PENNSYLVANIA POWER COMPANY

2004 ANNUAL REPORT TO STOCKHOLDERS

Pennsylvania Power Company, an electric utility operating company of FirstEnergy Corp. and a wholly owned subsidiary of Ohio Edison Company, provides electric service to approximately 157,000 customers in western Pennsylvania.

Contents	Page
Glossary of Terms	i-ii
Management Reports	1
Report of Independent Registered Public Accounting Firm	2
Selected Financial Data	3
Management's Discussion and Analysis	4-13
Consolidated Statements of Income	14
Consolidated Balance Sheets	15
Consolidated Statements of Capitalization	16
Consolidated Statements of Common Stockholder's Equity	17
Consolidated Statements of Preferred Stock	17
Consolidated Statements of Cash Flows	18
Consolidated Statements of Taxes	19
Notes to Consolidated Financial Statements	20-35

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify Pennsylvania Power Company and its affiliates:

ATSI	American Transmission Systems, Inc., owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an affiliated Ohio electric utility
Companies	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FirstEnergy	FirstEnergy Corp., a registered public utility holding company
JCP&L	Jersey Central Power & Light Company, an affiliated New Jersey electric utility
Met-Ed	Metropolitan Edison Company, an affiliated Pennsylvania electric utility
OE	Ohio Edison Company, Penn's Ohio electric utility parent company
Penelec	Pennsylvania Electric Company, an affiliated Pennsylvania electric utility
Penn	Pennsylvania Power Company
TE	The Toledo Edison Company, an affiliated Ohio electric utility

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

ALJ	Administrative Law Judge
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB 29	APB Opinion No. 29, "Accounting for Nonmonetary Transactions"
ARB	Accounting Research Bulletin
ARB 43	ARB No. 43, "Restatement and Revision of Accounting Research Bulletins"
ARO	Asset Retirement Obligation
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
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 03-16	EITF Issue No. 03-16, "Accounting for Investments in Limited Liability Companies"
EITF 97-4	EITF Issue No. 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101"
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FMB	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 106-1	FASB Staff Position No.106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"
FSP 106-2	FASB Staff Position No.106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"
FSP 109-1	FASB Staff Position No. 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"
GAAP	Accounting Principles Generally Accepted in the United States
IRS	Internal Revenue Service
KWH	Kilowatt-hours
LOC	Letter of Credit
MACT	Maximum Achievable Control Technologies
Medicare Act	Medicare Prescription Drug, Improvement and Modernization Act of 2003
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Council
NOV	Notices of Violation

i

GLOSSARY OF TERMS, Cont.

NOx	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
PJM	PJM Interconnection L. L. C.
PPUC	Pennsylvania Public Utility Commission
PUCO	Public Utilities Commission of Ohio
PUHCA	Public Utility Holding Company Act
S&P	Standard & Poor’s Ratings Service
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 87	SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 101	SFAS No. 101, "Accounting for Discontinuation of Application of SFAS 71"
SFAS 106	SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS 115	SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
SFAS 143	SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 144	SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS 150	SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity"
SO2	Sulfur Dioxide

ii

MANAGEMENT REPORTS

Management's Responsibility for Financial Statements

The consolidated financial statements were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2004 consolidated financial statements.

FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.

FirstEnergy’s Audit Committee consists of five independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent Registered Public Accounting Firm and is charged with reviewing and approving all services performed for the Company by the independent Registered Public Accounting Firm and for reviewing and approving the related fees. The Committee reviews the independent Registered Public Accounting Firm's report on internal quality control and reviews all relationships between the independent Registered Public Accounting Firm and the Company, in order to assess the Registered Public Accounting Firm's independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held six meetings in 2004.

Management's Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2004. Management’s assessment of the effectiveness of the Company’s internal control over financial reporting, as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 2.

1

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of Pennsylvania Power Company:

We have completed an integrated audit of Pennsylvania Power Company’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Pennsylvania Power Company and its subsidiary at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2(G) to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Cleveland, Ohio

March 7, 2005

2

PENNSYLVANIA POWER COMPANY

SELECTED FINANCIAL DATA

	2004			2003			2002			2001			2000
	(Dollars in thousands)
Operating Revenues	$	549,121		$	526,581		$	506,407		$	498,401		$	383,112
Operating Income	$	60,780		$	47,363		$	60,922		$	55,178		$	39,979
Income Before Cumulative Effect of Accounting Change	$	59,076		$	37,833		$	47,717		$	41,041		$	22,847
Net Income	$	59,076		$	48,451		$	47,717		$	41,041		$	22,847
Earnings on Common Stock	$	56,516		$	45,263		$	44,018		$	37,338		$	19,143
Total Assets	$	921,156		$	879,379		$	907,748		$	960,097		$	988,909
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder’s Equity	$	327,379		$	230,786		$	229,374		$	223,788		$	213,851
Preferred Stock-
Not Subject to Mandatory Redemption		39,105			39,105			39,105			39,105			39,105
Subject to Mandatory Redemption		--			--			13,500			14,250			15,000
Long-Term Debt and Other Long-Term Obligations		133,887			130,358			185,499			262,047			270,368
Total Capitalization	$	500,371		$	400,249		$	467,478		$	539,190		$	538,324
CAPITALIZATION RATIOS:
Common Stockholder’s Equity		65.4	%		57.7	%		49.1	%		41.5	%		39.7	%
Preferred Stock-
Not Subject to Mandatory Redemption		7.8			9.8			8.3			7.3			7.3
Subject to Mandatory Redemption		--			--			2.9			2.6			2.8
Long-Term Debt and Other Long-Term Obligations		26.8			32.5			39.7			48.6			50.2
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KILOWATT-HOUR DELIVERIES
(Millions):
Residential		1,551			1,506			1,533			1,391			1,387
Commercial		1,299			1,283			1,268			1,220			1,198
Industrial		1,573			1,464			1,505			1,540			1,665
Other		7			6			6			6			6
Total		4,430			4,259			4,312			4,157			4,256
CUSTOMERS SERVED:
Residential		138,377			137,170			136,410			134,956			121,066
Commercial		18,730			18,455			18,397			18,153			16,634
Industrial		219			219			220			224			177
Other		85			85			85			87			87
Total		157,411			155,929			155,112			153,420			137,964
NUMBER OF EMPLOYEES		200			201			201			256			275

3

PENNSYLVANIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate," "potential," "expect," "believe," "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), adverse regulatory or legal decisions and outcomes (including revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the Securities and Exchange Commission as disclosed in our Securities and Exchange Commission filings, the availability and cost of capital, the continuing availability and operation of generating units, our ability to experience growth in the distribution business, our ability to access the public securities and other capital markets, further investigation into the causes of the August 14, 2003, regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

Results of Operations

Earnings on common stock in 2004 increased to $57 million from $45 million in 2003. Earnings in 2003 included an after-tax credit of $11 million from the cumulative effect of an accounting change due to the adoption of SFAS 143 (see Note 8). Income before the cumulative effect of an accounting change in 2003 was $38 million. Improved results in 2004 resulted from lower nuclear operating costs, higher operating revenues and reduced net interest charges which were partially offset by higher purchased power costs. Operating revenues were higher in 2004 primarily due to significant increases in wholesale sales to FES. Lower nuclear operating costs in 2004 compared with 2003 were due to the absence of scheduled nuclear refueling outages at Beaver Valley Unit 2 and Perry Plant in 2004.

Earnings on common stock in 2003 increased to $45 million from $44 million in 2002. Income before the cumulative effect of an accounting change in 2003 decreased 21% to $38 million from $48 million in 2002. The lower earnings in 2003 were primarily due to higher nuclear operating costs and purchased power costs. These increased costs were partially offset by higher operating revenues, lower fuel costs and reduced financing costs.

Operating revenues increased by $23 million or 4% in 2004 as compared with 2003. The higher revenues primarily resulted from $14 million of increased wholesale revenues in 2004 (primarily to FES) due to an increase in nuclear generation available for sale and higher retail generation revenues. Sales increased in all retail customer sectors for 2004 compared with 2003. Increased generation sales and higher unit prices resulted in a $15 million increase in generation revenues. Distribution deliveries increased in all customer classes in 2004 compared with 2003 reflecting an improving economy in our service area; lower unit prices more than offset the effect of the higher deliveries in 2004, resulting in a $6 million decrease in revenues. Higher deliveries to the steel sector in 2004 were principally responsible for the increase in kilowatt-hour sales to industrial customers.

