as provided in the General Terms and Conditions for the Engineering, Procurement, and Construction.

FirstEnergy may authorize minor changes in the work not involving an adjustment in the [******] Price or [******] for Performance, which are consistent with the overall intent of the Contract.

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EXHIBIT 5.1-12

Example of Labor Costs

As of July 26, 2005

COST REIMBURSABLE WORK

BREAKDOWN OF COST OF LABOR (PF OH, 1^st Shift)

1.   [*****%] published wage rate (plus taxable fringes @ [$*****])

      Pipe Fitter Journeyman Local 495                                                                                        [$*****]

a.  Base Hourly Wage Rate [*****%] published rate (plus taxable                                                 [$*****]

      fringes @ [$*****]) Pipe Fitter Journeyman

2.   Fringe benefit cost/MNHR* (Non Taxable Fringes)

      a.  Hours Worked(Includes $-______/HR Industry Funds**)                                                   [$*****]

      b.Hours Paid(Includes $-______/HR Industry Funds**)                                                 [$*****]

3.  Insurance & Taxes (CAR) [*****%] of Wages (Hours Paid)                                                      [$*****]

4.   Overheads (excluding Fee) (Hours Worked)                                                                           [$*****]

5.   Payment for small tools (Hours Worked)                                                                               [$*****]

6.   Payment for consumables (Hours Worked)                                                                            [$*****]

7.   Total Cost Per Hour (First Shift)

a.  Straight (1a+2a+2b+3+4+5+6)                                                                                   [$*****]

b.  Premium (1a+2b+3)                                                                                                  [$*****]

                1.Time & one-half [(straight + .5 (premium)]                                                                [$*****]

                2.Double Time (straight + premium)                                                                           [$*****]

8.  Shift differential - Add to 1 above and recalculate

      3, 4, and 7 for 2nd and 3rd shift rates. If fringe

      benefits are affected by shift differential (i.e. fringes

      as a % of pay rate), items 2a. and 2b. may also

      need adjusted.

1.  2^nd       [$*****]/HR

2.  3^rd        [$*****]/HR

NOTE:(1)The AE-Constructor will be required to complete and submit the information above for all crafts used prior to the crafts beginning any Work.

All billing rate information to be sent to:

FirstEnergy Corp.

76 S. Main Street

Akron, OH 44308

ATTN: Peter F. Bertolo

        * As required by applicable union contract.

      ** Industry Funds, if applicable.

***Exclusive of the premium cost of [******] insurance, which shall be priced at an additional [*****%] of Wages paid.

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EXHIBIT 5.1-12

Example of Labor Costs

As of July 26, 2005

COST REIMBURSABLE WORK

BREAKDOWN OF COST OF LABOR (BM OH, 1^st Shift)

1.[*****%] published wage rate (plus taxable fringes @ [$*****])

    Boiler Maker Journeyman Local 154                                                                                     [$*****]

    a.Base Hourly Wage Rate [*****%] published rate (plus taxable

        fringes @ [$*****]) Boiler Maker Journeyman                                                                     [$*****]

2.Fringe benefit cost/MNHR* (Non Taxable Fringes)

a. Hours Worked(Includes $______/HR Industry Funds**)                                           [$*****]

b.Hours Paid(Includes $______/HR Industry Funds**)                                        [$*****]

3.Insurance & Taxes (CAR) [*****%] of Wages (Hours Paid)                                                       [$*****]

4.Overheads (excluding Fee)          (Hours Worked)                                                                [$*****]

5.Payment for small tools (Hours Worked)                                                                                [$*****]

6.Payment for consumables (Hours Worked)                                                                            [$*****]

7.Total Cost Per Hour (First Shift)

a.Straight (1a+2a+2b+3+4+5+6)                                                                                  [$*****]

b.Premium (1a+2b+3)                                                                                                 [$*****]

                1.Time & one-half [(straight + .5 (premium)]                                                              [$*****]

                2.Double Time (straight + premium)                                                                        [$*****]

8. Shift differential - Add to 1 above and recalculate

     3, 4, and 7 for 2nd and 3rd shift rates. If fringe

    benefits are affected by shift differential (i.e. fringes

    as a % of pay rate), items 2a. and 2b. may also

    need adjusted.

               1.2nd[$*****]/HR

               2.3rd[$*****]/HR

NOTE:  (1)The AE-Constructor will be required to complete and submit the information above for all crafts used prior to the crafts beginning any Work.

All billing rate information to be sent to:

                      FirstEnergy Corp.

                      76 S. Main Street

                      Akron, OH 44308

                      ATTN: Peter F. Bertolo

       * As required by applicable union contract.

      ** Industry Funds, if applicable.

***Exclusive of the premium cost of $[******] million excess liability insurance, which shall be priced at an additional [*****]% of Wages paid.

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EXECUTION COPY

EXHIBIT 5.1-12

Example of Labor Costs

As of July 26, 2005

COST REIMBURSABLE WORK

BREAKDOWN OF COST OF LABOR (EL OH, 1^st Shift)

1.[*****%] published wage rate (plus taxable fringes @ [$*****])

Electrician Journeyman Local 246                                                                                       [$*****]

a.Base Hourly Wage Rate 90% published rate (plus taxable

fringes @ [$*****]) Electrician Journeyman                                                                [$*****]

2.Fringe benefit cost/MNHR* (Non Taxable Fringes)

a.Hours Worked(Includes $ - ___/HR Industry Funds**)                                                    [$*****]

b.Hours Paid(Includes $ - ___/HR Industry Funds**)                                                 [$*****]

3.Insurance & Taxes (CAR) [*****%] of Wages (Hours Paid)                                                              [$*****]

4.Overheads (excluding Fee) (Hours Worked)                                                                                [$*****]

5.Payment for small tools (Hours Worked)                                                                                       [$*****]

6.Payment for consumables (Hours Worked)                                                                                    [$*****]

7.Total Cost Per Hour (First Shift)

a.Straight (1a+2a+2b+3+4+5+6)                                                                                         [$*****]

b.Premium (1a+2b+3)                                                                                                        [$*****]

1.Time & one-half [(straight + .5 (premium)]                                                             [$*****]

2.Double Time (straight + premium)                                                                        [$*****]

8. Shift differential - Add to 1 above and recalculate

    3, 4, and 7 for 2nd and 3rd shift rates. If fringe

    benefits are affected by shift differential (i.e. fringes

    as a % of pay rate), items 2a. and 2b. may also

    need adjusted.

