PENNSYLVANIA POWER COMPANY

2005 ANNUAL REPORT TO STOCKHOLDERS

Pennsylvania Power Company, an electric utility operating company of FirstEnergy Corp. and a wholly owned subsidiary of Ohio Edison Company, furnishes electric service to communities in a 1,500 square mile area of western Pennsylvania. It also engages in the purchase of electric energy from other electric companies. The area served has a population of approximately 0.3 million.

Contents	Page
Glossary of Terms	i-ii
Report of Independent Registered Public Accounting Firm	1
Selected Financial Data	2
Management's Discussion and Analysis	3-14
Consolidated Statements of Income	15
Consolidated Balance Sheets	16
Consolidated Statements of Capitalization	17
Consolidated Statements of Common Stockholder's Equity	18
Consolidated Statements of Preferred Stock	18
Consolidated Statements of Cash Flows	19
Consolidated Statements of Taxes	20
Notes to Consolidated Financial Statements	21-35

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
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial, and other corporate support services
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a 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
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, Penn's Ohio electric utility parent company
Ohio Companies	CEI, OE and TE
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:

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
CAL	Confirmatory Action Letter
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
DOJ	United States Department of Justice
ECAR	East Central Area Reliability Coordination Agreement
EITF	Emerging Issues Task Force
EITF 03-1	EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments”
EITF 04-13	EITF Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty
EPA	Environmental Protection Agency
EPACT	Energy Policy Act of 2005
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 47	FASB Interpretation 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143"
FMB	First Mortgage Bonds
FSP	FASB Staff Position
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 115-1 and FAS 124-1	FASB Staff Position No. 115-1 and FAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"
GAAP	Accounting Principles Generally Accepted in the United States
IRS	Internal Revenue Service
KWH	Kilowatt-hours
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

i

NERC	North American Electric Reliability Council
NOV	Notices of Violation
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
RFP	Request for Proposal
S&P	Standard & Poor’s Ratings Service
SEC	United States Securities and Exchange Commission
SFAC	Statement of Financial Accounting Concepts
SFAC 7	SFAC No. 7, “Using Cash Flow Information and Present Value in Accounting Measurement”
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"
SFAS 151	SFAS No. 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4"
SFAS 153	SFAS No. 153, "Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29"
SFAS 154	SFAS No. 154, "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3"
SO2	Sulfur Dioxide

ii

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of

Directors of Pennsylvania Power Company:

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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 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) and Note 8 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003.

PricewaterhouseCoopers LLP

Cleveland, Ohio

February 27, 2006

1

The following selected financial data should be read in conjunction with, and is qualified in its entirety by reference to, the sections entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and with our consolidated financial statements and the “Notes to Consolidated Financial Statements.” Our Consolidated Statements of Income are not necessarily indicative of future conditions or results of operations.

PENNSYLVANIA POWER COMPANY
SELECTED FINANCIAL DATA
	2005			2004			2003			2002			2001
	(Dollars in thousands)
GENERAL FINANCIAL INFORMATION:
Operating Revenues	$	540,556		$	549,121		$	526,581		$	506,407		$	498,401
Operating Income	$	68,025		$	60,780		$	47,363		$	60,922		$	55,178
Income Before Cumulative Effect
of Accounting Change	$	65,865		$	59,076		$	37,833		$	47,717		$	41,041
Net Income	$	65,865		$	59,076		$	48,451		$	47,717		$	41,041
Earnings on Common Stock	$	64,176		$	56,516		$	45,263		$	44,018		$	37,338
Total Assets	$	815,000		$	921,156		$	878,967		$	907,748		$	960,097
CAPITALIZATION AS OF DECEMBER 31:
Common Stockholder’s Equity	$	296,933		$	327,379		$	230,786		$	229,374		$	223,788
Preferred Stock-
Not Subject to Mandatory Redemption		14,105			39,105			39,105			39,105			39,105
Subject to Mandatory Redemption		-			-			-			13,500			14,250
Long-Term Debt and Other Long-Term Obligations		130,677			133,887			130,358			185,499			262,047
Total Capitalization	$	441,715		$	500,371		$	400,249		$	467,478		$	539,190
CAPITALIZATION RATIOS:
Common Stockholder’s Equity		67.2	%		65.4	%		57.7	%		49.1	%		41.5	%
Preferred Stock-
Not Subject to Mandatory Redemption		3.2			7.8			9.8			8.3			7.3
Subject to Mandatory Redemption		-			-			-			2.9			2.6
Long-Term Debt and Other Long-Term Obligations		29.6			26.8			32.5			39.7			48.6
Total Capitalization		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%
DISTRIBUTION KWH DELIVERIES (Millions):
Residential		1,664			1,551			1,506			1,533			1,391
Commercial		1,367			1,299			1,283			1,268			1,220
Industrial		1,629			1,573			1,464			1,505			1,540
Other		6			7			6			6			6
Total		4,666			4,430			4,259			4,312			4,157
CUSTOMERS SERVED:
Residential		138,834			138,377			137,170			136,410			134,956
Commercial		18,939			18,730			18,455			18,397			18,153
Industrial		211			219			219			220			224
Other		85			85			85			85			87
Total		158,069			157,411			155,929			155,112			153,420
Number of Employees		201			200			201			201			256

2

PENNSYLVANIA POWER COMPANY

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF RESULTS OF OPERATIONS

AND FINANCIAL CONDITION

Forward-looking Statements. This discussion includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate," "potential," "expect," "believe," "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, the continued ability of our regulated utilities to collect transition and other charges or to recover increased transmission costs, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), the repeal of PUHCA and the legal and regulatory changes resulting from the implementation of the EPACT, the uncertainty of the timing and amounts of the capital expenditures (including that such amounts could be higher than anticipated) or levels of emission reductions related to the settlement agreement resolving the New Source Review litigation, adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits, fines or other enforcement actions and remedies) of governmental investigations and oversight, including by the Securities and Exchange Commission, the United States Attorney's Office, the Nuclear Regulatory Commission and the Pennsylvania Public Utility Commission as disclosed in our Securities and Exchange Commission filings, the continuing availability and operation of generating units, the ability of generating units to continue to operate at, or near full capacity, our inability to accomplish or realize anticipated benefits from strategic goals (including employee workforce factors), the anticipated benefits from our voluntary pension plan contributions, our ability to improve electric commodity margins and to experience growth in the distribution business, our ability to access the public securities and other capital markets and the cost of such capital, the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the August 14, 2003 regional power outage, the risks and other factors discussed from time to time in our Securities and Exchange Commission filings, and other similar factors. Also, a credit rating should not be viewed as a recommendation to buy, sell or hold securities and may be revised or withdrawn by a rating agency at any time. We expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events, or otherwise.

FirstEnergy Intra-System Generation Asset Transfers

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

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

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

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

The transfers are expected to affect our near-term future results with reductions in revenues and expenses. Revenues will be reduced due to the termination of the sale of our nuclear generation KWH and the lease of our non-nuclear-generated assets arrangements with FES. Our expenses will be lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. In addition, we will receive interest income from associated company notes receivable from FGCO and NGC for the transfer of our generation net assets and eliminate the interest expense on certain pollution control notes to be transferred to FGCO and NGC. FES will continue to provide our PLR requirements under revised purchased power arrangements for a three-year period beginning January 1, 2006 (see Regulatory Matters).