Operating revenues increased by $20 million or 4% in 2003 as compared with 2002. The higher revenues primarily resulted from increased wholesale revenues of $25 million in 2003, along with higher retail generation sales revenues of $3 million due to higher unit prices, partially offset by a 1% decrease in retail kilowatt-hour sales. These electric generation revenue increases were partially offset by $5 million of lower revenues from distribution deliveries. Wholesale revenue increases from sales to FES reflected higher unit prices, which were partially offset by lower kilowatt-hour sales due to reduced nuclear generation available for sale to FES.

Changes in electric generation and distribution deliveries in 2004 and 2003 compared to the prior years are summarized in the following table:

4

Changes in KWH Sales	2004			2003
Increase (Decrease)
Electric Generation:
Retail		4.1	%		(1.0	)%
Wholesale		10.9	%		(11.6	)%
Total Electric Generation Sales		8.0	%		(7.4	)%
Distribution Deliveries:
Residential		3.0	%		(1.8	)%
Commercial		1.3	%		1.1	%
Industrial		7.5	%		(2.7	)%
Total Distribution Deliveries		4.0	%		(1.3	)%

Operating Expenses and Taxes

Total operating expenses and taxes increased by $9 million in 2004 and $34 million in 2003 from the prior year. The following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes	2004			2003
Increase (Decrease)	(In millions)
Fuel costs	$	1		$	(4	)
Purchased power costs		15			9
Nuclear operating costs		(22	)		39
Other operating costs		(2	)		2
Provision for depreciation		1			(2	)
Amortization of regulatory assets		--			(1	)
General taxes		1			(2	)
Income taxes		15			(7	)
Total operating expenses and taxes	$	9		$	34

Higher fuel costs in 2004 compared with 2003 resulted from increased nuclear generation in 2004. Purchased power costs increased in 2004 compared with 2003 as a result of a $15 million increase in power purchased from FES, reflecting higher unit prices and higher kilowatt-hour purchases due to increased retail generation requirements. Nuclear operating costs decreased $22 million, primarily due to one scheduled refueling outage in 2004 compared to three scheduled refueling outages in 2003.

Lower fuel costs in 2003, compared with 2002, resulted from reduced nuclear generation. The increased purchased power costs in 2003 reflected higher unit costs and increased kilowatt-hour purchases. Higher nuclear operating costs occurred, in large part, due to three scheduled refueling outages in 2003, compared with one scheduled refueling outage in 2002.

Depreciation charges were relatively unchanged in 2004 compared to the prior year while depreciation decreased by $2 million in 2003 compared with 2002, primarily from lower charges resulting from the implementation of SFAS 143, ($1 million for 2003) and revised service life assumptions for nuclear generating plants ($1 million for 2003).

General taxes decreased $2 million in 2003 from 2002 principally due to settled property tax claims.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $7 million in 2004 and by $3 million in 2003, compared with the prior years. We continued to redeem and refinance outstanding debt, with 2004 redemptions totaling $64 million (including mandatorily redeemable preferred stock). In 2003, redemptions totaled $42 million (including mandatorily redeemable preferred stock).

Cumulative Effect of Accounting Change

Upon adoption of SFAS 143 in 2003, we recorded an after-tax credit to net income of $11 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was an $18 million increase to income, or $11 million net of income taxes.

5

Capital Resources and Liquidity

Our cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions were met without increasing our net debt and preferred stock outstanding. We received $65 million of equity contributions from OE in the second half of 2004. During 2005 and thereafter, we expect to meet our contractual obligations with a combination of cash from operations and funds from the capital markets.

Changes in Cash Position

As of December 31, 2004, we had $38,000 of cash and cash equivalents, compared with $40,000 as of December 31, 2003. The major sources for changes in these balances are summarized below.

Cash Flows From Operating Activities

Net cash provided from operating activities was $115 million in 2004, $116 million in 2003 and $105 million in 2002. Cash provided from 2004, 2003 and 2002 operating activities are as follows:

Operating Cash Flows	2004			2003		2002
	(In millions)
Cash earnings (1)	$	140		$	99	$	119
Pension trust contribution(2)		(8	)		--		--
Working capital and other		(17	)		17		(14	)
Total	$	115		$	116	$	105

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

⁽²⁾ Pension trust contribution net of $5 million of income tax benefits.

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

Reconciliation of Cash Earnings	2004		2003			2002
	(In millions)
Net Income (GAAP)	$	59	$	48		$	48
Non-Cash Charges (Credits):
Provision for depreciation		14		13			15
Amortization of regulatory assets		40		41			42
Nuclear fuel and capital lease amortization		17		16			19
Deferred income taxes and investment      tax credits, net		--		(5	)		(8	)
Cumulative effect of accounting change		--		(18	)		--
Other non-cash expenses		10		4			3
Cash earnings (Non-GAAP)	$	140	$	99		$	119

Net cash from operating activities decreased $1 million in 2004 compared with 2003 due to a $34 million comparative change in working capital and an $8 million after-tax voluntary pension trust contribution, partially offset by a $41 million increase in cash earnings as described above under "Results of Operations". The working capital decrease was due to changes of $14 million in receivables and $28 million in accrued tax balances partially offset by an $18 million increase in accounts payable.

Net cash from operating activities increased $11 million in 2003 compared with 2002 due to a $31 million increase in working capital, partially offset by a $20 million decrease in cash earnings as described above under "Results of Operations". Working capital increased principally as a result of changes of $25 million in receivables and $21 million of accrued tax balances partially offset by an $18 million decrease in accounts payable.

6

Cash Flows From Financing Activities

Net cash used for financing activities decreased to $25 million in 2004 from $76 million in 2003. This decrease primarily reflects a $65 million equity contribution from OE and a $19 million reduction of common stock dividends to OE. Net cash used for financing activities in 2003 was unchanged from 2002 with a $14 million increase in dividends to OE offsetting a $13 million reduction in net debt redemptions.

Securities Issued or Redeemed	2004		2003		2002
	(In millions)
New Issues
Pollution Control Notes	$	--	$	--	$	15
Short-Term Borrowings, Net		1		11		--
Redemptions
First Mortgage Bonds	$	63	$	41	$	1
Pollution Control Notes		--		--		15
Capital Fuel Leases		--		--		41
Preferred Stock		1		1		1
Other		1		--		--
	$	65	$	42	$	58

In 2002, net cash used for financing activities totaled $75 million, primarily due to long-term debt redemptions and $32 million of dividend payments.

We had $469,000 of cash and temporary investments (which include short-term notes receivable from associated companies) and $12 million of short-term indebtedness with associated companies as of December 31, 2004. We have obtained authorization from the SEC to incur short-term debt up to our charter limit of $51 million (including the utility money pool). We have the capability to issue $515 million of additional FMB on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests, we could issue up to $424 million of preferred stock (assuming no additional debt was issued) as of December 31, 2004.

We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy’s and OE’s revolving credit facilities. 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 2004 was 1.43%.

In March 2004, we completed, through a separate wholly owned subsidiary, a receivables financing arrangement that provides borrowing capability of up to $25 million. The borrowing rate is based on bank commercial paper rates. We are required to pay an annual facility fee of 0.40% on the entire finance limit. The facility was undrawn as of December 31, 2004 and matures on March 29, 2005. This receivables financing arrangement is expected to be renewed prior to expiration.

On December 1, 2004, Ohio Water Development Authority Series 1999-A pollution control notes aggregating $5.2 million were remarketed in a Dutch Auction interest mode and insured with municipal bond insurance.

Our access to capital markets and costs of financing are dependent on the ratings of our securities and the securities of OE and FirstEnergy. The following table shows securities ratings as of December 31, 2004. The ratings outlook on all securities is stable.