1.2nd         [$*****]/HR

2.3rd          [$*****]/HR

NOTE:(1)The AE-Constructor will be required to complete and submit the information above for all crafts used prior to the crafts beginning any Work.

                            All billing rate information to be sent to:

                               FirstEnergy Corp.

                               76 S. Main Street

                               Akron, OH 44308

                               ATTN: Peter F. Bertolo

       *   As required by applicable union contract.

       ** Industry Funds, if applicable.

***Exclusive of the premium cost of ${******] million excess liability insurance, which shall be priced at an additional [*****]% of Wages paid.

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EXHIBIT 5.2(C)

CONTRACTOR’S INTERIM WAIVER AND RELEASE OF LIENS ANDCLAIMS

UPON PROGRESS PAYMENT

STATE OF ______________________

COUNTY OF ____________________:

The undersigned, _____________________________ ("Contractor"), has been engaged by FirstEnergy Generation Corp. ("FirstEnergy"), to furnish certain materials, equipment, services, and/or labor for the project known as [Subproject #____ (the "Subproject")] of the W.H. Sammis Plant Air Quality Control Project (the "Project"), which is located in Stratton, Ohio, and more particularly described on Attachment A, attached hereto (the "Property"), pursuant to the General Terms and Conditions for Engineering, Procurement, and Construction, dated _______________, 2005 (the “Agreement”).

Upon receipt of the sum of $_____________________ (“Current Payment”), Contractor waives and releases all liens or claims of liens for labor and materials against FirstEnergy, the Subproject, the Project, and the Property, and any right against any labor and/or material bond with the exception of the bond obligations in Section 12.7 of the Agreement, “Security for Vendor Termination Costs” Contractor has or may have through the date of ____________________, 200__ (“Current Date”) arising out of Contractor's performance of work on the Subproject and the Project.

Contractor represents that all of its obligations, legal, equitable, or otherwise, through ____________________, 200__ (date of last prior invoice) relating to or arising out of its work on the Subproject or the Project have been fully satisfied, including, but not limited to obligations relating to:

· Employees, laborers, materialmen and subcontractors employed by Contractor;

· Labor, materials, equipment and supplies furnished by others to Contractor; and

· Sales and use taxes, social security taxes, income tax withholding, unemployment insurance, privilege taxes, license fees, and any other taxes and obligations imposed by governmental authorities.

This Interim Lien Waiver is freely and voluntarily given, and Contractor acknowledges and represents that it has fully reviewed the terms and conditions of this Interim Lien Waiver, that it is fully informed with respect to the legal effect of this Interim Lien Waiver, and that it has voluntarily chosen to accept the terms and conditions of this Interim Lien Waiver in return for the payment recited above.

[NAME OF CONTRACTOR]
By:
	Title

AFFIDAVIT

On this ____ day of _________________, 20____, before me appeared the above-signed, known or identified to me personally, who, being first duly sworn, did say that the information provided in this document is true and accurate, this document was signed under oath personally and on behalf of Contractor, and that this Affidavit was executed as a free act and deed of Contractor.

Notary Public

My term Expires (date): _________________

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EXHIBIT 5.2(C)

SUBCONTRACTOR'S INTERIM WAIVER AND RELEASE OF LIENS AND CLAIMS

UPON PROGRESS PAYMENT

STATE OF ______________________

COUNTY OF ____________________:

OR OTHER JURISDICTION (where signing) __________________

The undersigned, ________________________, of ____________________________ ("Subcontractor") who has, under an agreement with ____________________________________ ("Contractor"), furnished certain materials, equipment, services, and/or labor for the project known as [Subproject #____ (the "Subproject")] of the W.H. Sammis Plant Air Quality Control Project (the "Project"), which is located in Stratton, Ohio, and more particularly described on Attachment A, attached hereto (the "Property").

Upon receipt of the sum of $_____________________ (“Current Payment”), the Subcontractor waives and releases any and all claims of lien for labor and materials against FirstEnergy Generation Corp. ("FirstEnergy"), Contractor, the Subproject, the Project, and the Property, at law, in contract, tort, equity or otherwise, and any and all liens or claims of liens or any right against any labor and/or material bond Subcontractor has or may have through the date of ____________________, 200__ (“Current Date”), arising out of Subcontractor's performance of work on the Subproject and the Project.

The Subcontractor represents that all of its obligations, legal, equitable, or otherwise, relating to or arising out of its work on the Subproject and the Project through ____________________, 200__ (date of last prior invoice) relating to or arising out of its work on the Subproject or the Project have been fully satisfied, including, but not limited to obligations relating to:

· Employees, laborers, materialmen and subcontractors employed by the Subcontractor;

· Labor, materials, equipment and supplies furnished by others to the Subcontractor; and

· Sales and use taxes, social security taxes, income tax withholding, unemployment insurance, privilege taxes, license fees, and any other taxes and obligations imposed by governmental authorities.

This Interim Lien Waiver is freely and voluntarily given and the Subcontractor acknowledges and represents that it has fully reviewed the terms and conditions of this Interim Lien Waiver, that it is fully informed with respect to the legal effect of this Interim Lien Waiver, and that it has voluntarily chosen to accept the terms and conditions of this Interim Lien Waiver in return for the payment recited above.

[NAME OF SUBCONTRACTOR]
By:
	Title:

AFFIDAVIT

On this ____ day of _________________, 20____, before me appeared the above-signed, known or identified to me personally, who, being first duly sworn, did say that the information provided in this document is true and accurate, this document was signed under oath personally and on behalf of Subcontractor, and that this Affidavit was executed as a free act and deed of Subcontractor.