3

Results of Operations

Earnings on common stock in 2005 increased to $64 million from $57 million in 2004. Improved earnings in 2005 resulted from lower purchased power and nuclear operating costs, partially offset by lower operating revenues, higher other operating expenses and higher income taxes. Operating revenues were down primarily due to reduced wholesale sales to FES. Other operating costs were higher in 2005 primarily due to increased transmission expenses.

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 2(G)). Income before the cumulative effect of an accounting change in 2003 was $38 million. Improved results in 2004 reflected lower nuclear operating costs, higher operating revenues and reduced net interest charges, 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 the Perry Plant in 2003.

Operating Revenues

Operating revenues decreased by $9 million or 2% in 2005 as compared with 2004. The lower revenues primarily resulted from reductions in wholesale sales to FES of $24 million, lease revenues to FGCO of $4 million and distribution throughput of $2 million. These reductions were partially offset by a $19 million increase in retail generation sales. The decrease in FES sales revenues was primarily due to lower unit prices. In addition, the nuclear generation asset transfers on December 16 terminated our nuclear generation sales arrangement to FES. Revenues from the leases of fossil generation assets to FGCO decreased when the lease arrangements were terminated as a result of the non-nuclear intra-system asset transfers completed on October 24, 2005. Distribution revenues decreased due to lower unit prices which were partially offset by higher distribution KWH deliveries resulting from the warmer summer weather in 2005. The higher retail generation revenues (residential - $4 million, commercial - $5 million and industrial - $10 million) resulted from higher KWH sales in all customer sectors and higher unit prices. The increase in industrial sector sales reflected higher KWH sales to our steel industry customers.

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 KWH sales to industrial customers.

Changes in electric generation and distribution deliveries in 2005 and 2004 compared to the prior years are summarized in the following table:

Changes in KWH Sales	2005			2004
Increase (Decrease)
Electric Generation:
Retail		5.3	%		4.1	%
Wholesale		(1.5	)%		10.9	%
Total Electric Generation Sales		1.3	%		8.0	%
Distribution Deliveries:
Residential		7.3	%		3.0	%
Commercial		5.2	%		1.3	%
Industrial		3.5	%		7.5	%
Total Distribution Deliveries		5.3	%		4.0	%

4

Operating Expenses and Taxes

Total operating expenses and taxes decreased by $16 million in 2005 and increased by $9 million in 2004 from the prior year. The following table presents changes from the prior year by expense category.

Operating Expenses and Taxes - Changes	2005			2004
Increase (Decrease)	(In millions)
Fuel costs	$	-		$	1
Purchased power costs		(5	)		15
Nuclear operating costs		(35	)		(22	)
Other operating costs		17			(2	)
Provision for depreciation		-			1
Amortization of regulatory assets		-			-
General taxes		2			1
Income taxes		5			15
Total operating expenses and taxes	$	(16	)	$	9

The $35 million decrease in nuclear operating costs in 2005 was due to our lower owned interests in the two plants (Beaver Valley Unit 2 - 13.74% and Perry - 5.24%) with refueling outages in 2005 as compared to the Beaver Valley Unit 1 (65.00% owned) that had a refueling outage in 2004. Purchased power costs decreased by $5 million in 2005 compared with 2004 as a result of lower unit prices, partially offset by increased KWH purchases to meet our higher retail generation sales requirements. Other operating costs increased by $17 million in 2005, reflecting a $14 million increase in transmission expenses associated with MISO Day 2 transactions that began on April 1, 2005.

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 KWH purchases to meet increased retail generation sales requirements. Nuclear operating costs decreased $22 million in 2004, primarily due to expenses associated with one scheduled refueling outage in 2004 compared to three scheduled refueling outages in 2003.

General taxes increased $2 million in 2005 primarily due to the absence in 2005 of settled property tax claims in the prior year.

Net Interest Charges

Net interest charges continued to trend lower, decreasing by $1 million in 2005 and by $7 million in 2004 compared with the prior years, as we continued to redeem and refinance outstanding debt. Long-term debt redemptions in 2005, 2004 and 2003 totaled $10 million, $64 million and $41 million, respectively.

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.

Capital Resources and Liquidity

Our cash requirements in 2005 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions were met without increasing our net debt and preferred stock outstanding (excluding any debt impacts related to the intra-system generation asset transfer). During 2006 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, 2005, we had $24,000 of cash and cash equivalents compared with $38,000 as of December 31, 2004. The major sources for changes in these balances are summarized below.

5

Cash Flows From Operating Activities

Net cash provided from operating activities was $162 million in 2005, $115 million in 2004 and $116 million in 2003. Cash provided from 2005, 2004 and 2003 operating activities are as follows:

Operating Cash Flows	2005			2004			2003
	(In millions)
Cash earnings(1)	$	126		$	135		$	99
Pension trust contribution(2)		(13	)		(8	)		-
Working capital and other		49			(12	)		17
Net cash provided from operating activities	$	162		$	115		$	116

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

⁽²⁾Pension trust contributions in 2005 and 2004 are net of $6 million and $5 million

of income tax benefits, respectively.

Cash earnings (in the table above) are 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	2005			2004		2003
	(In millions)
Net Income (GAAP)	$	66		$	59	$	48
Non-Cash Charges (Credits):
Provision for depreciation		14			14		13
Amortization of regulatory assets		40			40		41
Nuclear fuel and capital lease amortization		17			17		16
Deferred income taxes and investment tax credits, net*		(12	)		-		(13	)
Cumulative effect of accounting change		-			-		(11	)
Other non-cash expenses		1			5		5
Cash earnings (Non-GAAP)	$	126		$	135	$	99

* Excludes $5 million of deferred tax benefit from pension contribution in 2004.

Net cash provided from operating activities increased $47 million in 2005 compared with 2004 due to a $61 million increase in working capital and other, partially offset by a $9 million decrease in cash earnings as described under "Results of Operations" and a $5 million increase in the after-tax voluntary pension trust contributions in 2005 compared to 2004. The increase in working capital and other was primarily due to a decreased cash outflow of $22 million for payables and a decreased outflow of $22 million in tax payments.

Net cash from operating activities decreased $1 million in 2004 compared with 2003 due to a $29 million comparative change in working capital and the $8 million after-tax voluntary pension trust contribution in 2004, partially offset by a $36 million increase in cash earnings as described above under “Results of Operations”. The working capital decrease was primarily due to an increased cash outflow of $28 million in higher tax payments.

Cash Flows From Financing Activities

In 2005, 2004 and 2003, net cash used for financing activities of $53 million, $25 million and $76 million, respectively, primarily reflected the new issues and redemptions shown below.

Securities Issued or Redeemed	2005		2004		2003
	(In millions)
New Issues:
Pollution Control Notes	$	-	$	-	$	-
Short-Term Borrowings, Net		5		1		11
Redemptions:
FMB	$	1	$	63	$	41
Pollution Control Notes		9		-		-
Capital Fuel Leases				-		-
Preferred Stock		38		1		1
Other		-		1		-
	$	48	$	65	$	42

6

The $28 million increase in cash used for financing in 2005 was primarily due to the absence of a $65 million equity contribution from OE received in 2004, partially offset by a $15 million decrease in common stock dividend payments to OE and the net decrease in debt redemptions shown above. In 2004, net cash used for financing activities decreased by $51 million from 2003. This decrease primarily reflects a $65 million equity contribution from OE and a $19 million reduction in common stock dividends to OE, partially offset by an $11 million decrease in short-term borrowings and a $23 million increase in long-term debt redemptions.