Ratings of Securities
	Securities	S&P	Moody’s	Fitch
FirstEnergy	Senior unsecured	BB+	Baa3	BBB-
OE	Senior secured	BBB	Baa1	BBB+
	Senior unsecured	BB+	Baa2	BBB
	Preferred stock	BB	Ba1	BBB-
Penn	Senior secured	BBB	Baa1	BBB+
	Senior unsecured (1)	BB+	Baa2	BBB
	Preferred stock	BB	Ba1	BBB-

(1) Penn’s only senior unsecured debt obligations are pollution control revenue refunding bonds issued in the name of the Ohio Air Quality Development Authority to which this rating applies.

7

On December 10, 2004, S&P reaffirmed FirstEnergy's ‘BBB-' corporate credit rating and kept the outlook stable. S&P noted that the stable outlook reflects FirstEnergy's improving financial profile and cash flow certainty through 2006. S&P stated that should the two refueling outages at the Davis-Besse and Perry nuclear plants scheduled for the first quarter of 2005 be completed successfully without any significant negative findings and delays, FirstEnergy's outlook would be revised to positive. S&P also stated that a ratings upgrade in the next several months did not seem likely, as remaining issues of concern to S&P, primarily the outcome of environmental litigation and SEC investigations, are not likely to be resolved in the short term.

Cash Flows From Investing Activities

Net cash used in investing activities totaled $90 million in 2004 compared to $41 million in 2003. The $49 million increase in 2004 reflects $22 million of increased property additions and a reduction of $28 million in loan repayments from associated companies. Expenditures for property additions include expenditures supporting our distribution of electricity.

Net cash used in investing activities increased to $41 million in 2003 from $28 million in 2002. The $13 million increase in 2003 reflects $25 million of increased property additions, partially offset by a $15 million increase in loan repayments from associated companies.

Our capital spending for the period 2005-2007 is expected to be about $227 million (excluding nuclear fuel) of which approximately $82 million applies to 2005. Investments for additional nuclear fuel during the 2005-2007 period are estimated to be approximately $63 million, of which about $13 million relates to 2005. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $52 million and $17 million, respectively, as the nuclear fuel is consumed. We had no other material obligations as of December 31, 2004 that have not been recognized on our Consolidated Balance Sheet.

Contractual Obligations

As of December 31, 2004, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

Contractual Obligations	Total		2005		2006-2007		2008-2009		Thereafter
	(In millions)
Long-term debt (3)	$	148	$	1	$	2	$	2	$	143
Preferred stock (1)		13		1		12		--		--
Short-term borrowings		12		12		--		--		--
Operating leases		1		--		--		--		1
Purchases (2)		81		13		49		19		--
Total	$	255	$	27	$	63	$	21	$	144

⁽¹⁾ Subject to mandatory redemption.

⁽²⁾ Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.

⁽³⁾  Amounts reflected do not include interest on long-term debt.

Interest Rate Risk

Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the following table.

The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.

8

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2005			2006			2007			2008			2009			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents-
Fixed Income							$	1		$	1		$	1		$	116		$	119		$	125
Average interest rate								7.8	%		7.8	%		7.8	%		5.5	%		5.5	%
Liabilities
Long-term Debt and Other Long-Term Obligations:
Fixed rate	$	1		$	1		$	1		$	1		$	1		$	81		$	86		$	98
Average interest rate		9.7	%		9.7	%		9.7	%		9.7	%		9.7	%		6.4	%		6.6	%
Variable rate																$	62		$	62		$	62
Average interest rate																	2.1	%		2.1	%
Preferred Stock Subject to Mandatory Redemption	$	1		$	1		$	11											$	13		$	12
Average dividend rate		7.6	%		7.6	%		7.6	%											7.6	%
Short-term Borrowings	$	12																	$	12		$	12
Average interest rate		2.0	%																	2.0	%

Equity Price Risk

Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $57 million and $50 million as of December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of December 31, 2004 (see Note 4 - Fair Value of Financial Instruments).

Outlook

We have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated.

Regulatory Matters

Pennsylvania enacted its electric utility competition law in 1996 with the phase in of customer choice for electric generation suppliers completed as of January 1, 2001. We continue to deliver power to homes and businesses through our distribution system, which remains regulated by the PPUC. Our rates have been restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of our rates is excluded from their bill and the customers receive a generation charge from the alternative supplier. The stranded cost recovery portion of rates provides for recovery of certain amounts not otherwise considered recoverable in a competitive generation market, including regulatory assets. Under the rate restructuring plan, we are entitled to recover $236 million of stranded costs through the CTC that began in 1999 and ends in 2006.

On January 16, 2004, the PPUC initiated a formal investigation of whether our "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, we filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, we, Met-Ed and Penelec agreed to enhance service reliability, ongoing periodic performance reporting and communications with customers and to collectively maintain our current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. The settlement also outlines an expedited remediation process to address any alleged non-compliance with terms of the settlement and an expedited PPUC hearing process if remediation is unsuccessful. On November 4, 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.

See Note 6 to the consolidated financial statements for a complete and detailed discussion of regulatory matters.

9

Environmental Matters

We believe we are in compliance with current SO₂ and NO_x reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the EPA finalized regulations requiring additional NO_x reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NO_x reduction requirements (see Note 10(B) - Environmental Matters). We continue to evaluate our compliance plans and other compliance options.

Clean Air Act Compliance-

We are 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. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

We believe we are 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. NOx 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 our facilities. The EPA's NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85% reduction in utility plant NO_x emissions from projected 2007 emissions) across a region of nineteen states (including 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. We believe our facilities are also complying with NO_x budgets established under State Implementation Plans (SIP) through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards-

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 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. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NO_x and SO₂ emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO₂ emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NO_x emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which we 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 December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.

10

W. H. Sammis Plant-

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included 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. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase of the trial to address any civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's, OE's and our respective financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.

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.

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% through 2012.

We 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 us is lower than many regional competitors due to our diversified generation sources which includes 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 the company's plants. In addition, Ohio and Pennsylvania have water quality standards applicable to the Companies' 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 and Pennsylvania have assumed such authority.

On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) 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. We are conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by our facilities with the performance standards. Management 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.

11

Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to our normal business operations pending against us. The most significant are described below.

On August 12, 2004, the NRC notified FENOC that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, in which we own a 5.24% interest. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased oversight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC's corrective actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

Critical Accounting Policies

We prepare our consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of our assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Our more significant accounting policies are described below.

Regulatory Accounting

We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on costs that the regulatory agencies determine we are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets and liabilities based on anticipated future cash inflows and outflows. We regularly review these assets and liabilities to assess their ultimate disposition within the approved regulatory guidelines. Impairment risk associated with regulations assets relates to potentially adverse legislative, judicial or regulatory actions in the future.

Revenue Recognition

We follow the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, weather-related impacts, prices in effect for each customer class and electricity provided by alternative suppliers.

Pension and Other Postretirement Benefits Accounting

Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations, which impact employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.

In accordance with SFAS 87, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience.

In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, we reduced the assumed discount rate as of December 31, 2004 to 6.00% from 6.25% and 6.75% used as of December 31, 2003 and 2002, respectively.

12

Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2004, 2003 and 2002, plan assets actually earned 11.1%, 24.2% and (11.3)%, respectively. Our pension costs in 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and a pension trust investment allocation of approximately 68% equities, 29% bonds, 2% real estate and 1% cash.

In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan (our share was $13 million). Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. FirstEnergy's election to pre-fund the plan is expected to eliminate that funding requirement.

As a result of our voluntary contribution and the increased market value of pension plan assets, we reduced our accrued benefit cost as of December 31, 2004 by $8 million. As prescribed by SFAS 87, we increased our additional minimum liability by $4 million, recording an increase in an intangible asset of $1 million and charging $3 million to OCI. The balance in AOCL of $14 million (net of $10 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2005 composite health care trend rate assumptions are approximately 10%-12% and 9%-11%, respectively, gradually decreasing to 5% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates.

Long-Lived Assets

In accordance with SFAS 144, we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows).

The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment.

Nuclear Decommissioning

In accordance with SFAS 143, we recognize an ARO for the future decommissioning of our nuclear power plants. The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. We used an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for EITF 03-1, which provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, the Company will continue to evaluate its investments as required by existing authoritative guidance.