Notary Public

My term Expires (date):_____________

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EXHIBIT 6.3(A)

CONTRACTOR’S FINAL LIEN WAIVER

STATE OF ______________________

COUNTY OF ____________________:

The undersigned, _____________________________ ("Contractor"), has been engaged by FirstEnergy Generation Corp. ("FirstEnergy"), to furnish certain materials, equipment, services, and/or labor for the project known as [Subproject #____ (the "Subproject")] of the W.H. Sammis Plant Air Quality Control Project (the "Project"), which is located in Stratton, Ohio, and more particularly described on Attachment A, attached hereto (the "Property"), pursuant to the General Terms and Conditions for Engineering, Procurement, and Construction, dated _______________, 2005 (the “Agreement”).

In consideration of payment of the Contract Price, the Fee (as defined in the Agreement), and all other amounts due under the Agreement, Contractor waives and releases all liens or claims of liens for labor and materials against FirstEnergy, the Subproject, and the Property in respect of the Subproject, and any right against any labor and/or material bond Contractor has, may have had or may have in the future arising out of Contractor's performance of work on the Subproject.

Contractor represents that all of its payment obligations, legal, equitable, or otherwise, that are due as of the date hereof relating to or arising out of its work on the Subproject have been fully satisfied, including, but not limited to obligations relating to:

· Employees, laborers, materialmen and subcontractors employed by Contractor;

· Labor, materials, equipment and supplies furnished by others to Contractor (except for the disputed amounts specified in the Certificate of Final Completion); and

· Sales and use taxes, social security taxes, income tax withholding, unemployment insurance, privilege taxes, license fees, and any other taxes and obligations imposed by governmental authorities.

This Final Lien Waiver is freely and voluntarily given, and Contractor acknowledges and represents that it has fully reviewed the terms and conditions of this Final Lien Waiver, that it is fully informed with respect to the legal effect of this Final Lien Waiver, and that it has voluntarily chosen to accept the terms and conditions of this Final Lien Waiver in return for the payment recited above.

[NAME OF CONTRACTOR]
By:
	Title:

AFFIDAVIT

On this ____ day of _________________, 20____, before me appeared the above-signed, known or identified to me personally, who, being first duly sworn, did say that the information provided in this document is true and accurate, this document was signed under oath personally and on behalf of Contractor, and that this Affidavit was executed as a free act and deed of Contractor.

Notary Public

My term Expires (date): _______________

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EXHIBIT 6.3(A)

SUBCONTRACTOR'S FINAL LIEN WAIVER

STATE OF ______________________

COUNTY OF ____________________:

OR OTHER JURISDICTION (where signing) __________________

The undersigned, ________________________, of ____________________________ ("Subcontractor") who has, under an agreement with ____________________________________ ("Contractor"), furnished certain materials, equipment, services, and/or labor for the project known as [Subproject #____ (the "Subproject")] of the W.H. Sammis Plant Air Quality Control Project (the "Project"), which is located in Stratton, Ohio, and more particularly described on Attachment A, attached hereto (the "Property").

In consideration of payment of the full amount of contract price owing to Subcontractor, the receipt of which is hereby acknowledged, the Subcontractor waives and releases any and all claims of lien for labor and materials against FirstEnergy Generation Corp. ("FirstEnergy"), Contractor, the Subproject, and the Property in respect of such Subproject, at law, in contract, tort, equity or otherwise, and any and all liens or claims of liens or any right against any labor and/or material bond Subcontractor has, may have had or may have in the future arising out of Subcontractor's performance of work on the Subproject.

The Subcontractor represents that all of its payment obligations, legal, equitable, or otherwise, relating to or arising out of its work on the Subproject have been fully satisfied, including, but not limited to obligations relating to:

·   Employees, laborers, materialmen and subcontractors employed by the Subcontractor;

·   Labor, materials, equipment and supplies furnished by others to the Subcontractor; and

·   Sales and use taxes, social security taxes, income tax withholding, unemployment insurance, privilege taxes, license fees, and any other taxes and obligations imposed by governmental authorities.

This Final Lien Waiver is freely and voluntarily given and the Subcontractor acknowledges and represents that it has fully reviewed the terms and conditions of this Final Lien Waiver, that it is fully informed with respect to the legal effect of this Final Lien Waiver, and that it has voluntarily chosen to accept the terms and conditions of this Final Lien Waiver in return for the payment recited above.

[NAME OF SUBCONTRACTOR]
By:
	Title

AFFIDAVIT

On this ____ day of _________________, 20____, before me appeared the above-signed, known or identified to me personally, who, being first duly sworn, did say that the information provided in this document is true and accurate, this document was signed under oath personally and on behalf of Subcontractor, and that this Affidavit was executed as a free act and deed of Subcontractor.

Notary Public

My term Expires (date):___________________ 

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EXHIBIT 6.3(C)

FINAL COMPLETION CERTIFICATE

__________________________________, a(n) ________________ corporation ("Contractor"), in accordance with Section 6.3(C) of the General Terms and Conditions for Engineering, Procurement, and Construction, dated __________________, 2005 (the "Agreement"), between Contractor and FirstEnergy Generation Corp., an Ohio corporation ("FirstEnergy"), does hereby certify that[, with respect to Subproject #___ of the W.H. Sammis Plant]:

1. Contractor has achieved Mechanical Completion of the Subproject;

2. Contractor has delivered to FirstEnergy a Final Lien Waiver, and Final Lien Waivers from each of its Subcontractors involved in the Subcontract, each in the form of Exhibit 6.3(A) to the Agreement;

3. Contractor has transferred to FirstEnergy all final documentation, records, Drawings and Specifications, and test reports required by the Agreement to be delivered to FirstEnergy.