We had $489,000 of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $13 million of short-term indebtedness with associated companies as of December 31, 2005. We have obtained authorization from the SEC to incur short-term debt of up to our charter limit of $44 million (including the utility money pool described below). In addition, we have a $25 million (all of which was unused as of December 31, 2005) of accounts receivable financing facility through Penn Funding, our wholly owned subsidiary. As a separate legal entity with separate creditors, Penn Funding would have to satisfy its obligations to creditors before any of its remaining assets could be made available to us.

As of December 31, 2005, we had the capability to issue $7 million of additional FMB on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests, we could issue up to $526 million of preferred stock (assuming no additional debt was issued as of December 31, 2005).

On June 14, 2005, we, FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility. Borrowings under the facility are available to each Borrower separately and will mature on the earlier of 364 days from the date of borrowing or the commitment termination date. Our borrowing limit under the facility is $50 million, subject to applicable regulatory approvals.

Under the revolving credit facility, borrowers may request the issuance of letters of credit expiring up to one year from the date of issuance. The stated amount of outstanding letters of credit will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit. Total unused borrowing capability under the existing credit facility and accounts receivable financing facilities totaled $75 million as of December 31, 2005.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%. As of December 31, 2005, our debt to total capitalization as defined under the revolving credit facility was 42%.

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

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. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2005 was 3.24%.

On July 18, 2005, Moody’s revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Moody’s stated that the revision to FirstEnergy’s outlook resulted from steady financial improvement and steps taken by management to improve operations, including the stabilization of its nuclear operations. On October 3, 2005, S&P raised its corporate credit rating on FirstEnergy and the EUOC to 'BBB' from 'BBB-'. At the same time, S&P raised the senior unsecured ratings at the holding company to 'BBB-' from 'BB+' and each of the EUOC by one notch above the previous rating. S&P noted that the upgrade followed the continuation of a good operating track record, specifically for the nuclear fleet through the third quarter of 2005. On December 23, 2005, Fitch revised its rating outlook on FirstEnergy and its subsidiaries to positive from stable. Fitch stated that the revision to FirstEnergy's outlook resulted from improved performance of the Company's generating fleet and ongoing debt reduction.

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, 2005. The ratings outlook from S&P on all securities is stable. The ratings outlook from Moody's and Fitch on all securities is positive.

7

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

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

Cash Flows from Investing Activities

Net cash used in investing activities totaled $109 million in 2005 compared to $90 million in 2004. The $19 million increase in 2005 is primarily due to the collection of $114 million of principal on long-term notes receivable, partially offset by a $50 million loan to associated companies and $78 million of investments for an escrow fund and a mortgage indenture deposit.

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 $34 million in loan repayments from associated companies.

Our capital spending for the period 2006-2010 is expected to be about $91 million of which approximately $19 million applies to 2006. We had no other material obligations as of December 31, 2005 that have not been recognized on our Consolidated Balance Sheet.

Contractual Obligations

As of December 31, 2005, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:

					2007-		2009-
Contractual Obligations	Total		2006		2008		2010		Thereafter
	(In millions)
Long-term debt (1)	$	200	$	1	$	2	$	2	$	195
Short-term borrowings		13		13		-		-		-
Operating leases (2)		7		1		2		1		3
Total	$	220	$	15	$	4	$	3	$	198

⁽¹⁾Amounts reflected do not include interest on long-term debt.

⁽²⁾See Note 5 to Consolidated Financial Statements.

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.

8

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.

Comparison of Carrying Value to Fair Value
																There-						Fair
Year of Maturity	2006			2007			2008			2009			2010			after			Total			Value
	(Dollars in millions)
Assets
Investments Other Than Cash and Cash Equivalents-
Fixed Income	$	-		$	-		$	1		$	1		$	1		$	281		$	284		$	269
Average interest rate		7.8	%		7.8	%		7.8	%		7.8	%		7.8			5.6	%		5.7	%
Liabilities
Long-term Debt and Other Long-Term Obligations:
Fixed rate	$	1		$	1		$	1		$	1		$	64		$	79		$	147		$	152
Average interest rate		9.7	%		9.7	%		9.7	%		9.7	%		5.5	%		6.4	%		6.1	%
Variable rate																$	53		$	53		$	53
Average interest rate																	3.4	%		3.4	%
Short-term Borrowings	$	13																	$	13		$	13
Average interest rate		4.0	%																	4.0	%

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. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated.

Regulatory Matters

Regulatory assets and liabilities are costs which have been authorized by the PPUC and the FERC for recovery from or credit to customers in future periods and, without such authorization, would have been charged or credited to income when incurred. Our net regulatory liabilities were approximately $59 million and $19 million as of December 31, 2005 and December 31, 2004, respectively, and are included under Noncurrent Liabilities on the Consolidated Balance Sheets.

On October 11, 2005, we filed a plan with the PPUC to secure electricity supply for our customers at set rates following the end of our transition period on December 31, 2006. We are recommending that a RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with main briefs filed on January 27, 2006 and reply briefs on February 3, 2006. On February 17, 2006, the ALJ issued a Recommended Decision to adopt our RFP process with modifications. A PPUC vote is expected in April 2006. Under Pennsylvania’s electric competition law, we are required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

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

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticizes the Ohio competitive bid process, and requires FES to submit additional evidence in support of the reasonableness of the prices charged in the Ohio and Pennsylvania Contracts. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in the fall of 2006. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order.

See Note 6 to the consolidated financial statements for further details and a complete discussion of regulatory matters in Pennsylvania, including a detailed discussion of reliability initiatives.

Environmental Matters

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

9

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

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NOx and SO2 emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if we fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, we could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results in 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million,respectively, for probable future cash contributions toward environmentally beneficial projects.

Other Legal Proceedings

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

Power Outages and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concludes, among other things, that the problems leading to the outages began in our Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within our 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). We believe 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. We remain convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. We implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of our electric system. Our implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. We also are proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment, and therefore we have not accrued a liability as of December 31, 2005 for any expenditures in excess of those actually incurred through that date. We note, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review our filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators before determining the next steps, if any, in the proceeding.

10

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

Nuclear Plant Matters-

As of December 16, 2005 NGC acquired ownership of the nuclear generation assets transferred from the OE, Penn, CEI and TE with the exception of leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates. The transfer included our prior owned interests in Beaver Valley Unit 1 (65.00%), Beaver Valley Unit 2 (13.74%) and Perry (5.24%).

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

In an April 4, 2005 public meeting discussing FENOC’s performance at Perry identified in its annual assessment, NRC stated that , overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. The NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.

Other Legal Matters-

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

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

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

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 the 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 based on anticipated future cash inflows. We regularly review these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these 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.

11

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, 2005 to 5.75% from 6.00% and 6.25% used as of December 31, 2004 and 2003, respectively.

Our assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2005, 2004 and 2003, plan assets actually earned $325 million or 8.2%, $415 million or 11.1% and $671 million or 24.2% respectively. Our pension costs in 2005, 2004 and 2003 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and our pension trust investment allocation is approximately 63% equities, 33% bonds, 2% real estate and 2% cash. The gains or losses generated as a result of the difference between expected and actual returns on plan assets are deferred and amortized and will increase or decrease future net periodic pension expense, respectively.