13

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
OPERATING REVENUES (Note 2(I))	$	549,121		$	526,581		$	506,407
OPERATING EXPENSES AND TAXES:
Fuel		22,894			21,443			25,180
Purchased power (Note 2(I))		181,031			165,643			156,788
Nuclear operating costs		106,659			128,895			90,024
Other operating costs (Note 2(I))		51,180			52,809			50,523
Provision for depreciation		14,134			13,017			15,197
Amortization of regulatory assets		40,012			40,789			41,566
General taxes		23,607			22,458			24,474
Income taxes		48,824			34,164			41,733
Total operating expenses and taxes		488,341			479,218			445,485
OPERATING INCOME		60,780			47,363			60,922
OTHER INCOME (NET OF INCOME TAXES) (Note 2(I))		3,464			2,807			1,960
NET INTEREST CHARGES:
Interest on long-term debt		8,250			14,228			15,521
Allowance for borrowed funds used during construction		(4,563	)		(3,189	)		(1,509	)
Other interest expense		1,481			1,298			1,153
Net interest charges		5,168			12,337			15,165
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		59,076			37,833			47,717
Cumulative effect of accounting change (net of income taxes of $7,532,000)
(Note 2(G))		--			10,618			--
NET INCOME		59,076			48,451			47,717
PREFERRED STOCK DIVIDEND REQUIREMENTS		2,560			3,188			3,699
EARNINGS ON COMMON STOCK	$	56,516		$	45,263		$	44,018

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

14

PENNSYLVANIA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

As of December 31,	2004		2003
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	866,303	$	808,637
Less-Accumulated provision for depreciation		356,020		324,710
		510,283		483,927
Construction work in progress-
Electric plant		104,366		68,091
Nuclear fuel		3,362		360
		107,728		68,451
		618,011		552,378
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts (Note 4)		143,062		133,867
Long-term notes receivable from associated companies		32,985		39,179
Other		722		2,195
		176,769		175,241
CURRENT ASSETS:
Cash and cash equivalents		38		40
Notes receivable from associated companies		431		399
Receivables-
Customers (less accumulated provisions of $888,000 and $769,000,
respectively, for uncollectible accounts)		44,282		44,861
Associated companies		23,016		24,965
Other		1,656		1,047
Materials and supplies, at average cost		37,923		33,918
Prepayments and other		8,924		9,383
		116,270		114,613
DEFERRED CHARGES:
Regulatory assets		--		27,513
Other		10,106		9,634
		10,106		37,147
	$	921,156	$	879,379
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder’s equity	$	327,379	$	230,786
Preferred stock not subject to mandatory redemption		39,105		39,105
Long-term debt and other long-term obligations		133,887		130,358
		500,371		400,249
CURRENT LIABILITIES:
Currently payable long-term debt		26,524		93,474
Accounts payable-
Associated companies		46,368		40,172
Other		1,436		1,294
Notes payable to associated companies		11,852		11,334
Accrued taxes		14,055		27,091
Accrued interest		1,872		4,396
Other		8,802		8,444
		110,909		186,205
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		93,418		97,871
Accumulated deferred investment tax credits		3,222		3,516
Asset retirement obligation		138,284		129,546
Retirement benefits		49,834		54,057
Regulatory liabilities		18,454		--
Other		6,664		7,935
		309,876		292,925
COMMITMENTS AND CONTINGENCIES (Notes 5 and 10)
	$	921,156	$	879,379

The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

15

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

As of December 31,	2004				2003
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER’S EQUITY:
Common stock, $30 par value, 6,500,000 shares authorized, 6,290,000 shares outstanding	$	188,700		$	188,700
Other paid-in capital		64,690			(310)	)
Accumulated other comprehensive loss (Note 2(F))		(13,706	)		(11,783	)
Retained earnings (Note 7(A))		87,695			54,179
Total common stockholder’s equity		327,379			230,786

	Number of Shares				Optional
	Outstanding				Redemption Price
	2004		2003		Per Share		Aggregate
PREFERRED STOCK (Note 7(B)):
Cumulative, $100 par value-
Authorized 1,200,000 shares
4.24%		40,000		40,000	$	103.13	$	4,125		4,000			4,000
4.25%		41,049		41,049		105.00		4,310		4,105			4,105
4.64%		60,000		60,000		102.98		6,179		6,000			6,000
7.75%		250,000		250,000		100.00		25,000		25,000			25,000
Total		391,049		391,049			$	39,614		39,105			39,105
LONG-TERM DEBT AND OTHER
LONG-TERM OBLIGATIONS (Note 7(C)):
First mortgage bonds-
9.740% due 2005-2019										14,643			15,617
6.375% due 2004										--			20,500
6.625% due 2004										--			14,000
8.500% due 2022										--			27,250
7.625% due 2023										6,500			6,500
Total first mortgage bonds										21,143			83,867
Secured notes-
5.400% due 2013										1,000			1,000
5.400% due 2017										10,600			10,600
*  1.700% due 2017										17,925			17,925
5.900% due 2018										16,800			16,800
*  1.700% due 2021										14,482			14,482
6.150% due 2023										12,700			12,700
*  2.000% due 2027										10,300			10,300
5.375% due 2028										1,734			1,734
5.450% due 2028										6,950			6,950
6.000% due 2028										14,250			14,250
5.950% due 2029										238			238
*   1.800% due 2033										5,200			--
Total secured notes										112,179			106,979
Unsecured notes-
*3.375% due 2029										14,500			14,500
*5.900% due 2033										--			5,200
Total unsecured notes										14,500			19,700
Preferred stock subject to mandatory redemption										12,750			13,500
Net unamortized discount on debt										(161	)		(214	)
Long-term debt due within one year										(26,524	)		(93,474	)
Total long-term debt and other long-  term obligations										133,887			130,358
TOTAL CAPITALIZATION									$	500,371		$	400,249

* Denotes variable rate issue with December 31, 2004 interest rate shown.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

16

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

											Accumulated
								Other			Other
	Comprehensive			Number		Par		Paid-In			Comprehensive				Retained
	Income			of Shares		Value		Capital			Income (Loss)				Earnings
	(Dollars in thousands)
Balance, January 1, 2002					6,290,000	$	188,700	$	(310	)	$	--		$	35,398
Net income	$	47,717													47,717
Minimum liability for unfunded retirement
benefits, net of $(7,045,000) of
income taxes		(9,932	)									(9,932	)
Comprehensive income	$	37,785
Cash dividends on preferred stock															(3,699	)
Cash dividends on common stock															(28,500	)
Balance, December 31, 2002					6,290,000		188,700		(310	)		(9,932	)		50,916
Net income	$	48,451													48,451
Minimum liability for unfunded retirement
benefits, net of $(1,290,000) of
income taxes		(1,851	)									(1,851	)
Comprehensive income	$	46,600
Cash dividends on preferred stock															(3,188	)
Cash dividends on common stock															(42,000	)
Balance, December 31, 2003					6,290,000		188,700		(310	)		(11,783	)		54,179
Net income	$	59,076													59,076
Minimum liability for unfunded retirement
benefits, net of $(1,372,000) of
income taxes		(1,923	)									(1,923	)
Comprehensive income	$	57,153
Cash dividends on preferred stock															(2,560	)
Cash dividends on common stock															(23,000	)
Equity contribution from parent									65,000
Balance, December 31, 2004					6,290,000	$	188,700	$	64,690		$	(13,706	)	$	87,695

CONSOLIDATED STATEMENTS OF PREFERRED STOCK

	Not Subject to				Subject to
	Mandatory Redemption				Mandatory Redemption
	Number		Par		Number			Par
	of Shares		Value		of Shares			Value
	(Dollars in thousands)
Balance, January 1, 2002		391,049	$	39,105		150,000		$	15,000
Redemptions-
7.625% Series						(7,500	)		(750	)
Balance, December 31, 2002		391,049		39,105		142,500			14,250
Redemptions-
7.625% Series						(7,500	)		(750	)
Balance, December 31, 2003		391,049		39,105		135,000			13,500	*
Redemptions-
7.625% Series						(7,500	)		(750	)
Balance, December 31, 2004		391,049	$	39,105		127,500		$	12,750	*