4. Contractor has assigned or provided to FirstEnergy all warranties relating to the Subproject to the extent Contractor is required to do so under the Agreement;

5. Contractor has obtained all Contractor Permits required in connection with the performance of the Subproject;

6. Contractor has removed all Hazardous Substances brought onto, stored, used or located on the Site by Contractor or its Subcontractors in connection with the delivery, installation, or testing of the Subproject (unless the same have been permanently incorporated into the work in accordance with the Agreement and Applicable Law or unless the Parties have mutually agreed the same are required to support other on-going Contractor work);

7. Contractor has removed all its supplies, waste, materials, rubbish, and temporary facilities from the Site (except to the extent the Parties have mutually agreed the same are required to support other on-going Contractor work);

8. All Subcontractors have been finally paid, except for the disputed amounts listed below (but without limiting Contractor’s obligations under Article 14 and Section 6.4 of the Agreement.

Capitalized terms used herein which are not defined shall have the meaning ascribed to such terms in the Agreement.

IN WITNESS WHEREOF, Contractor has caused this Notice of Final Completion to be duly executed and delivered this ____ day of ______________, 20____.

[NAME OF CONTRACTOR]
By:
	Title:

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EXHIBIT 6.5

SCHEDULE LIQUIDATED DAMAGES

SCHEDULE LIQUIDATED DAMAGES (Wrap Arrangement)

For each day after the Guaranteed Final Completion date, but prior to 12/31/2010 (the “NSR Consent Decree Date”), that the Final Completion of an AQC Unit is delayed, the Contractor shall pay FirstEnergy an amount equal to the amount of the liquidated damages provided in the contract between the OEM and the Contractor regardless of whether Contractor or its Subcontractors (including the OEM) are at fault (but except to the extent FirstEnergy or FE Vendors are at fault or the Guaranteed Final Completion Date is extended pursuant to a Change Order) and regardless of the ability of the Contractor to ultimately collect such liquidated damages from the OEM. Contractor shall use best efforts to obtain, in such OEM contract, a liquidated damages rate of {$******] for each megawatt of NDC (defined in Exhibit 7.2) on the affected Generating Unit for each day of delay prior to the NSR Consent Decree Date (e.g. for the 300 MW Sammis Unit 5, the rate would be {$******] per day of delay).

For each day after the NSR Consent Decree Date that the Final Completion of an AQC Unit is delayed, the Contractor shall pay FirstEnergy an amount equal to the amount of the liquidated damages provided in the contract between the OEM and the Contractor regardless of whether Contractor or its Subcontractors (including the OEM) are at fault (but except to the extent FirstEnergy or FE Vendors are at fault or the Guaranteed Final Completion Date is extended pursuant to a Change Order) and regardless of the ability of the Contractor to ultimately collect such liquidated damages from the OEM. Contractor shall use best efforts to obtain, in such OEM contract, a liquidated damages rate of {$******] for each megawatt of NDC on the affected Generating Unit for each day of delay after the NSR Consent Decree Date (e.g. for the 300 MW Sammis Unit 5, the rate would be {$******] per day of delay).

In addition, with respect to an AQC Unit, for each Outage Day (defined in Exhibit 7.2) beyond [******] days the Contractor uses during the Corrective Action Period (defined in Exhibit 7.2), the Contractor shall pay FirstEnergy the an amount equal to the amount of liquidated damages provided in the contract between the OEM and the Contractor regardless of whether Contractor or its Subcontractors (including the OEM) are at fault (but except to the extent FirstEnergy or FE Vendors are at fault or the Guaranteed Final Completion Date is extended pursuant to a Change Order) and regardless of the ability of the Contractor to ultimately collect such liquidated damages from the OEM. Contractor shall use best efforts to obtain, in such OEM contract, a liquidated damages rate of {$******] for each affected megawatt of NDC on the affected Generating Unit for each Outage Day (e.g. for the 300 MW Sammis Unit 5, the rate would be {$******] per Outage Day).

In addition, with respect to each Subproject or AQC Unit, in the event that Final Document Delivery has not been achieved by the date that Final Completion is achieved, Contractor shall pay FirstEnergy as liquidated damages {$******] per day until Final Document Delivery occurs.

SCHEDULE LIQUIDATED DAMAGES (FE Vendor Arrangement)

With respect to an AQC Unit, for each day after the Guaranteed Final Completion date, but prior to the NSR Consent Decree Date, that the Final Completion is delayed, but only for that portion of such delay caused by the Contractor, the Contractor shall pay FirstEnergy as Liquidated Damages {$******] for each megawatt of NDC on the affected Generating Unit for each day of delay (e.g. for the 300 MW Sammis Unit 5, the rate would be {$******] per day of delay) and for each day after the NSR Consent Decree Date that the Final Completion is delayed, but only for that portion of such delay caused by the Contractor, the Contractor shall pay FirstEnergy as liquidated damages {$******] for each megawatt of NDC on the affected Generating Unit for each day of delay (e.g. for the 300 MW Sammis Unit 5, the rate would be {$******]/day of delay).

Page 1 of 2

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 6.5

In addition, with respect to an AQC Unit, for each Outage Day beyond [******] days the Contractor uses during the Corrective Action Period, the Contractor shall pay FirstEnergy as liquidated damages, but only for that portion of such Outage Days caused by the Contractor, {$******] for each megawatt of NDC on the affected Generating unit for each Outage Day (e.g. for the 300 MW Sammis Unit 5, the rate would be {$******] Outage Day of delay).

In addition, with respect to each Subproject or AQC Unit, in the event that Final Document Delivery has not been achieved by the date that Final Completion is achieved, Contractor shall pay FirstEnergy as Liquidated Damages {$******] per day until Final Document Delivery occurs.

The Parties anticipate that the Project Schedule for the Subproject associated with Generating Units 1 through 4 of the Sammis Plant will designate a separate Guaranteed Final Completion Date for each AQC Unit within that Subproject. At the election of FirstEnergy, the Project Schedule for the Subproject associated with Sammis Plant Generating Units 5, 6, and 7 will designate either a single Guaranteed Final Completion Date for all AQC Units within that Subproject, or separate Guaranteed Final Completion Dates for each AQC Unit within that Subproject (with an adequate time allowed between the Scheduled Mechanical Completion Dates established for Generating Units 5, 6, and 7).