In the fourth quarter of 2005, FirstEnergy made a $500 million voluntary contribution to its pension plan (our share was $19 million). As a result of our voluntary contribution and the increased market value of pension plan assets, we recognized a prepaid benefit cost of $42 million as of December 31, 2005. As prescribed by SFAS 87, we eliminated our additional minimum liability of $29 million and its intangible asset of $6 million. In addition, the entire AOCL balance was credited by $14 million (net of $9 million in deferred taxes) as the fair value of trust assets exceeded the accumulated benefit obligation as of December 31, 2005.

Health care cost trends have significantly increased and will affect future OPEB costs. The 2005 and 2004 composite health care trend rate assumptions are approximately 9-11%, 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. The effect on Penn Power's portion of pension and OPEB costs from changes in key assumptions are as follows:

Increase in Costs from Adverse Changes in Key Assumptions
Assumption	Adverse Change			Pension		OPEB		Total
			(In millions)
Discount rate		Decrease by 0.25%		$	0.2	$	0.1	$	0.3
Long-term return on assets		Decrease by 0.25%		$	0.3	$	-	$	0.3
Health care trend rate		Increase by 1%			na	$	0.8	$	0.8

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.

12

Asset Retirement Obligations

In accordance with SFAS 143 and FIN 47, we recognize an ARO for the future decommissioning of our nuclear power plants and future remediation of other environmental liabilities associated with all our long-lived assets. The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities 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 and environmental remediation 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; settlement based on an extended license term and expected remediation dates.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

FSP FAS 115-1 and FAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

Issued in November 2005, FSP 115-1 and FAS 124-1 addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. This FSP will (1) nullify certain requirements of Issue 03-1 and supersedes EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FSP requires prospective application with an effective date for reporting periods beginning after December 15, 2005. We are currently evaluating this FSP Issue and any impact on its investments.

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

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

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

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

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

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

13

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

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

14

PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,	2005			2004			2003
				(In thousands)
OPERATING REVENUES (Note 2(I))	$	540,556		$	549,121		$	526,581
OPERATING EXPENSES AND TAXES:
Fuel		23,042			22,894			21,443
Purchased power (Note 2(I))		175,782			181,031			165,643
Nuclear operating costs		71,690			106,659			128,895
Other operating costs (Note 2(I))		68,005			51,180			52,809
Provision for depreciation		14,409			14,134			13,017
Amortization of regulatory assets		39,967			40,012			40,789
General taxes		25,580			23,607			22,458
Income taxes		54,056			48,824			34,164
Total operating expenses and taxes		472,531			488,341			479,218
OPERATING INCOME		68,025			60,780			47,363
OTHER INCOME (net of income taxes) (Notes 2(I))		1,786			3,464			2,807
NET INTEREST CHARGES:
Interest on long-term debt		8,144			8,250			14,228
Allowance for borrowed funds used during construction		(5,944	)		(4,563	)		(3,189	)
Other interest expense		1,746			1,481			1,298
Net interest charges		3,946			5,168			12,337
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE		65,865			59,076			37,833
Cumulative effect of accounting change (net of income
taxes of $7,532,000) (Note 2(G))		-			-			10,618
NET INCOME		65,865			59,076			48,451
PREFERRED STOCK DIVIDEND REQUIREMENTS		1,689			2,560			3,188
EARNINGS ON COMMON STOCK	$	64,176		$	56,516		$	45,263
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

15

PENNSYLVANIA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31,	2005		2004
	(In thousands)
ASSETS
UTILITY PLANT:
In service	$	359,069	$	866,303
Less - Accumulated provision for depreciation		129,118		356,020
		229,951		510,283
Construction work in progress -
Electric plant		3,775		104,366
Nuclear fuel		-		3,362
		3,775		107,728
		233,726		618,011
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		-		143,062
Long-term notes receivable from associated companies		284,482		32,985
Other		351		722
		284,833		176,769
CURRENT ASSETS:
Cash and cash equivalents		24		38
Notes receivable from associated companies		465		431
Receivables -
Customers (less accumulated provision of $1,087,000 and $888,000,
respectively, for uncollectible accounts)		44,555		44,282
Associated companies		115,441		23,016
Other		2,889		1,656
Materials and supplies, at average cost		-		37,923
Prepayments and other		86,995		8,924
		250,369		116,270
DEFERRED CHARGES:
Prepaid pension costs		42,243		-
Other		3,829		10,106
		46,072		10,106
	$	815,000	$	921,156
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity	$	296,933	$	327,379
Preferred stock		14,105		39,105
Long-term debt and other long-term obligations		130,677		133,887
		441,715		500,371
CURRENT LIABILITIES:
Currently payable long-term debt		69,524		26,524
Accounts payable -
Associated companies		73,444		46,368
Other		1,828		1,436
Notes payable to associated companies		12,703		11,852
Accrued taxes		28,632		14,055
Accrued interest		1,877		1,872
Other		8,086		8,802
		196,094		110,909
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		66,576		93,418
Asset retirement obligation		149		138,284
Retirement benefits		45,967		49,834
Regulatory liabilities		58,637		18,823
Other		5,862		9,517
		177,191		309,876
COMMITMENTS AND CONTINGENCIES (Notes 5 and 10)
	$	815,000	$	921,156
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

16

PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31,								2005			2004
(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									71,136			64,690
Accumulated other comprehensive loss (Note 2(F))									-			(13,706	)
Retained earnings (Note 7(A))									37,097			87,695
Total common stockholder’s equity									296,933			327,379
		Number of Shares			Optional
	Outstanding			Redemption Price
		2005	2004		Per Share		Aggregate
PREFERRED STOCK NOT SUBJECT TO
MANDATORY REDEMPTION (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				-		-			25,000
Total		141,049	391,049			$	14,614		14,105			39,105
LONG-TERM DEBT AND LONG-TERM OBLIGATIONS (Note 7(C)):
First mortgage bonds-
9.740% due 2005-2019									13,669			14,643
7.625% due 2023									6,500			6,500
Total first mortgage bonds									20,169			21,143
Secured notes-
5.400% due 2013									1,000			1,000
5.400% due 2017									10,600			10,600
*  3.300% due 2017									17,925			17,925
5.900% due 2018									16,800			16,800
*  3.300% due 2021									10,525			14,482
6.150% due 2023									12,700			12,700
*  3.610% 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
*  1.800% due 2033									-			5,200
Total secured notes									102,784			112,179
Unsecured notes-
*  3.500% due 2029									14,500			14,500
5.390% due 2010 to associated company									62,900			-
Total unsecured notes									77,400			14,500
Preferred stock subject to mandatory redemption									-			12,750
Net unamortized discount on debt									(152	)		(161	)
Long-term debt due within one year									(69,524	)		(26,524	)
Total long-term debt and other long-term obligations									130,677			133,887
TOTAL CAPITALIZATION								$	441,715		$	500,371
* Denotes variable-rate issue with applicable year-end interest rate shown.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

17

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, 2003					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
Net income	$	65,865													65,865
Minimum liability for unfunded retirement
benefits, net of $9,707,000 of income taxes		13,706										13,706
Comprehensive income	$	79,571
Affiliated company asset transfers									6,101						(106,774	)
Preferred stock redemption adjustment									345
Cash dividends on preferred stock															(1,689	)
Cash dividends on common stock															(8,000	)
Balance, December 31, 2005					6,290,000	$	188,700	$	71,136		$	-		$	37,097

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, 2003		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
Redemptions-
7.750% Series		(250,000	)		(25,000	)
7.625% Series								(127,500	)		(12,750	)
Balance, December 31, 2005		141,049		$	14,105			-		$	-
*  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.