* Preferred stock subject to mandatory redemption is classified as debt under SFAS 150.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

17

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	59,076		$	48,451		$	47,717
Adjustments to reconcile net income to net cash from operating activities:
Provision for depreciation		14,134			13,017			15,197
Amortization of regulatory assets		40,012			40,789			41,566
Nuclear fuel and lease amortization		16,790			15,947			19,204
Deferred income taxes and investment tax credits, net		5,011			(5,228	)		(7,932	)
Cumulative effect of accounting change (Note 2(G))		--			(18,150	)		--
Pension trust contribution		(12,934	)		--			--
Decrease (Increase) in operating assets:
Receivables		1,919			16,276			(8,434	)
Materials and supplies		(4,005	)		(3,609	)		(4,711	)
Prepayments and other current assets		459			(4,037	)		336
Increase (Decrease) in operating liabilities:
Accounts payable		6,338			(11,163	)		6,338
Accrued taxes		(13,036	)		14,584			(6,346	)
Accrued interest		(2,524	)		(1,162	)		294
Asset retirement obligation, net		(1,242	)		4,112			--
Other		5,097			5,814			1,361
Net cash provided from operating activities		115,095			115,641			104,590
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		--			--			14,500
Short-term borrowings, net		518			11,334			--
Equity contribution from parent		65,000			--			--
Redemptions and Repayments-
Preferred stock		(750	)		(750	)		(750	)
Long-term debt		(63,903	)		(41,155	)		(56,837	)
Dividend Payments-
Common stock		(23,000	)		(42,000	)		(28,500	)
Preferred stock		(2,560	)		(3,188	)		(3,699	)
Net cash used for financing activities		(24,695	)		(75,759	)		(75,286	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(93,320	)		(70,864	)		(46,060	)
Contributions to nuclear decommissioning trusts		(1,594	)		(1,594	)		(1,594	)
Loan repayments from associated companies		6,162			34,660			19,463
Other		(1,650	)		(3,266	)		42
Net cash used for investing activities		(90,402	)		(41,064	)		(28,149	)
Net increase (decrease) in cash and cash equivalents		(2	)		(1,182	)		1,155
Cash and cash equivalents at beginning of year		40			1,222			67
Cash and cash equivalents at end of year	$	38		$	40		$	1,222
SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash paid during the year-
Interest (net of amounts capitalized)	$	6,885		$	12,449		$	13,771
Income taxes	$	68,869		$	33,502		$	60,078

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

18

PENNSYLVANIA POWER COMPANY

CONSOLIDATED STATEMENTS OF TAXES

For the Years Ended December 31,	2004			2003			2002
	(In thousands)
GENERAL TAXES:
State gross receipts*	$	19,234		$	18,028		$	18,516
Real and personal property		1,288			2,262			3,729
State capital stock		2,014			952			1,357
Social security and unemployment		1,046			878			750
Other		25			338			122
Total general taxes	$	23,607		$	22,458		$	24,474
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	33,273		$	37,351		$	38,972
State		11,468			11,368			12,004
		44,741			48,719			50,976
Deferred, net-
Federal		5,552			(2,424	)		(4,144	)
State		1,693			(392	)		(1,193	)
		7,245			(2,816	)		(5,337	)
Investment tax credit amortization		(2,234	)		(2,412	)		(2,595	)
Total provision for income taxes	$	49,752		$	43,491		$	43,044
INCOME STATEMENT CLASSIFICATION OF PROVISION FOR
INCOME TAXES:
Operating income	$	48,824		$	34,164		$	41,733
Other income		928			1,795			1,311
Cumulative effect of accounting change		--			7,532			--
Total provision for income taxes	$	49,752		$	43,491		$	43,044
RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	108,828		$	91,942		$	90,761
Federal income tax expense at statutory rate	$	38,090		$	32,180		$	31,766
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit		8,555			7,134			7,027
Amortization of investment tax credits		(2,234	)		(2,412	)		(2,595	)
Amortization of tax regulatory assets		5,308			5,616			5,967
Other, net		33			973			879
Total provision for income taxes	$	49,752		$	43,491		$	43,044
ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Competitive transition charge	$	18,862		$	37,280		$	56,172
Property basis differences		87,584			77,147			72,488
Allowance for equity funds used during construction		--			--			1,045
Customer receivables for future income taxes		1,471			2,860			4,249
Unamortized investment tax credits		(1,335	)		(1,457	)		(1,578	)
Deferred gain for asset sale to affiliated company		7,451			8,106			8,810
Other comprehensive income		(9,707	)		(8,335	)		(7,045	)
Other		(10,908	)		(17,730	)		(16,756	)
Net deferred income tax liability	$	93,418		$	97,871		$	117,385

* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND BASIS OF PRESENTATION:

The consolidated financial statements include Penn (Company) and its wholly owned subsidiary, Penn Power Funding LLC. The Company is a wholly owned subsidiary of OE. The Company follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC, PPUC and FERC. OE is a wholly owned subsidiary of FirstEnergy. 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 the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain 2003 revenues and expenses have been reclassified and presented on a net basis to conform with the current year presentation.

The Company consolidates all majority-owned subsidiaries over which the Company exercises control and, when applicable, entities for which the Company has a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which the Company has the ability to exercise significant influence, but not control, are accounted for on the equity basis.

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

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

(A)   ACCOUNTING FOR THE EFFECTS OF REGULATION-

The Company accounts for the effects of regulation through the application of SFAS 71 when its rates:

· are established by a third-party regulator with the authority to set rates that bind customers;

· are cost-based; and

· can be charged to and collected from customers.

An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. SFAS 71 is applied only to the parts of the business that meet the above criteria. If a portion of the business applying SFAS 71 no longer meets those requirements, previously recorded regulatory assets are removed from the balance sheet in accordance with the guidance in SFAS 101.

Regulatory Assets and Liabilities-

The Company recognizes, as regulatory assets, costs which the FERC and PPUC 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 Company’s rate restructuring plan. Based on the rate restructuring plan, the Company continues to bill and collect cost-based rates relating to the Company’s nongeneration operations and continues the application of SFAS 71 to these operations.

Net regulatory assets (liabilities) on the Consolidated Balance Sheets are comprised of the following:

	2004			2003
	(In millions)
Competitive transition costs	$	46		$	90
Customer receivables for future income taxes		4			7
Loss on reacquired debt.		7			6
Employee postretirement benefit costs		1			2
Nuclear decommissioning costs		(69	)		(72	)
Asset removal costs		(7	)		(6	)
Other		--			1
Net regulatory assets (liabilities)	$	(18	)	$	28

20

Accounting for Generation Operations-

The application of SFAS 71 was discontinued in 1998 with respect to the Company's generation operations. The SEC's interpretive guidance regarding asset impairment measurement provided that any supplemental regulated cash flows such as a CTC should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance and EITF 97-4, $227 million of impaired plant investments were recognized by the Company as regulatory assets recoverable through a CTC over a seven-year transition period. Net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued were $263 million as of December 31, 2004.

(B)   CASH AND SHORT-TERM FINANCIAL INSTRUMENTS-

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Noncash financing and investing activities included capital lease transactions amounting to $1.5 million for 2002. There were no capital lease transactions in 2004 and 2003.

(C)   REVENUES AND RECEIVABLES-

The Company's principal business is providing electric service to customers in western Pennsylvania. The Company's retail customers are metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided between the last meter reading and the end of the month. This estimate includes many factors including estimated weather impacts, customer shopping activity, historical line loss factors and prices in effect for each class of customer. In each accounting period, the Company accrues the estimated unbilled amount receivable as revenue and reverses the related prior period estimate.

Receivables from customers include sales to residential, commercial and industrial customers located in the Company’s service area and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2004 or 2003, with respect to any particular segment of the Company’s customers. Total customer receivables were $44 million (billed - $28 million and unbilled - $16 million) and $45 million (billed - $29 million and unbilled - $16 million) as of December 31, 2004 and 2003, respectively.

(D)   UTILITY PLANT AND DEPRECIATION-

Utility plant reflects original cost of construction (except for nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred.