Contractor’s liability for Schedule Liquidated Damages for AQC Units associated with Sammis Plant Generating Units 1 through 4 shall in no event exceed the amount of the [******] on the total Subproject.

The limitation on the amount of Schedule Liquidated Damages for the AQC Units associated with Sammis Plant Generating Units 5, 6, and 7 shall be determined during the Development Phase as follows:

i)   If FirstEnergy elects to designate a single Guaranteed Final Completion Date for all AQC Units within that Subproject, then the Parties will treat all such AQC Units as one Subproject for purposes of the application of Schedule Liquidated Damages, and the Project Schedule will include an adequate time allowed between the Scheduled Mechanical Completion Dates established for the AQC Units associated with Generating Units 5, 6, and 7. In such case, Contractor’s liability for the Schedule Liquidated Damages for the Subproject shall in no event exceed the amount of the [******] on the total Subproject.

ii)   If FirstEnergy elects to designate separate Guaranteed Final Completion Dates for each AQC Unit within that Subproject, then the Parties will treat such AQC Units separately for purposes of the application of Schedule Liquidated Damages. In such case, Contractor’s liability for the Schedule Liquidated Damages for each AQC Unit shall in no event exceed the amount of the [******] on that AQC Unit.

Page 2 of 2

EXECUTION COPY

EXHIBIT 7.2

RELIABILITY STANDARD, PERFORMANCE GUARANTEES AND PERFORMANCE LIQUIDATED DAMAGES

RELIABILITY STANDARD

As a prerequisite for Final Completion of an AQC Unit such AQC Unit shall complete a reliability test consisting of a 30 consecutive day run (the “Reliability Standard”).

An AQC Unit shall be deemed to have successfully met the Reliability Standard if the following criteria (or such criteria as may be negotiated with the OEM during the Development Phase; Contractor shall use best efforts to obtain the criteria listed below in the contract between the OEM and Contractor are met:

1.   During the reliability test, the average outlet emission rate is 0.10 lb./MMBTU or less for SO₂ with respect to AQC Units 5, 6, and 7 of the W.H. Sammis facility as measured by the AQC Unit CEMS. The acceptable average outlet emission rate with respect to AQC Units 1 - 4 will be determined during the Development Phase for that Subproject.

2.   The AQC Unit does not cause the associated Generating Unit output to be restricted during the duration of the test.

3.   No auxiliary, standby or temporary equipment or machinery is used during the performance of the test, unless otherwise approved by FirstEnergy (however, installed redundant, permanent plant equipment may be used during the test).

4.   The AQC Unit is operated in its normal mode of operation while the test is being conducted, which shall consist of;

(i)   the operation of the AQC Unit as a whole in accordance with the Specifications and the operating instructions supplied by the Contractor and approved by FirstEnergy during the Development Phase;

(ii)   the operation of all AQC Unit systems within the manufacturers’ specifications and without over-stressing or over-pressurizing any such systems; and

(iii)   the Generating Unit is operating on the range of fuels shown in Exhibit 7.2 -1.

The test shall be run by the Contractor utilizing FirstEnergy’s personnel by means of supervising and directing FirstEnergy’s supervisor(s); it being agreed by the parties that FirstEnergy’s personnel shall not be (or deemed to be) employees of the Contractor. However, the use of FirstEnergy’s personnel by the Contractor shall not relieve the Contractor of any liability or responsibility under this Agreement. FirstEnergy shall reasonably make available a set of operating spare parts for the Subproject available for Contractor’s use during the performance test. The operating spare parts inventory requirements will be established during the Development Phase.

In the event the Contractor fails to successfully meet the Reliability Standard after a test run, it shall promptly thereafter submit a plan to correct the work including an explanation of the reason for failure of the test, the tasks anticipated to correct the deficiencies, duration of the tasks and their critical path, the outages required and a cost estimate (the “Corrective Action Plan”). The Corrective Action Plan will be subject to timely and reasonable review and approval by FirstEnergy. Once the Corrective Action Plan is approved, the Contractor will execute the plan and re-perform the test. The Contractor shall repeat this procedure until the Reliability Standard has been met.

If, during the course of performing the test, the Generating Unit operation causes the Subproject to fail the test through no fault of the Contractor or the Subproject itself, the test will be suspended until the Generating Unit is returned to service. Once the AQC Unit is returned to service, the Contractor will continue the test counting from the day it had been suspended as if no interruption had occurred. Contractor will be given a day for day extension of the Corrective Action Period, if required, to complete such suspended test, and a Change Order to reflect adjustments to the Guaranteed Final Completion Date (and any other appropriate changes to the Changed Criteria) shall be completed.

Page 1 of 4

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 7.2

PERFORMANCE GUARANTEES (Wrap Arrangement)

Performance Guarantees for an AQC Unit under a Wrap Arrangement are as follows:

· SO₂ Emission Removal Rate Guarantee: [******%] (or such amount as may be negotiated with the OEM during the Development Phase; Contractor shall use best efforts to obtain a [******%] SO₂ emission removal rate guarantee in the contract between the OEM and Contractor.)

· Auxiliary Power Guarantee: To be set during the Development Phase for the Subproject but will include all new loads associated with a given Subproject and any modification of existing loads (e.g. fan upgrades etc.) for a Subproject. For purposes of the Auxiliary Power Guarantee, allocation of new and existing electric loads between the AQC Units will be established during the Development Phase.

All Performance Guarantees are to be met while the Generating Unit operates at its Net Demonstrated Capacity (which capacity FirstEnergy shall reasonably document for Contractor) as modified by the additional auxiliary loads related to the Subproject (“NDC”) with consumables meeting the criteria set forth in the Design Fuel range as defined in Exhibit 7.2 -1 and the Design Reagent range. FirstEnergy and Contractor will establish the Design Reagent range during the Development Phase for the Subproject. During the performance test, there should be no net increase in front half filterable PM emissions for AQC Units 6 & 7 between inlet and outlet of the new WFGD systems for units 6 and 7, using reference methods specified in 40 CFR Part 60, Appendix A, Method 5, or Method 5B, in support of FirstEnergy's commitments within the NSR Consent Decree.