18

PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31,	2005			2004			2003
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	65,865		$	59,076		$	48,451
Adjustments to reconcile net income to net cash from
operating activities -
Provision for depreciation		14,409			14,134			13,017
Amortization of regulatory assets		39,967			40,012			40,789
Nuclear fuel and other amortization		16,796			16,790			15,947
Deferred income taxes and investment tax credits, net		(12,390	)		5,011			(12,760	)
Cumulative effect of accounting change (Note 2(G))		-			-			(10,618	)
Pension trust contribution		(18,791	)		(12,934	)		-
Decrease (increase) in operating assets -
Receivables		13,320			1,919			16,276
Materials and supplies		(729	)		(4,005	)		(3,609	)
Prepayments and other current assets		177			459			(4,037	)
Increase (decrease) in operating liabilities -
Accounts payable		28,704			6,338			(11,163	)
Accrued taxes		14,577			(13,036	)		14,584
Accrued interest		5			(2,524	)		(1,162	)
Asset retirement obligation, net		-			(1,242	)		4,112
Other		130			5,097			5,814
Net cash provided from operating activities		162,040			115,095			115,641
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing -
Long-term debt		99			-			-
Short-term borrowings, net		4,815			518			11,334
Equity contributions from parent		-			65,000			-
Redemptions and Repayments -
Preferred stock		(37,750	)		(750	)		(750	)
Long-term debt		(10,370	)		(63,903	)		(41,155	)
Dividend Payments-
Common stock		(8,000	)		(23,000	)		(42,000	)
Preferred stock		(1,689	)		(2,560	)		(3,188	)
Net cash used for financing activities		(52,895	)		(24,695	)		(75,759	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(92,375	)		(93,320	)		(70,864	)
Contributions to nuclear decommissioning trusts		(1,594	)		(1,594	)		(1,594	)
Collection of principal on long-term notes receivable		113,638			6,452			370
Loan repayments from (payments to) associated companies		(50,287	)		(290	)		34,290
Other		(78,541	)		(1,650	)		(3,266	)
Net cash used for investing activities		(109,159	)		(90,402	)		(41,064	)
Net increase (decrease) in cash and cash equivalents		(14	)		(2	)		(1,182	)
Cash and cash equivalents at beginning of year		38			40			1,222
Cash and cash equivalents at end of year	$	24		$	38		$	40
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid During the Year-
Interest (net of amounts capitalized)	$	5,242		$	6,885		$	12,449
Income taxes	$	46,289		$	68,869		$	33,502
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

19

PENNSYLVANIA POWER COMPANY
CONSOLIDATED STATEMENTS OF TAXES
For the Years Ended December 31,	2005			2004			2003
				(In thousands)
GENERAL TAXES:
State gross receipts*	$	20,425		$	19,234		$	18,028
Real and personal property		2,330			1,288			2,262
State capital stock		2,049			2,014			952
Other		776			1,071			1,216
Total general taxes	$	25,580		$	23,607		$	22,458
PROVISION FOR INCOME TAXES:
Currently payable-
Federal	$	43,268		$	33,273		$	37,351
State		24,065			11,468			11,368
		67,333			44,741			48,719
Deferred, net-
Federal		(1,034	)		5,552			(2,424	)
State		(9,336	)		1,693			(392	)
		(10,370	)		7,245			(2,816	)
Investment tax credit amortization		(2,020	)		(2,234	)		(2,412	)
Total provision for income taxes	$	54,943		$	49,752		$	43,491
INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income	$	54,056		$	48,824		$	34,164
Other income		887			928			1,795
Cumulative effect of accounting change		-			-			7,532
Total provision for income taxes	$	54,943		$	49,752		$	43,491
RECONCILIATION OF FEDERAL INCOME TAX
EXPENSE AT STATUTORY RATE TO TOTAL
PROVISION FOR INCOME TAXES:
Book income before provision for income taxes	$	120,808		$	108,828		$	91,942
Federal income tax expense at statutory rate	$	42,283		$	38,090		$	32,180
Increases (reductions) in taxes resulting from-
State income taxes, net of federal income tax benefit		9,573			8,555			7,134
Amortization of investment tax credits		(2,020	)		(2,234	)		(2,412	)
Amortization of tax regulatory assets		1,661			1,658			1,650
Competitive transition charge		3,322			3,650			3,966
Other, net		124			33			973
Total provision for income taxes	$	54,943		$	49,752		$	43,491
ACCUMULATED DEFERRED INCOME TAXES AS OF
DECEMBER 31:
Property basis differences	$	66,970		$	87,584		$	77,147
Competitive transition charge		713			18,862			37,280
Asset retirement obligations		-			7,422			7,469
Customer receivables for future income taxes		84			1,471			2,860
Unamortized investment tax credits		(812	)		(1,335	)		(1,457	)
Deferred gain for asset sales- affiliated companies		7,342			7,451			8,106
Retirement benefits		4,874			(2,620)			(7,317	)
Other comprehensive income		-			(9,707	)		(8,335	)
Other		(12,595	)		(15,710	)		(17,882	)
Net deferred income tax liability	$	66,576		$	93,418		$	97,871
*Collected from customers through regulated rates and included in revenue in the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

20

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, which is a wholly owned subsidiary of FirstEnergy. In the fourth quarter of 2005, the Company completed the intra-system transfers of its fossil and nuclear generation assets to FGCO and NGC, respectively. See Note 11 - FirstEnergy Intra-System Generation Asset Transfers for further discussion. The Company follows GAAP and complies with the regulations, orders, policies and practices prescribed by the SEC, PPUC and FERC.  The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

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% 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 since 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:

	2005			2004
	(In millions)
Competitive transition costs	$	3		$	46
Customer receivables for future income taxes		-			4
Loss on reacquired debt		6			7
Nuclear decommissioning costs		(62	)		(69	)
Asset removal costs		(6	)		(7	)
Net regulatory liabilities	$	(59	)	$	(19	)

21

Pursuant to FirstEnergy's intra-system generation asset transfers (see Note 11), the Company transferred the ARO associated with its prior ownership interests in Beaver Valley and Perry to NGC, along with the nuclear decommissioning trust funds that are legally restricted for purposes of settling the ARO. Customer obligations regarding nuclear decommissioning costs remain as specified in the PPUC’s Order approving the Company’s Restructuring Plan. As of December 31, 2005, the Company continues to recognize a regulatory liability for nuclear decommissioning costs, as any excess or deficiency of trust funds to ultimately decommission the nuclear sites owned by the Company at the time of restructuring may be refunded to or recovered from customers.

Accretion on the ARO and depreciation on the associated asset retirement costs will reduce the intercompany receivable from NGC that was recognized as part of the nuclear generation asset transfer, with a corresponding reduction in the Company's regulatory liability for nuclear decommissioning costs. Unrealized gains and losses and earnings on the nuclear decommissioning trust funds held by NGC will also adjust the Company's intercompany receivable and regulatory liability balances.

(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.

(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, 2005 with respect to any particular segment of the Company’s customers. Total customer receivables were $45 million (billed - $28 million and unbilled - $17 million) and $44 million (billed - $28 million and unbilled - $16 million) as of December 31, 2005 and 2004, respectively.

(D)UTILITY PLANT AND DEPRECIATION-

Utility plant reflects original cost of construction, 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 2.4% in 2005 and 2.2% in 2004 and 2003.

(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.

(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, 2005, the Company does not have an accumulated other comprehensive balance. As of December 31, 2004, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $14 million.