The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for electric plant was approximately 2.2% in 2004 and 2003 and 2.3% in 2002.

Jointly - Owned Generating Stations-

The Company, together with OE and other affiliated companies, CEI and TE, own, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly - owned facility in the same proportion as its interest. The Company’s portion of operating expenses associated with jointly - owned facilities is included in the corresponding operating expenses on the Statements of Income. The amounts reflected on the Consolidated Balance Sheet under utility plant as of December 31, 2004 include the following:

	Utility		Accumulated		Construction		Company's
	Plant		Provision for		Work in		Ownership
Generating Units	in Service		Depreciation		Progress		Interest
	(In millions)
W. H. Sammis Unit 7	$	64	$	24	$	--		20.80	%
Bruce Mansfield Units 1, 2 and 3		187		102		--		16.38	%
Beaver Valley Units 1 and 2		158		27		94		39.37	%
Perry		10		2		1		5.24	%
Total	$	419	$	155	$	95

Nuclear Fuel-

Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Company amortizes the cost of nuclear fuel based on the units of production method.

21

Asset Retirement Obligations-

The Company recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143. This standard requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and depreciated over time, as described further in Note 8, "Asset Retirement Obligations".

(E)   ASSET IMPAIRMENTS-

Long-Lived Assets-

The Company evaluates the carrying value of its long-lived assets when events or circumstances indicate that the carrying amount may not be recoverable. In accordance with SFAS 144, the carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If an impairment exists, a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Fair value is estimated by using available market valuations or the long-lived asset's expected future net discounted cash flows. The calculation of expected cash flows is based on estimates and assumptions about future events.

Investments-

The Company periodically evaluates for impairment investments that include available-for-sale securities held by its nuclear decommissioning trusts. In accordance with SFAS 115, securities classified as available-for-sale are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. If the decline in fair value is determined to be other than temporary, the cost basis of the security is written down to fair value. The Company considers, among other factors, the length of time and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. The fair value and unrealized gains and losses of the Company's investments are disclosed in Note 4.

(F)   COMPREHENSIVE INCOME-

Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with OE and preferred stockholders. As of December 31, 2004 and 2003, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $14 million and $12 million, respectively.

(G)   CUMULATIVE EFFECT OF ACCOUNTING CHANGE-

Results for 2003 include an after-tax credit to net income of $10.6 million recorded upon the adoption of SFAS 143 in January 2003. The Company identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $78 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $9 million. The ARO liability at the date of adoption was $121 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, the Company had recorded decommissioning liabilities of $120 million. The Company expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, it recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts subject to refund through rates related to the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was an $18.2 million increase to income, or $10.6 million net of income taxes. If SFAS 143 had been applied during 2002, the impact would not have been material to the Company's Consolidated Statements of Income.

(H)   INCOME TAXES-

Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a åstand-aloneæ company basis, with the Company recognizing any tax losses or credits it contributed to the consolidated return.

22

(I)   TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily ATSI, FES and FESC. FES operates the generation businesses of the Company, OE, CEI and TE. As a result, the Company entered into power supply agreements (PSA) whereby FES purchases all of the Company's nuclear generation and the Company purchases its power from FES to meet its "provider of last resort" obligations. In the fourth quarter of 2003, ATSI transferred operational control of its transmission facilities to MISO and previously affiliated transmission service expenses are now provided under the MISO Open Access Transmission Tariff. In 2002, the Company terminated its nuclear fuel leasing arrangement with OES Fuel and now owns its nuclear fuel. The primary affiliated companies transactions are as follows:

	2004		2003		2002
	(In millions)
Operating Revenues:
PSA revenues from FES	$	177	$	162	$	138
Generating units rent from FES		20		20		20
Ground lease with ATSI		1		1		1
Operating Expenses:
Nuclear fuel leased from OES Fuel		--		--		5
Purchased power under PSA		181		166		157
Transmission facilities rentals		--		10		13
FESC support services		15		13		9
Other Income:
Interest income from ATSI		3		3		3
Interest income from FES		--		1		1

FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, a subsidiary of FirstEnergy Corp. and a "mutual service company" as defined in Rule 93 of the PUHCA. The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with OE, FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days, except for $4 million payable to affiliates for OPEB obligations.

3.   PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS:

FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees. The trusteed plans provide defined benefits based on years of service and compensation levels. The Company's funding policy is based on actuarial computations using the projected unit credit method. In the third quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan (Company's share was $13 million). Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. The election to pre-fund the plan is expected to eliminate that funding requirement. Since the contribution is deductible for tax purposes, the after-tax cash impact of the voluntary contribution is approximately $300 million (Company's share was $8 million).

FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits.

Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Such factors may be further affected by business combinations, which impact employee demographics, plan experience and other factors. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for the majority of its plans.

23

Unless otherwise indicated, the following tables provide information applicable to FirstEnergy’s pension and OPEB plans.

Obligations and Funded Status	Pension Benefits									Other Benefits
As of December 31	2004			2003			2004			2003
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	4,162		$	3,866		$	2,368		$	2,077
Service cost		77			66			36			43
Interest cost		252			253			112			136
Plan participants’ contributions		--			--			14			6
Plan amendments		--			--			(281	)		(123	)
Actuarial (gain) loss		134			222			(211	)		323
Benefits paid		(261	)		(245	)		(108	)		(94	)
Benefit obligation as of December 31	$	4,364		$	4,162		$	1,930		$	2,368
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	3,315		$	2,889		$	537		$	473
Actual return on plan assets		415			671			57			88
Company contribution		500			--			64			68
Plan participants’ contribution		--			--			14			2
Benefits paid		(261	)		(245	)		(108	)		(94	)
Fair value of plan assets as of December 31	$	3,969		$	3,315		$	564		$	537
Funded status	$	(395	)	$	(847	)	$	(1,366	)	$	(1,831	)
Unrecognized net actuarial loss		885			919			730			994
Unrecognized prior service cost (benefit)		63			72			(378	)		(221	)
Unrecognized net transition obligation		--			--			--			83
Net asset (liability) recognized	$	553		$	144		$	(1,014	)	$	(975	)
Amounts Recognized in the Consolidated Balance Sheets As of December 31
Accrued benefit cost	$	(14	)	$	(438	)	$	(1,014	)	$	(975	)
Intangible assets		63			72			--			--
Accumulated other comprehensive loss		504			510			--			--
Net amount recognized	$	553		$	144		$	(1,014	)	$	(975	)
Company's share of net amount recognized	$	23		$	10		$	(43	)	$	(39	)
Increase (decrease) in minimum liability
Included in other comprehensive income
(net of tax)	$	(4	)	$	(145	)		--			--
Assumptions Used to Determine Benefit Obligations As of December 31
Discount rate		6.00	%		6.25	%		6.00	%		6.25	%
Rate of compensation increase		3.50	%		3.50	%

Allocation of Plan Assets As of December 31
Asset Category
Equity securities	68	%	70	%	74	%	71	%
Debt securities	29		27		25		22
Real estate	2		2		--		--
Cash	1		1		1		7
Total	100	%	100	%	100	%	100	%

Information for Pension Plans With an Accumulated Benefit Obligation in
Excess of Plan Assets	2004		2003
	(In millions)
Projected benefit obligation	$	4,364	$	4,162
Accumulated benefit obligation		3,983		3,753
Fair value of plan assets		3,969		3,315

24

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2004			2003			2002			2004			2003			2002
	(In millions)
Service cost	$	77		$	66		$	59		$	36		$	43		$	29
Interest cost		252			253			249			112			137			114
Expected return on plan assets		(286	)		(248	)		(346	)		(44	)		(43	)		(52	)
Amortization of prior service cost		9			9			9			(40	)		(9	)		3
Amortization of transition obligation (asset)		--			--			--			--			9			9
Recognized net actuarial loss		39			62			--			39			40			11
Net periodic cost (income)	$	91		$	142		$	(29	)	$	103		$	177		$	114
Company's share of net periodic cost	$	--		$	4		$	1		$	5		$	7		$	2

Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits									Other Benefits
for Years Ended December 31	2004			2003			2002			2004			2003			2002
Discount rate		6.25	%		6.75	%		7.25	%		6.25	%		6.75	%		7.25	%
Expected long-term return on plan assets		9.00	%		9.00	%		10.25	%		9.00	%		9.00	%		10.25	%
Rate of compensation increase		3.50	%		3.50	%		4.00	%

In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the Company's pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy.

FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalizations. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

Assumed Health Care Cost Trend Rates
As of December 31	2004			2003
Health care cost trend rate assumed for next
year (pre/post-Medicare)		9%-11	%		10%-12	%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend rate)		5	%		5	%
Year that the rate reaches the ultimate trend
rate (pre/post-Medicare)		2009-2011			2009-2011

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1-Percentage-		1-Percentage-
	Point Increase		Point Decrease
	(In millions)
Effect on total of service and interest cost	$	19	$	(16	)
Effect on postretirement benefit obligation	$	205	$	(179	)

Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasurement of the plan's obligations. The plan amendment, which increases cost-sharing by employees and retirees effective January 1, 2005, reduced the Company's postretirement benefit costs by $2 million during 2004.

Consistent with the guidance in FSP 106-2 issued on May 19, 2004, FirstEnergy recognized a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act related to benefits for past service. This reduction was accounted for as an actuarial gain in 2004 pursuant to FSP 106-2. The subsidy reduced the Company's net periodic postretirement benefit costs by $2 million during 2004.

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As a result of its voluntary contribution and the increased market value of pension plan assets, the Company reduced its accrued benefit cost as of December 31, 2004 by $8 million. As prescribed by SFAS 87, the Company increased its additional minimum liability by $4 million, recording an increase in an intangible asset of $1 million and charging $3 million to OCI. The balance in AOCL of $14 million (net of $10 million in deferred taxes) will reverse in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets:

	Pension Benefits		Other Benefits
	(In millions)
2005	$	228	$	111
2006		228		106
2007		236		109
2008		247		112
2009		264		115
Years 2010 - 2014		1,531		627

4.   FAIR VALUE OF FINANCIAL INSTRUMENTS:

Long-term Debt and Other Long-term Obligations-

All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of December 31:

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	148	$	160	$	211	$	228
Preferred stock subject to mandatory redemption		13		12		14		14
	$	161	$	172	$	225	$	242

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Company’s ratings.

Investments-

The carrying amounts of cash and cash equivalents approximate fair value due to the short-term nature of these investments. The following table provides the approximate fair value and related carrying amounts of investments other than cash and cash equivalents as of December 31:

	2004				2003
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Debt securities(1):
-Government obligations	$	41	$	41	$	47	$	47
-Corporate debt securities		77		83		76		81
-Mortgage-backed securities		1		1		--		--
		119		125		123		128
Equity securities(1)		57		57		52		52
	$	176	$	182	$	175	$	180

⁽¹⁾ Includes nuclear decommissioning trust investments.

The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms.

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Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. Decommissioning trust investments are classified as available-for-sale. The Company has no securities held for trading purposes. The following table summarizes the amortized cost basis, gross unrealized gains and losses and fair values for decommissioning trust investments as of December 31:

	2004								2003
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities	$	85	$	2	$	1	$	86	$	82	$	2	$	--	$	84
Equity securities		50		8		1		57		47		5		2		50
	$	135	$	10	$	2	$	143	$	129	$	7	$	2	$	134

Proceeds from the sale of decommissioning trust investments, gross realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2004 were as follows:

	2004		2003		2002
	(In millions)
Proceeds from sales	$	41	$	47	$	53
Gross realized gains		1		2		2
Gross realized losses		1		1		3
Interest and dividend income		5		5		5

The following table provides the fair value and gross unrealized losses of nuclear decommissioning trust investments that are deemed to be temporarily impaired as of December 31, 2004.

	Less Than 12 Months				12 Months or More				Total
	Fair		Unrealized		Fair		Unrealized		Fair		Unrealized
	Value		Losses		Value		Losses		Value		Losses
	(In millions)
Debt securities	$	30	$	--	$	3	$	1	$	33	$	1
Equity securities		--		--		13		1		13		1
	$	30	$	--	$	16	$	2	$	46	$	2

The Company periodically evaluates the securities held by its nuclear decommissioning trusts for other-than-temporary impairment. The Company considers the length of time and the extent to which the security's fair value has been less than its cost basis and other factors to determine whether an impairment is other than temporary. The Company's decommissioning trusts are subject to regulatory accounting in accordance with SFAS 71. Net unrealized gains and losses are recorded as regulatory liabilities or assets since the difference between investments held in trust and the decommissioning liabilities are recovered from or refunded to customers.

The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries.

5.   LEASES:

The Company leases office space and other property and equipment under cancelable and noncancelable leases. Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Statements of Income. Such costs for the three years ended December 31, 2004, are summarized as follows:

	2004		2003		2002
	(In millions)
Operating leases
Interest element	$	0.3	$	0.2	$	0.1
Other		0.6		0.3		0.2
Capital leases
Interest element		--		--		--
Other		--		--		0.1
Total rentals	$	0.9	$	0.5	$	0.4

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The future minimum lease payments as of December 31, 2004, are:

	Operating
	Leases
	(In millions)
2005	$	0.1
2006		0.1
2007		0.1
2008		0.1
2009		0.1
Years thereafter		0.5
Total minimum lease payments	$	1.0

6.   REGULATORY MATTERS:

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. With respect to each of these reliability enhancement initiatives, FirstEnergy submitted its response to the respective entity according to any required response dates. 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. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with minor exceptions noted, that FirstEnergy had completed the recommended enhancements, policies, procedures and actions it had recommended be completed by June 30, 2004. In addition, FirstEnergy requested, and NERC provided, a technical assistance team of experts to assist in implementing and confirming timely and successful completion of various initiatives. The NERC-assembled independent verification team confirmed on July 14, 2004, that FirstEnergy had implemented the NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the U.S. - Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004, with minor exceptions noted by FirstEnergy. On December 28, 2004, FirstEnergy submitted a follow-up to its June 30, 2004 Certification and Report of Completion to NERC addressing the minor exceptions, which 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. 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 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.

In May 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for the Company. The Company filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. Evidentiary hearings have been scheduled for September 2005. No procedural schedule or hearing date has been set for this proceeding. The Company is unable to predict the outcome of this proceeding.

On January 16, 2004, the PPUC initiated a formal investigation of whether the Company's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, the Company filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, the Company, Met-Ed and Penelec agreed to enhance service reliability, ongoing periodic performance reporting and communications with customers and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. The settlement also outlines an expedited remediation process to address any alleged non-compliance with terms of the settlement and an expedited PPUC hearing process if remediation is unsuccessful. On November 4, 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.

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Pennsylvania enacted its electric utility competition law in 1996 with the phase in of customer choice for electric generation suppliers completed as of January 1, 2001. The Company continues to deliver power to homes and businesses through its distribution system, which remains regulated by the PPUC. The Company’s rates have been restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of the Company’s rates is excluded from their bill and the customers receive a generation charge from the alternative supplier. The stranded cost recovery portion of rates provides for recovery of certain amounts not otherwise considered recoverable in a competitive generation market, including regulatory assets. Under the rate restructuring plan, the Company is entitled to recover $236 million of stranded costs through the CTC that began in 1999 and ends in 2006.

7.   CAPITALIZATION:

(A)   RETAINED EARNINGS-

Under the Company’s Charter, the Company’s retained earnings unrestricted for payment of cash dividends on the Company’s common stock were $78.0 million as of December 31, 2004.

(B)   PREFERRED STOCK-

All preferred stock may be redeemed by the Company in whole, or in part, with 30-60 days’ notice.

(C)   LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS-

Preferred Stock Subject to Mandatory Redemption-

The Company’s 7.625% series has an annual sinking fund requirement for 7,500 shares in 2005 and 2006.

     The Company's preferred shares are retired at $100 per share plus accrued dividends. Annual sinking fund requirements are $750,000 in 2005 and 2006 and $11.25 million in 2007.

Other Long-Term Debt-

The Company has a FMB indenture under which it issues FMB secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Company.