PERFORMANCE GUARANTEES (FE Vendor Arrangement)

Performance Guarantees, Design Fuel range, and Design Reagent range under a FE Vendor Arrangement will be set between the OEM for each Subproject and FirstEnergy and coordinated with Bechtel. Contractor shall be liable with respect to such Performance Guarantees to the extent Contractor contributes to any performance shortfall.

CORRECTIVE ACTION PERIOD

For purposes of this Exhibit 7.2, the “Operation Date” with respect to an AQC Unit shall mean the date which is [******] days prior to the Guaranteed Final Completion Date. If the Contractor fails to meet any of the Performance Guarantees, excluding the Reliability Standard, by the Operation Date, Contractor will be permitted a [******] day period to correct deficiencies in the work (the “Corrective Action Period”). During the Corrective Action Period the Contractor will be allowed an aggregate of [******] days during which the Generating Unit may be taken out of service at Contractor’s request without schedule Liquidated Damages and during which Contractor shall have reasonably unimpeded access to the Subproject in order to correct any such deficiencies (“Outage Days”). Once FirstEnergy has reviewed and approved the Corrective Action Plan the Contractor will implement the plan. FirstEnergy may modify the dates of any Outage Days at FirstEnergy’s sole discretion; however, at the end of the Corrective Action Period, if Contractor has not met the Performance Guarantees and FE has not provided at least [******] Outage Days during the Corrective Action Period, an extension of the Corrective Action Period and the Guaranteed Final Completion Date will be granted in accordance with Section 9.2 to allow scheduling of additional Outage Days. The number of additional Outage Days will be equal to the lessor of (i) the number of Outage Days requested by Contractor and denied by FirstEnergy during the original Corrective Action Period, or (ii) the difference between [******] days and the number of Outage Days actually used by Contractor during the initial Corrective Action Period.

Contractor shall work diligently to minimize the length of any required extension of the Correction Period.

Prior to Final Completion, FirstEnergy will work with the Contractor to allow Contractor additional access to the AQC Unit during any outages that are not related to the Subproject. Such access shall be granted at FirstEnergy’s sole discretion. The AE/Constructor will pay Schedule Liquidated Damages for any Outage Days taken in excess of the permitted [*****] Outage Days as provided in Exhibit 6.5.

Page 2 of 4

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 7.2

Contractor shall use best efforts to obtain, in the contract between the OEM and Contractor, provisions for a Corrective Action Period and Outage Days similar to those provisions above. Contractor and FirstEnergy shall mutually determine the terms of the Corrective Action Period if the foregoing provisions cannot be obtained from an OEM.

PERFORMANCE LIQUIDATED DAMAGES (Wrap Arrangement)

·   SO₂ Emission Removal Rate Guarantee:

The SO₂ removal rate for an AQC Unit should be greater than or equal to the SO₂ Emission Removal Rate Guarantee by the Guaranteed Final Completion Date. If the SO₂ removal rate for an AQC Unit is less than the SO₂ Emission Removal Rate Guarantee, the Contractor shall pay FirstEnergy, as Liquidated Damages, the liquidated damages provided in the contract between the OEM and the Contractor regardless of whether Contractor or its Subcontractors (including the OEM) are at fault (but except to the extent FirstEnergy or FE Vendors are at fault or the Performance Guarantee(s) has changed pursuant to a ChangeOrder) and regardless of the ability of the Contractor to ultimately collect such liquidated damages from the OEM. Contractor shall use best efforts to obtain, in such OEM contract, a liquidated damages rate of [$******] for each 0.1 percentage point by which the actual SO₂ removal rate is less than the SO₂ Emission Removal Rate Guarantee for each AQC Unit,

·   Auxiliary Power Guarantee:

The auxiliary power requirements for an AQC Unit should be less than or equal to the Auxiliary Power Guarantee by the Guaranteed Final Completion Date. If the auxiliary power requirements of an AQC Unit are greater than the Auxiliary Power Guarantee, the Contractor shall pay FirstEnergy, as Liquidated Damages, the liquidated damages provided in the contract between the OEM and the Contractor regardless of whether Contractor or its Subcontractors (including the OEM) are at fault (but except to the extent FirstEnergy or FE Vendors are at fault or the Performance Guarantee(s) has changed pursuant to a ChangeOrder) and regardless of the ability of the Contractor to ultimately collect such liquidated damages from the OEM. Contractor shall use best efforts to obtain, in such OEM contract, a liquidated damages rate of [$******] for each kilowatt by which the actual auxiliary power requirements of an AQC Unit, are greater than the Auxiliary Power Guarantee.

Contractor’s aggregate payment for all Performance Liquidated Damages for the Subproject conducted under the Wrap Arrangement is limited to the amount of the performance liquidated damages provided in the contract between the OEM (for purposes of clarification, it is anticipated that there will be only one (1) OEM for this Subproject) and the Contractor (subject to further limitation by the aggregate overall Liquidated Damages cap provided in such contract as applicable), regardless of whether Contractor or the OEM is at fault (but except to the extent FirstEnergy or FE Vendors are at fault or the Performance Guarantee(s) has changed pursuant to a Change Order) and regardless of the ability of the Contractor to ultimately collect such performance liquidated damages from the OEM, provided that, in the event such cap exceeds[$******], Contractor shall -be required to pay any amount in excess of [$******] in the cumulative aggregate only to the extent such excess is collected from the OEM. Contractor shall use best efforts to obtain, in such OEM contract, a liquidated damages aggregate payment cap of at least[$******].