22

(G)CUMULATIVE EFFECT OF ACCOUNTING CHANGE-

As a result of adopting SFAS 143 in January 2003, asset retirement costs were recorded in the amount of $78 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $9 million. The ARO liability on 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. 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 existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was $18 million increase to income ($11 million, net of tax) in the year ended December 31, 2003.

(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 “stand-alone” company basis, with the Company recognizing any tax losses or credits it contributed to the consolidated return.

(I)TRANSACTIONS WITH AFFILIATED COMPANIES-

Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily ATSI, FES, NGC and FESC. FES operates the generation businesses of the Company, OE, CEI and TE. As a result, the Company had entered into power supply agreements (PSA) whereby FES purchased all of the Company's nuclear generation and the generation from leased fossil generation facilities. In the fourth quarter of 2005, the Company, OE, CEI and TE completed the intra-system transfers of their generation assets to FGCO and NGC (see Note 11). This resulted in the elimination of the fossil generating units rent revenues and the nuclear generation PSA revenues. The Company is now receiving interest income from FGCO and NGC on the associated companies notes received in exchange for the transferred net assets. The Company continues to purchase its power from FES to meet its PLR 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. The primary affiliated companies transactions are as follows:

	2005		2004		2003
	(In millions)
Operating Revenues:
PSA revenues from FES	$	153	$	177	$	162
Generating units rent from FES		17		20		20
Ground lease with ATSI		1		1		1
Services Received:
Purchased power under PSA		176		181		166
Transmission facilities rentals		-		-		10
FESC support services		14		15		13
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. The majority of costs are directly billed or assigned at no more than cost. 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 developed by FESC. 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.

23

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 fourth quarter of 2005, FirstEnergy made a $500 million voluntary contribution to its pension plan (Company's share was $19 million). Projections indicated that absent this funding, cash contributions would have been required at some point prior to 2010. Pre-funding the pension plan is expected to eliminate this future funding requirement under current pension funding rules and should also minimize FirstEnergy's exposure to any funding requirements resulting from proposed pension reform.

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 upon retirement to employees hired prior to January 1, 2005, 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. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement for disability related 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 most of its plans.

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

24

Obligations and Funded Status	Pension Benefits							Other Benefits
As of December 31	2005			2004				2005			2004
	(In millions)
Change in benefit obligation
Benefit obligation as of January 1	$	4,364		$	4,162		$		1,930		$	2,368
Service cost		77			77				40			36
Interest cost		254			252				111			112
Plan participants’ contributions		-			-				18			14
Plan amendments		15			-				(312	)		(281	)
Actuarial (gain) loss		310			134				197			(211	)
Benefits paid		(270	)		(261	)			(100	)		(108	)
Benefit obligation as of December 31	$	4,750		$	4,364		$		1,884		$	1,930
Change in fair value of plan assets
Fair value of plan assets as of January 1	$	3,969		$	3,315		$		564		$	537
Actual return on plan assets		325			415				33			57
Company contribution		500			500				58			64
Plan participants’ contribution		-			-				18			14
Benefits paid		(270	)		(261	)			(100	)		(108	)
Fair value of plan assets as of December 31	$	4,524		$	3,969		$		573		$	564
Funded status	$	(226	)	$	(395	)	$		(1,311	)	$	(1,366	)
Unrecognized net actuarial loss		1,179			885				899			730
Unrecognized prior service cost (benefit)		70			63				(645	)		(378	)
Net asset (liability) recognized	$	1,023		$	553		$		(1,057	)	$	(1,014	)
Amounts Recognized in the Consolidated Balance Sheets As of December 31
Prepaid benefit cost	$	1,023		$			$		-		$
Accrued benefit cost		-			(14	)			(1,057	)		(1,014	)
Intangible assets		-			63				-			-
Accumulated other comprehensive loss		-			504				-			-
Net amount recognized	$	1,023		$	553		$		(1,057	)	$	(1,014	)
Company's share of net amount recognized	$	42		$	23		$		(46	)	$	(43	)
Decrease in minimum liability
Included in other comprehensive income
(net of tax)	$	(295	)	$	(4	)	$		-		$	-
Assumptions Used to Determine Benefit Obligations As of December 31
Discount rate		5.75	%		6.00	%			5.75	%		6.00	%
Rate of compensation increase		3.50	%		3.50	%

Allocation of Plan Assets As of December 31
Asset Category
Equity securities	63	%	68	%	71	%	74	%
Debt securities	33		29		27		25
Real estate	2		2		-		-
Cash	2		1		2		1
Total	100	%	100	%	100	%	100	%

Information for Pension Plans With an Accumulated Benefit Obligation in
Excess of Plan Assets	2005		2004
	(In millions)
Projected benefit obligation	$	4,750	$	4,364
Accumulated benefit obligation		4,327		3,983
Fair value of plan assets		4,524		3,969

25

	Pension Benefits									Other Benefits
Components of Net Periodic Benefit Costs	2005			2004			2003			2005			2004			2003
	(In millions)
Service cost	$	77		$	77		$	66		$	40		$	36		$	43
Interest cost		254			252			253			111			112			137
Expected return on plan assets		(345	)		(286	)		(248	)		(45	)		(44	)		(43	)
Amortization of prior service cost		8			9			9			(45	)		(40	)		(9	)
Amortization of transition obligation		-			-			-			-			-			9
Recognized net actuarial loss		36			39			62			40			39			40
Net periodic cost	$	30		$	91		$	142		$	101		$	103		$	177
Company's share of net periodic cost (income)	$	(1	)	$	-		$	4		$	5		$	5		$	7

Weighted-Average Assumptions Used
to Determine Net Periodic Benefit Cost	Pension Benefits									Other Benefits
for Years Ended December 31	2005			2004			2003			2005			2004			2003
Discount rate		6.00	%		6.25	%		6.75	%		6.00	%		6.25	%		6.75	%
Expected long-term return on plan assets		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%		9.00	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%

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 rates of return on pension plan assets consider 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 on 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 capitalization funds. 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	2005			2004
Health care cost trend rate assumed for next
year (pre/post-Medicare)		9-11	%		9-11	%
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)		2010-2012			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	$	23	$	(19	)
Effect on postretirement benefit obligation	$	239	$	(209	)

As a result of its voluntary contribution and the increased market value of pension plan assets, the Company recognized a prepaid benefit cost of $42 million as of December 31, 2005. As prescribed by SFAS 87, the Company eliminated its additional minimum liability of $29 million and its intangible asset of $6 million. In addition, the entire AOCL balance was credited by $14 million (net of $9 million of deferred taxes) as the fair value of trust assets exceeded the accumulated benefit obligation as of December 31, 2005.

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

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	Pension Benefits		Other Benefits
	(In millions)
2006	$	228	$	106
2007		228		109
2008		236		112
2009		247		115
2010		264		119
Years 2011 - 2015		1,531		642

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:

	2005				2004
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Long-term debt	$	200	$	204	$	148	$	160
Preferred stock subject to mandatory redemption		-		-		13		12
	$	200	$	204	$	161	$	172

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:

	2005				2004
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Debt securities:(1)
-Government obligations	$	-	$	-	$	41	$	41
-Corporate debt securities		284		269		77		83
-Mortgage-backed securities		-		-		1		1
		284		269		119		125
Equity securities(1)		-		-		57		57
	$	284	$	269	$	176	$	182

⁽¹⁾ Includes nuclear decommissioning trust investments as of December 31, 2004.