Based on the amount of FMB authenticated by the mortgage bond trustee through December 31, 2004, the Company's annual sinking fund requirements for all FMB issued under its first mortgage indenture amounts to $10 million. The Company expects to deposit funds with its mortgage bond trustee in 2005 that will then be withdrawn upon the surrender for cancellation of a like principal amount of FMB, which are specifically authenticated for such purposes against unfunded property additions or against previously retired FMB. This method can result in minor increases in the amount of the annual sinking fund requirement.

Sinking fund requirements for FMB and maturing long-term debt during the next five years are $26 million in 2005 and $1.0 million in each year 2006 through 2009. Included in these amounts are various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. Those amounts are $25 million in 2005, which represents the next time the debt holders may exercise this provision.

The Company's obligations to repay certain pollution control revenue bonds are secured by several series of FMB. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank LOCs of $10.4 million and noncancelable municipal bond insurance policies of $38 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the LOCs or policies, the Company is entitled to a credit against its obligation to repay the related bond. The Company pays an annual fee of 1.0% of the amount of the LOCs to the issuing bank and 0.24% to 0.30% of the amounts of the policies to the insurers and is obligated to reimburse the bank or insurers, as the case may be, for any drawings thereunder.

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8.   ASSET RETIREMENT OBLIGATION:

In January 2003, the Company implemented SFAS 143, which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an ARO in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead of an expense if the criteria for such treatment are met. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

The Company identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond related to the Bruce Mansfield Plant. The ARO liability as of the date of adoption of SFAS 143 was $121.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. Accretion during 2004 was $8 million, bringing the ARO liability as of December 31, 2004 to $138 million. The ARO includes the Company's obligation for nuclear decommissioning of the Beaver Valley and Perry generating facilities. The Company's share of the obligation to decommission these units was developed based on site-specific studies performed by an independent engineer. The Company utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO. The Company maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2004, the fair value of the decommissioning trust assets was $143 million.

The following table describes changes to the ARO balances during 2004 and 2003.

ARO Reconciliation	2004		2003
	(In millions)
Beginning balance as of January 1	$	130	$	122
Accretion		8		8
Ending balance as of December 31	$	138	$	130

The following table provides the year-end balance of the ARO for 2002, as if SFAS 143 had been adopted on January 1, 2002.

Adjusted ARO Reconciliation	2002
	(In millions)
Beginning balance as of January 1	$	114
Accretion		8
Ending balance as of December 31	$	122

9.   SHORT-TERM BORROWINGS:

The Company may borrow from affiliates on a short-term basis. As of December 31, 2004, the Company had borrowed $11.9 million from its affiliates at an average interest rate of 2.0%.

In March 2004, the Company completed, through a separate wholly owned subsidiary, a receivables financing arrangement that provides borrowing capability of up to $25 million. The borrowing rate is based on bank commercial paper rates. The Company is required to pay an annual facility fee of 0.40% on the entire finance limit. The facility was undrawn as of December 31, 2004 and matures on March 29, 2005. This receivables financing arrangement is expected to be renewed prior to expiration.

10.   COMMITMENTS AND CONTINGENCIES:

(A)   NUCLEAR INSURANCE-

The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.8 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its ownership interests in the Beaver Valley Station and the Perry Plant, the Company’s maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $84.5 million per incident but not more than $8.4 million in any one year for each incident.

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The Company is also insured as to its interest in Beaver Valley and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $280.1 million of insurance coverage for replacement power costs for its interests in Beaver Valley and Perry. Under these policies, the Company can be assessed a maximum of approximately $13.2 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.

The Company intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Company’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Company’s insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs.

(B)   ENVIRONMENTAL MATTERS-

Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on the Company's earnings and competitive position. These environmental regulations affect the Company'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, the Company believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. Generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit.

Clean Air Act Compliance-

The Company 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 Company cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

The Company 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 the Company's facilities. The EPA's NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85% reduction in utility plant NO_x emissions from projected 2007 emissions) across a region of nineteen states (including 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. The Company believes its facilities are complying with the NO_x budgets established under State Implementation Plans (SIPs) through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

National Ambient Air Quality Standards-

In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 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. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NO_x and SO₂ emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO₂ emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NO_x emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Company 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 December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of SO₂ and NO_x emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The 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 covering 44 power plants, including the W. H. Sammis Plant, which is owned by the Company and OE. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against the Company and OE in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase trial to address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's, the Company's and OE's respective financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.

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.

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% through 2012.

The Company 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 Company is lower than many regional competitors due to the Company's diversified generation sources which includes low or non-CO₂ emitting gas-fired and nuclear generators.

32

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 the Companies' plants. In addition, Ohio and Pennsylvania have water quality standards applicable to the Companies' 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 Clean Water Act Section 316(b) 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. The Company 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.

(C) OTHER LEGAL PROCEEDINGS-

Power Outages and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. On April 5, 2004, the U.S. -Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, 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 contains 46 "recommendations to prevent or minimize the scope of future blackouts." Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends 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 are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 with minor exceptions noted by FirstEnergy (see Note 6). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the 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. FirstEnergy has not accrued a liability as of December 31, 2004 for any expenditures in excess of those actually incurred through that date.

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 instituted against the Companies. In particular, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.

Legal Matters-

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to the Company's normal business operations pending against the Company. The most significant are described below.

On August 12, 2004, the NRC notified FENOC that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, in which the Company owns a 5.24% interest. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased oversight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC's corrective actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition.

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11.   NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

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

In December 2004, the FASB issued this Statement 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. The Company is currently evaluating this standard but does not expect it to have a material impact on the financial statements.

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

In November 2004, the FASB issued this statement 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 the Company after June 30, 2005. The Company is currently evaluating this standard but does not expect it to have a material impact on the financial statements.

EITF   Issue No. 03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, the Company will continue to evaluate its investments as required by existing authoritative guidance.

EITF Issue No. 03-16, "Accounting for Investments in Limited Liability Companies"

In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF 03-16 requires that an investment in a limited liability company that maintains a "specific ownership account" for each investor should be viewed as similar to an investment in a limited partnership for determining whether the cost or equity method of accounting should be used. The equity method of accounting is generally required for investments that represent more than a three to five percent interest in a limited partnership. EITF 03-16 was adopted by Penn in the third quarter of 2004 and did not affect the Company's financial statements.

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 9 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). This tax deduction is limited to 50 percent of W-2 wages paid by the taxpayer. The FASB believes that the deduction should be accounted for as a special deduction in accordance with SFAS No. 109, "Accounting for Income Taxes." FirstEnergy is currently evaluating this FSP but does not expect it to have a material impact on the Company's financial statements.

FSP 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"

Issued in May 2004, FSP 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. The effect of the federal subsidy provided under the Medicare Act on the Company's consolidated financial statements is described in Note 3.

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12.   SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

The following summarizes certain consolidated operating results by quarter for 2004 and 2003.

	March 31,		June 30,		September 30,		December 31,
Three Months Ended	2004		2004		2004		2004
	(In millions)
Operating Revenues	$	142.6	$	134.6	$	143.3	$	128.6
Operating Expenses and Taxes		122.1		115.4		123.1		127.7
Operating Income		20.5		19.2		20.2		0.9
Other Income		1.0		0.5		0.8		1.2
Net Interest Charges		1.8		1.8		0.6		1.0
Net Income	$	19.7	$	17.9	$	20.4	$	1.1
Earnings on Common Stock	$	19.1	$	17.3	$	19.7	$	0.4

	March 31,			June 30,		September 30,		December 31,
Three Months Ended	2003			2003		2003		2003
	(In millions)
Operating Revenues	$	128.3		$	116.6	$	145.8	$	135.8
Operating Expenses and Taxes		130.2			110.3		125.9		112.8
Operating Income (Loss)		(1.9	)		6.3		19.9		23.0
Other Income		0.6			0.5		0.4		1.3
Net Interest Charges		3.4			3.4		2.9		2.5
Income (Loss) Before Cumulative Effect of Accounting Change		(4.7	)		3.4		17.4		21.8
Cumulative Effect of Accounting Change (Net of Income Taxes)		10.6			--		--		--
Net Income	$	5.9		$	3.4	$	17.4	$	21.8
Earnings on Common Stock	$	5.0		$	2.5	$	16.8	$	21.1

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