PERFORMANCE LIQUIDATED DAMAGES (FE Vendor Arrangement)

·   SO₂ Emission Removal Rate Guarantee:

The SO₂ removal rate for an AQC Unit should be greater than or equal to the SO₂ Emission Removal Rate Guarantee negotiated with the OEM by the Guaranteed Final Completion Date. If the SO₂ removal rate for an AQC Unit is less than the SO₂ Emission Removal Rate Guarantee, but only to the extent the Contractor contributes to such shortfall, the Contractor shall payFirstEnergy, as liquidated damages, [$******] for each 0.1 percentage point (i.e., prorated for the extent the Contractor contributed to such shortfall) by which the AQC Unit’s actual SO₂ removal rate is less than the SO₂ Emission Removal Rate Guarantee.

Page 3 of 4

CONFIDENTIAL TREATMENT REQUESTED

EXECUTION COPY

EXHIBIT 7.2

·   Auxiliary Power Guarantee:

The auxiliary power requirements for each AQC Unit should be less than or equal to the Auxiliary Power Guarantee by the Guaranteed Final Completion Date. If the auxiliary power requirements for an AQC unit are greater than the Auxiliary Power Guarantee, but only to the extent the Contractor contributes to such excess, the Contractor shall pay FirstEnergy as Liquidated Damages, [$******] for each kilowatt (i.e., prorated for the extent the Contractor contributed to such shortfall) by which the actual auxiliary power requirements of an AQC Unit are greater than the Auxiliary Power Guarantee.

The parties shall jointly develop a test procedure to reflect the above during the Development Phase of each Subproject.

Page 4 of 4

EXECUTION COPY

EXHIBIT 7.2-1

DESIGN FUEL

Proximate Analysis (As Received)

	Design Fuel	DesignRange
Moisture, wt.%	5.52	5.0 - 15.2
Volatiles, wt.%	37.27	33.0 - 38.0
Ash, wt.%	9.25	7.0 - 10.2
Fixed Carbon, wt.%	49.41	44.0 - 50.0
Sulfur, wt.%	2.57	1.2 - 2.7*
Heat Content, BTU/Lb.	12,962	11,100 - 13,000
SO2, Lb./MMBTU	4.00	2.00 - 4.15

* Uncontrolled SO₂ Lb./MMBTU values will govern design guarantees, not the sulfur wt. % values.

This is FirstEnergy Reliable Information

Page 1 of 1

EXECUTION COPY

EXHIBIT 8.2

W.A. Sammis Plant AQC Project(s)	CSCO No.
Contracted Services Change Order and
Pricing Sheet

Issued To		P.O. No.
Contractor Representative	Location/Unit	Other No.

Initiated By							Date
	Contr	FE Const	Engineering		Purchasing	Other
	Extra Work/Field Change			Design Change		Scope Change
	Price Before Work/Commence Upon Receipt of a Formal Change Order
	Work Before Price/Schedule Urgent/Commence Work Upon Receipt of a Signed Notice to Proceed

Schedule Start Work, This CSCO: Complete Work, This CSCO:

Schedule Impact: Yes No

Comments:

					Estimated by:
Estimated Agreed Price: $			Date:			Contractor
						FirstEnergy
	Cost Reimbursable	T&M Not to Exceed		Firm Price
						Other

Backcharge			To Whom	Contract/PO No.
	Yes	No

Description of Work:
Drawings/Sketches Attached	Yes	NA	No	Previously Transmitted
Revised Specification Attached	Yes	NA	No	Previously Transmitted

Contractor to Coordinate All Work Through:	Phone:
Authorized By:	Date:

Copies to:      TBD

PAGE 1 OF 1

EX-12

					EXHIBIT 12
					Page 1
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2005		2004
	(In thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	145,008	$	102,565
Add -
Interest and other charges, before reduction for
amounts capitalized and deferred interest income		62,105		64,199
Provision for income taxes		112,510		74,066
Interest element of rentals charged to income (a)		5,420		5,318
Earnings as defined	$	325,043	$	246,148
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest on long-term debt	$	56,843	$	62,241
Other interest expense		5,262		1,958
Interest element of rentals charged to income (a)		5,420		5,318
Fixed charges as defined	$	67,525	$	69,517
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		4.81		3.54
(a)  Includes the interest element of rentals calculated at 1/3 of rental expense as no readily defined interest
element can be determined.

171

					EXHIBIT 12
					Page 2
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES PLUS
PREFERRED STOCK DIVIDEND REQUIREMENTS
	Nine Months Ended
	September 30,
	2005		2004
	(In thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	145,008	$	102,565
Add -
Interest and other charges, before reduction for
amounts capitalized and deferred interest income		62,105		64,199
Provision for income taxes		112,510		74,066
Interest element of rentals charged to income (a)		5,420		5,318
Earnings as defined	$	325,043	$	246,148
FIXED CHARGES AS DEFINED IN REGULATION S-K PLUS PREFERRED
STOCK DIVIDEND REQUIREMENTS (PRE-INCOME TAX BASIS)
Interest on long-term debt	$	56,843	$	62,241
Other interest expense		5,262		1,958
Preferred stock dividend requirements		375		375
Adjustment to preferred stock dividends to
state on a pre-income tax basis		291		271
Interest element of rentals charged to income (a)		5,420		5,318
Fixed charges as defined plus preferred stock dividend
requirements (pre-income tax basis)	$	68,191	$	70,163
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
(PRE-INCOME TAX BASIS)		4.77		3.51
(a)   Includes the interest element of rentals calculated at 1/3 of rental expense as no readily defined interest element can be determined.