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.

Investments other than cash and cash equivalents include held-to-maturity securities and available-for-sale securities. Prior to their transfer to NGC (see Note 11), the Company’s decommissioning trust investments were classified as available-for-sale. The Company has no securities held for trading purposes.

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, 2005 were as follows:

	2005		2004		2003
	(In millions)
Proceeds from sales	$	75	$	41	$	47
Gross realized gains		11		1		2
Gross realized losses		1		1		1
Interest and dividend income		5		5		5

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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. Rentals for operating leases are charged to operating expenses on the Statements of Income. Such costs for the three years ended December 31, 2005, are summarized as follows:

	2005		2004		2003
	(In millions)
Operating leases
Interest element	$	0.6	$	0.4	$	0.3
Other		1.4		1.3		0.8
Total rentals	$	2.0	$	1.7	$	1.1

The future minimum lease payments as of December 31, 2005 are:

	Operating  Leases
		(In millions)
2006	$	1.0
2007		0.9
2008		0.9
2009		0.8
2010		0.7
Years thereafter		2.8
Total minimum lease payments		7.1

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

In May 2004, the PPUC issued an order approving revised reliability benchmarks 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, due to their implementation of automated outage management systems following restructuring. On December 30, 2005 the ALJ recommended that the PPUC adopt the Joint Petition for Settlement among the parties involved in the Company's request to amend the distribution reliability benchmarks, thereby eliminating the need for full litigation. The ALJ’s recommendation, adopting the revised benchmarks and standards was approved by the PPUC on February 9, 2006.

The EPACT provides for the creation of an ERO to establish and enforce reliability standards for the bulk power system, subject to FERC review. On February 3, 2006, the FERC adopted a rule establishing certification requirements for the ERO, as well as regional entities envisioned to assume monitoring responsibility for the new reliability standards.

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The NERC has been preparing the implementation aspects of reorganizing its structure to meet the FERC’s certification requirements for the ERO. The NERC will make a filing with the FERC to obtain certification as the ERO and to obtain FERC approval of delegation agreements with regional entities. The new FERC rule referred to above, further provides for reorganizing regional reliability organizations (regional entities) that would replace the current regional councils and for rearranging the relationship with the ERO. The “regional entity” may be delegated authority by the ERO, subject to FERC approval, for enforcing reliability standards adopted by the ERO and approved by the FERC. NERC also intends to make a parallel filing with the FERC seeking approval of mandatory reliability standards. These reliability standards are expected to be based on the current NERC Version 0 reliability standards with some additional standards. The two filings are expected to be made in the second quarter of 2006.

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

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

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

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

On December 29, 2005, the FERC issued an order setting the two power sales agreements for hearing. The order criticizes the Ohio competitive bid process, and requires FES to submit additional evidence in support of the reasonableness of the prices charged in the Ohio and Pennsylvania Contracts. A pre-hearing conference was held on January 18, 2006 to determine the hearing schedule in this case. FES expects an initial decision to be issued in this case in the fall of 2006. The outcome of this proceeding cannot be predicted. FES has sought rehearing of the December 29, 2005 order.

On October 11, 2005, the Company filed a plan with the PPUC to secure electricity supply for its customers at set rates following the end of its transition period on December 31, 2006. The Company is recommending that the RFP process cover the period January 1, 2007 through May 31, 2008. Hearings were held on January 10, 2006 with Main Briefs filed on January 27, 2006 and Reply Briefs on February 3, 2006. On February 17, 2006, the ALJ issued a Recommended Decision to adopt the Company's RFP process with modifications. A PPUC vote is expected in April 2006. Under Pennsylvania's electric competition law, the Company is required to secure generation supply for customers who do not choose alternative suppliers for their electricity.

7. CAPITALIZATION:

(A)   RETAINED EARNINGS-

Under the Company’s first mortgage indenture, the Company’s retained earnings unrestricted for payment of cash dividends on the Company’s common stock were $30 million as of December 31, 2005.

(B)   PREFERRED STOCK-

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

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

Other Long-Term Debt-

The Company has a first mortgage 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.

Sinking fund requirements for FMB and maturing long-term debt during the next five years are $70 million in 2006, $1 million in each year 2007 through 2009 and $64 million in 2010. Included in the 2006 amount are $15 million for variable interest rate long-term debt that have provisions by which individual debt holders are required to "put back" the respective debt to the issuer for redemption prior to its maturity date. This amount 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 noncancelable municipal bond insurance policies of $102 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the policies, the Company is entitled to a credit against its obligation to repay the related bond. The Company pays an annual fee of 0.24% to 0.30% of the amounts of the policies to the insurers and is obligated to reimburse the insurers for any drawings thereunder.

8.   ASSET RETIREMENT OBLIGATION:

In January 2003, the Company implemented SFAS 143, which provides accounting guidance for retirement obligations associated with tangible long-lived assets. 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 amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the ARO increases, resulting in a period expense. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount.

The Company initially identified applicable legal obligations as defined under the standard for nuclear power plant decommissioning of Beaver Valley and Perry nuclear generating facilities and reclamation of a sludge disposal pond related to the Bruce Mansfield Plant. The ARO liability as of 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. 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.

Pursuant to the generation asset transfers on October 24, 2005 and December 16, 2005, FGCO and NGC now own the fossil and nuclear generation assets, respectively, which were previously owned by the Company.

The Company implemented FIN 47, "Accounting for Conditional Asset Retirement Obligations", an interpretation of SFAS 143 on December 31, 2005. FIN 47 provides accounting standards for conditional retirement obligations associated with tangible long-lived assets, requiring recognition of the fair value of a liability for an ARO in the period in which it is incurred if a reasonable estimate can be identified. FIN 47 states that anobligation exists even though there may be uncertainty about timing or method of settlement andfurther clarifies SFAS 143, stating that the uncertainty surrounding the timing and method of settlement when settlement is conditional on a future event occurring should be reflected in the measurement of the liability not in the recognition of the liability. Accounting for conditional ARO under FIN 47 is the same as described above for SFAS 143. The adoption of FIN 47 had an immaterial impact on the Company’s year ended December 31, 2005.

The following table describes the changes to the ARO balances during 2005 and 2004.

	2005		2004
ARO Reconciliation	(In millions)
Balance at beginning of year	$	138	$	130
Transfer to FGCO and NCG		(155)		-
Accretion		9		8
Revisions in estimated cash flows		8		-
Balance at end of year	$	-	$	138

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9. SHORT-TERM BORROWINGS:

Short-term borrowings outstanding as of December 31, 2005, consisted of $13 million of borrowings from affiliates. Penn Funding, a wholly owned subsidiary of Penn, is a limited liability company whose borrowings are secured by customer accounts receivable purchased from Penn. It can borrow up to $25 million under a receivables financing arrangement at rates based on bank commercial paper rates. The financing arrangements require payment of an annual facility fee of 0.15% on the entire finance limit. Penn's receivables financing agreements expire in June 2006. As a separate legal entity with separate creditors, it would have to satisfy its separate obligations to creditors before any of its remaining assets could be made available to the Company.

In June 2005, the Company, FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed, Penelec, FES and ATSI, as Borrowers, entered into a syndicated $2 billion five-year revolving credit facility that expires in June 2010. Borrowings under the facility are available to each Borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. The Company's borrowing limit under the facility is $50 million. The average interest rate on short-term borrowings outstanding as of December 31, 2005 and 2004, was 4.0% and 2.0%, respectively.