172

					EXHIBIT 12
METROPOLITAN EDISON COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2005		2004
	(in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	33,144	$	41,786
Add -
Interest and other charges, before reduction for
amounts capitalized and deferred interest income		33,513		34,054
Provision for income taxes		24,159		27,641
Interest element of rentals charged to income (a)		1,279		1,061
Earnings as defined	$	92,095	$	104,542
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest on long-term debt	$	27,887	$	31,208
Other interest expense		5,626		2,846
Interest element of rentals charged to income (a)		1,279		1,061
Fixed charges as defined	$	34,792	$	35,115
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		2.65		2.98
(a)   Includes the interest element of rentals calculated at 1/3 of rental expense as no readily defined interest element can be
determined

173

			EXHIBIT 12
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
	Nine Months Ended
	September 30,
	2005		2004
	(In thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	24,852	$	26,944
Add -
Interest and other charges, before reduction for
amounts capitalized and deferred interest income		29,579		30,591
Provision for income taxes		16,870		15,658
Interest element of rentals charged to income (a)		2,479		1,999
Earnings as defined	$	73,780	$	75,192
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest on long-term debt	$	22,187	$	22,528
Other interest expense		7,392		8,063
Interest element of rentals charged to income (a)		2,479		1,999
Fixed charges as defined	$	32,058	$	32,590
CONSOLIDATED RATIO OF EARNINGS TO FIXED		2.30		2.31
CHARGES
(a)  Includes the interest element of rentals calculated at 1/3 of rental expense as no readily defined interest
element can be determined.

174

EX-15

EXHIBIT 15

November 1, 2005

Securities and Exchange Commission

450 Fifth Street, N.W.

Washington, D.C. 20549

Commissioners:

We are aware that our report dated November 1, 2005 on our review of consolidated interim financial information of FirstEnergy Corp. (the “Company”) as of September 30, 2005 and for the three-month and nine-month periods ended September 30, 2005 and 2004, included in the Company's quarterly report on Form 10-Q for the quarter ended September 30, 2005, is incorporated by reference in its Registration Statements on Form S-3 (Nos. 333-48587, 333-102074 and 333-103865) and Form S-8 (Nos. 333-48651, 333-56094, 333-58279, 333-67798, 333-72764, 333-72766, 333-72768, 333-75985, 333-81183, 333-89356, 333-101472 and 333-110662).

Very truly yours,

PricewaterhouseCoopers LLP

175

EXHIBIT 15

November 1, 2005

Securities and Exchange Commission

450 Fifth Street, N.W.

Washington, D.C. 20549

Commissioners:

We are aware that our report dated November 1, 2005 on our review of consolidated interim financial information of Ohio Edison Company (the “Company”) as of September 30, 2005 and for the three-month and nine-month periods ended September 30, 2005 and 2004, included in the Company's quarterly report on Form 10-Q for the quarter ended September 30, 2005, is incorporated by reference in its Registration Statements on Form S-3 (Nos. 33-49413, 33-51139, 333-01489 and 333-05277).

Very truly yours,

PricewaterhouseCoopers LLP

176

EXHIBIT 15

November 1, 2005

Securities and Exchange Commission

450 Fifth Street, N.W.

Washington, D.C. 20549

Commissioners:

We are aware that our report dated November 1, 2005 on our review of consolidated interim financial information of Pennsylvania Power Company (the “Company”) as of September 30, 2005 and for the three-month and nine-month periods ended September 30, 2005 and 2004, included in the Company's quarterly report on Form 10-Q for the quarter ended September 30, 2005, is incorporated by reference in its Registration Statements on Form S-3 (Nos. 33-62450 and 33-65156).

Very truly yours,

PricewaterhouseCoopers LLP

177

EXHIBIT 15

November 1, 2005

Securities and Exchange Commission

450 Fifth Street, N.W.

Washington, D.C. 20549

Commissioners:

We are aware that our report dated November 1, 2005 on our review of consolidated interim financial information of Pennsylvania Electric Company (the “Company”) as of September 30, 2005 and for the three-month and nine-month periods ended September 30, 2005 and 2004, included in the Company's quarterly report on Form 10-Q for the quarter ended September 30, 2005, is incorporated by reference in its Registration Statements on Form S-3 (Nos. 333-62295, 333-62295-01 and 333-62295-02).

Very truly yours,

PricewaterhouseCoopers LLP

178

EX-31.1

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Metropolitan Edison Company and Pennsylvania Electric Company;
2.	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.	Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this quarterly report;
4.	Each registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for such registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to such registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of such registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in such registrant's internal control over financial reporting that occurred during such registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, such registrant's internal control over financial reporting; and

5. Each registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to such registrant’s auditors and the audit committee of such registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect such registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in such registrant’s internal control over financial reporting.

Date:  November 2, 2005

/s/Anthony J. Alexander

  Anthony J. Alexander

 Chief Executive Officer

179

EX-31.2

Exhibit 31.2

Certification

I, Richard H. Marsh, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company;
2.	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.	Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this quarterly report;
4.	Each registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for such registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to such registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of such registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in such registrant's internal control over financial reporting that occurred during such registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, such registrant's internal control over financial reporting; and

5. Each registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to such registrant’s auditors and the audit committee of such registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect such registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in such registrant’s internal control over financial reporting.

Date:  November 2, 2005

/s/ Richard H. Marsh

 Richard H. Marsh

 Chief Financial Officer

180

EX-31.3

Exhibit 31.3

Certification

I, Stephen E. Morgan, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Jersey Central Power & Light Company;
2.	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3.	Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and we have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial data; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 2, 2005

    /s/  Stephen E. Morgan

            Stephen E. Morgan

            Chief Executive Officer

181

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Quarterly Reports of FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Pennsylvania Power Company, Metropolitan Edison Company, and Pennsylvania Electric Company ("Companies") on Form 10-Q for the period ending September 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Reports"), each undersigned officer of each of the Companies does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) Each of the Reports fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in each of the Reports fairly presents, in all material respects, the financial condition and results of operations of the Company to which it relates.

/s/  Anthony J. Alexander

       Anthony J. Alexander

       Chief Executive Officer

         November 2, 2005

/s/    Richard H. Marsh

        Richard H. Marsh

         Chief Financial Officer

          November 2, 2005

182

EX-32

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Quarterly Report of Jersey Central Power & Light Company ("Company") on Form 10-Q for the period ending September 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Stephen E. Morgan

                    Stephen E. Morgan

                              President

                 (Chief Executive Officer)

 November 2, 2005

/s/ Richard H. Marsh

  Richard H. Marsh

 Senior Vice President and

 Chief Financial Officer

 November 2, 2005

183