10.COMMITMENTS AND CONTINGENCIES:

(A)   ENVIRONMENTAL MATTERS-

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

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

W. H. Sammis Plant

In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities alleging violations of the Clean Air Act based on operation and maintenance of 44 power plants, including the W. H. Sammis Plant, which was owned at that time by OE and Penn. In addition, the DOJ filed eight civil complaints against various investor-owned utilities, including a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey, and New York) that resolved all issues related to the W. H. Sammis Plant New Source Review litigation. This settlement agreement was approved by the Court on July 11, 2005, and requires reductions of NO_x and SO₂ emissions at the W. H. Sammis Plant and other coal fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if OE and Penn fail to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, OE and Penn could be exposed to penalties under the settlement agreement. Capital expenditures necessary to meet those requirements are currently estimated to be $1.5 billion (the primary portion of which is expected to be spent in the 2008 to 2011 time period). On August 26, 2005, FGCO entered into an agreement with Bechtel Power Corporation (Bechtel), under which Bechtel will engineer, procure, and construct air quality control systems for the reduction of sulfur dioxide emissions. The settlement agreement also requires OE and Penn to spend up to $25 million toward environmentally beneficial projects, which include wind energy purchased power agreements over a 20-year term. OE and Penn agreed to pay a civil penalty of $8.5 million. Results in 2005 included the penalties payable by OE and Penn of $7.8 million and $0.7 million, respectively. OE and Penn also recognized liabilities of $9.2 million and $0.8 million,respectively, for probable future cash contributions toward environmentally beneficial projects.

(B)    OTHER LEGAL PROCEEDINGS-

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

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Power Outages and Related Litigation-

On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. - Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy also is proceeding with the implementation of the recommendations regarding enhancements to regional reliability that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment, and therefore FirstEnergy has not accrued a liability as of December 31, 2005 for any expenditures in excess of those actually incurred through that date. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review FirstEnergy’s filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.

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

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

Nuclear Plant Matters-

As of December 16, 2005 NGC acquired ownership of the nuclear generation assets transferred from the Company, OE, CEI and TE with the exception of leasehold interests of OE and TE in certain of the nuclear plants that are subject to sale and leaseback arrangements with non-affiliates. The transfer included the Company's prior owned interests in Beaver Valley Unit 1 (65.00%), Beaver Valley Unit 2 (13.74%) and Perry (5.24%).

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

In an April 4, 2005 public meeting discussing FENOC’s performance at Perry identified in its annual assessment, NRC stated that, overall the Perry Plant operated "in a manner that preserved public health and safety" even though it remained under heightened NRC oversight. The NRC indicated that additional inspections will continue and that the plant must improve performance to be removed from the Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. By an inspection report dated January 18, 2006, the NRC closed one of the White Findings (related to emergency preparedness) which led to the multiple degraded cornerstones.

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

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

11. FIRSTENERGY INTRA-SYSTEM GENERATION ASSET TRANSFERS

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

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

The difference (approximately $2.7 million) between the purchase price specified in the Master Facility Lease and the net book value at the date of transfer was credited to equity. FGCO also assumed certain assets and liabilities relating to the purchased units. As consideration, FGCO delivered to the Company a promissory note of approximately $124.5 million that is secured by a lien on the units purchased, bears interest at a rate per annum based on the weighted cost of Penn’s long-term debt (5.39%) and matures twenty years after the date of issuance. FGCO may pre-pay a portion of the promissory note through refunding from time to time of Penn’s outstanding pollution control debt. The timing of any refunding will be subject to market conditions and other factors.

On December 16, 2005, the Company completed the intra-system transfer of its interests in the nuclear generation assets to NGC through a spin-off by way of dividend. FENOC will continue to operate and maintain the nuclear generation assets.

The purchase price of the generation assets was the net book value as of September 30, 2005. The difference (approximately $3.4 million) between the purchase price and the net book value at the date of transfer was credited to equity. Pursuant to the Penn Contribution Agreement, Penn previously acquired the common stock of NGC. Upon closing, Penn made a capital contribution to NGC of its undivided interests in certain nuclear generation assets, together with associated decommissioning trust funds and other related assets. In connection with the contribution, NGC assumed certain other liabilities associated with the transferred assets. In addition, Penn received a promissory note from NGC in the principal amount of approximately $240.4 million, representing the net book value of the contributed assets as of September 30, 2005, less other liabilities assumed. The note bears interest at a rate per annum based on Penn’s weighted average cost of long-term debt (5.39%), matures twenty years from the date of issuance, and is subject to prepayment at any time, in whole or in part, by NGC. Following the capital contribution, Penn distributed the common stock of NGC as a dividend (approximately $106.8 million) to its parent, OE, such that NGC became a wholly owned subsidiary of OE.

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

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The transfers are expected to affect the Company's near-term future results with reductions in revenues and expenses. Revenues will be reduced due to the termination of the sale of its nuclear generation KWH and the lease of its non-nuclear generation assets arrangements with FES. The Company's expenses will be lower due to the nuclear fuel and operating costs assumed by NGC as well as depreciation and property tax expenses assumed by FGCO and NGC related to the transferred generating assets. In addition, the Company will receive interest income from associated company notes receivable from FGCO and NGC for the transfer of our generation net assets and eliminate the interest expense on certain pollution control notes to be transferred to FGCO and NGC. FES will continue to provide the Company's PLR requirements revised purchased power arrangements for a three-year period beginning January 1, 2006 (see Note 6 - Regulatory Matters).

The following table provides the value of assets transferred along with the related liabilities:

Assets Transferred (In millions)
Property, plant and equipment	$	451
Other property and investments		150
Current assets		39
Deferred charges		-
	$	640
Liabilities Related to Assets Transferred
Long-term debt	$	-
Current liabilities		-
Noncurrent liabilities		174
	$	174
Net Assets Transferred	$	466

12.NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

FSP FAS 115-1 and FAS 124-1, "The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments"

Issued in November 2005, FSP 115-1 and FAS 124-1 addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. The FSP finalized and renamed EITF 03-1 and 03-1-a to FSP FAS 115-1. This FSP will (1) nullify certain requirements of Issue 03-1 and supersedes EITF topic No. D-44, "Recognition of Other Than Temporary Impairment upon the Planned Sale of a Security Whose Cost Exceeds Fair Value," (2) clarify that an investor should recognize an impairment loss no later than when the impairment is deemed other than temporary, even if a decision to sell has not been made, and (3) be effective for other-than-temporary impairment and analyses conducted in periods beginning after September 15, 2005. The FSP requires prospective application with an effective date for reporting periods beginning after December 15, 2005. The Company is currently evaluating this FSP Issue and any impact on its investments.

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

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

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

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

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

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

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

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

13.SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

The following summarizes certain consolidated operating results by quarter for 2005 and 2004:

	March 31,			June 30,		September 30,		December 31,
Three Months Ended	2005			2005		2005		2005
	(In millions)
Operating Revenues	$	134.5		$	134.3	$	145.5	$	126.3
Operating Expenses and Taxes		117.8			118.1		122.3		114.3
Operating Income		16.7			16.2		23.2		12.0
Other Income		(0.7	)		0.8		0.5		1.2
Net Interest Charges		1.0			1.3		0.7		1.0
Net Income	$	15.0		$	15.7	$	23.0	$	12.2
Earnings on Common Stock	$	14.3		$	15.0	$	22.9	$	12.0

	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

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