10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) of the SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) of the SECURITIES EXCHANGE ACT OF 1934

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification Number
1-267	ALLEGHENY ENERGY, INC.	13-5531602
	(A Maryland Corporation)
	800 Cabin Hill Drive
	Greensburg, Pennsylvania 15601
	Telephone (724) 837-3000
1-5164	MONONGAHELA POWER COMPANY	13-5229392
	(An Ohio Corporation)
	1310 Fairmont Avenue
	Fairmont, West Virginia 26554
	Telephone (304) 366-3000
1-3376-2	THE POTOMAC EDISON COMPANY	13-5323955
	(A Maryland and Virginia Corporation)
	800 Cabin Hill Drive
	Greensburg, Pennsylvania 15601
	Telephone (724) 837-3000
0-14688	ALLEGHENY GENERATING COMPANY	13-3079675
	(A Virginia Corporation)
	800 Cabin Hill Drive
	Greensburg, Pennsylvania 15601
	Telephone (724) 837-3000

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Allegheny Energy, Inc.	Yes	x	No	¨
Monongahela Power Company	Yes	¨	No	x
The Potomac Edison Company	Yes	¨	No	x
Allegheny Generating Company	Yes	¨	No	x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Allegheny Energy, Inc.	¨
Monongahela Power Company	¨
The Potomac Edison Company	¨
Allegheny Generating Company	¨

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) have been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act).

	Large accelerated filer	Accelerated filer	Non-accelerated filer
Allegheny Energy, Inc.	x	¨	¨
Monongahela Power Company	¨	¨	x
The Potomac Edison Company	¨	¨	x
Allegheny Generating Company	¨	¨	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Allegheny Energy, Inc.	Yes	¨	No	x
Monongahela Power Company	Yes	¨	No	x
The Potomac Edison Company	Yes	¨	No	x
Allegheny Generating Company	Yes	¨	No	x

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of each class	Name of each exchange on which registered
Allegheny Energy, Inc.	Common Stock, $1.25 par value	New York Stock Exchange Chicago Stock Exchange Pacific Stock Exchange
Monongahela Power Company	Cumulative Preferred Stock, $100 par value: 4.40% 4.50%, Series C	American Stock Exchange American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Allegheny Generating Company	Common Stock, $1.00 par value	None

	Aggregate market value of voting and non-voting common equity held by nonaffiliates of the registrants at June 30, 2005	Number of shares of common stock of the registrants outstanding at February 24, 2006
Allegheny Energy, Inc.	$4,083,469,189	163,182,102 ($1.25 par value)
Monongahela Power Company	None (a)	5,891,000 ($50 par value)
The Potomac Edison Company	None (a)	22,385,000 ($.01 par value)
Allegheny Generating Company	None (b)	1,000 ($1.00 par value)

(a) All outstanding common stock is held by Allegheny Energy, Inc.

(b) All outstanding common stock is held by Allegheny Generating Company’s parent companies, Monongahela Power Company and Allegheny Energy Supply Company, LLC.

Documents Incorporated by Reference

Portions of the Allegheny Energy, Inc. definitive Proxy Statement for its 2006 Annual Meeting of Stockholders are incorporated by reference to Part III of this Annual Report on Form 10-K.

GLOSSARY

I. The following abbreviations and terms are used in this report to identify Allegheny Energy, Inc. and its subsidiaries:

ACC	Allegheny Communications Connect, Inc., a subsidiary of Allegheny Ventures
AE	Allegheny Energy, Inc., a diversified utility holding company
AESC	Allegheny Energy Service Corporation, a wholly owned subsidiary of AE
AE Solutions	Allegheny Energy Solutions, Inc., a subsidiary of Allegheny Ventures
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC	Allegheny Generating Company, an unregulated generation subsidiary of AE Supply and Monongahela
Allegheny	Allegheny Energy, Inc., together with its consolidated subsidiaries
Allegheny Ventures	Allegheny Ventures, Inc., a nonutility, unregulated subsidiary of AE
Distribution Companies	Collectively, Monongahela, Potomac Edison and West Penn, which do business as Allegheny Power
Green Valley Hydro	Green Valley Hydro, LLC, a subsidiary of AE
Monongahela	Monongahela Power Company, a regulated subsidiary of AE
Potomac Edison	The Potomac Edison Company, a regulated subsidiary of AE
West Penn	West Penn Power Company, a regulated subsidiary of AE

II. The following abbreviations and acronyms are used in this report to identify entities and terms relevant to Allegheny’s business and operations:

Bcf	Billion cubic feet
CDD	Cooling Degree-Days
CDWR	California Department of Water Resources
Clean Air Act	Clean Air Act of 1970
EPA	United States Environmental Protection Agency
Energy Policy Act	Energy Policy Act of 2005
Exchange Act	Securities Exchange Act of 1934, as amended
FERC	Federal Energy Regulatory Commission, an independent commission within the U. S. Department of Energy
FPA	Federal Power Act
GAAP	Generally accepted accounting principles used in the United States of America
HDD	Heating Degree-Days
KW	Kilowatt, which is equal to 1,000 watts
kWh	Kilowatt-hour, which is a unit of electric energy equivalent to one kilowatt operating for one hour
Maryland PSC	Maryland Public Service Commission
MW	Megawatt, which is equal to 1,000,000 watts
MWh	Megawatt-hour, which is a unit of electric energy equivalent to one megawatt operating for one hour
NSR	The New Source Performance Review Standards, or “New Source Review,” applicable to facilities deemed “new” sources of emissions by the EPA
OVEC	Ohio Valley Electric Corporation
Pennsylvania PUC	Pennsylvania Public Utility Commission
PJM	PJM Interconnection, L.L.C., a regional transmission organization
PLR	Provider-of-last-resort
PUCO	Public Utilities Commission of Ohio
PUHCA 1935	Public Utility Holding Company Act of 1935, as amended
PUHCA 2005	Public Utility Holding Company Act of 2005
PURPA	Public Utility Regulatory Policies Act of 1978
RTO	Regional Transmission Organization
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
T&D	Transmission and distribution
Virginia SCC	Virginia State Corporate Commission
West Virginia PSC	Public Service Commission of West Virginia

CONTENTS

Item 1.	Business	1
	Overview	1
	Special Note Regarding Forward-Looking Statements	8
	Allegheny’s Sales And Revenues	9
	Capital Expenditures	10
	Electric Facilities	11
	Fuel, Power And Resource Supply	16
	Regulatory Framework Affecting Allegheny	19
	Federal Regulation And Rate Matters	19
	Employees	27
	Environmental Matters	28
	Research And Development	32
Item 1A.	Risk Factors	33
Item 2.	Properties	42
Item 3.	Legal Proceedings	43
Item 4.	Submission Of Matters To A Vote Of Security Holders	47
Item 5.	Market For The Registrants’ Common Equity And Related Stockholder Matters	48
Item 6.	Selected Financial Data	50
Item 7.	Management’s Discussion And Analysis Of Financial Condition And Results Of Operations	54
Item 7a.	Quantitative And Qualitative Disclosures About Market Risk	121
Item 8.	Financial Statements And Supplementary Data	124
Item 10.	Directors And Executive Officers Of The Registrants	270
Item 11.	Executive Compensation	274
Item 12.	Security Ownership Of Certain Beneficial Owners And Management And Related Stockholder Matters	288
Item 13.	Certain Relationships And Related Transactions	287
Item 14.	Principal Accountant Fees And Services	287
Item 15.	Exhibits And Financial Statement Schedules	289
Supplemental Information To Be Furnished With Reports Filed Pursuant To Section 15(D) Of The Exchange Act By Registrants Which Have Not Registered Securities Pursuant To Section 12 Of The Exchange Act		289
Signatures		290

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY ENERGY, INC., MONONGAHELA POWER COMPANY, THE POTOMAC EDISON COMPANY AND ALLEGHENY GENERATING COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY THE REGISTRANT ON ITS OWN BEHALF. NONE OF THE REGISTRANTS MAKES ANY REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.

PART I

ITEM 1.    BUSINESS

OVERVIEW

Allegheny is an integrated energy business that owns and operates electric generation facilities and delivers electric services to customers in Pennsylvania, West Virginia, Maryland, and Virginia. AE, Allegheny’s parent holding company, was incorporated in Maryland in 1925. Allegheny operates its business primarily through AE’s various directly and indirectly owned subsidiaries.

Allegheny has two business segments:

• The Delivery and Services segment includes Allegheny’s electric T&D operations.

• The Generation and Marketing segment includes Allegheny’s power generation operations.

Allegheny also conducted electric T&D operations in Ohio and natural gas T&D operations in West Virginia until it sold these operations as of December 31, 2005 and September 30, 2005, respectively. Monongahela agreed to sell power at a fixed price to Columbus Southern Power Company (“Columbus Southern”), the purchaser of its electric T&D operations in Ohio, to serve Monongahela’s former Ohio customers until May 31, 2007. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—2005 Asset Sales.”

The Delivery and Services Segment

The principal companies and operations in AE’s Delivery and Services segment include the following:

• The Distribution Companies include Monongahela (excluding its West Virginia generation assets), Potomac Edison and West Penn. Each of the Distribution Companies is a public utility company and does business under the trade name Allegheny Power. Allegheny Power’s principal business is the operation of electric public utility systems.

• Monongahela was incorporated in Ohio in 1924. It conducts an electric T&D business that serves approximately 371,400 electric customers in northern West Virginia in a service area of approximately 12,400 square miles with a population of approximately 769,700. Monongahela’s Delivery and Services segment had operating revenues of $691.4 million in 2005. Monongahela also has generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below. Monongahela also conducted electric T&D operations in Ohio and natural gas T&D operations in West Virginia until it sold the assets related to these operations as of December 31, 2005 and September 30, 2005, respectively. Monongahela agreed to sell power to Columbus Southern to serve Monongahela’s former Ohio customers until May 31, 2007.

• Potomac Edison was incorporated in Maryland in 1923 and was also incorporated in Virginia in 1974. It operates an electric T&D system in portions of West Virginia, Maryland and Virginia. Potomac Edison serves approximately 454,400 electric customers in a service area of about 7,300 square miles with a population of approximately 1.2 million. Potomac Edison’s 2005 total operating revenues were $971.2 million. One industrial customer accounted for 12.9% of Potomac Edison’s operating revenues in each of 2004 and 2005. It is anticipated that this customer, which curtailed its operations in December 2005, will have significantly reduced electric usage in 2006.

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• West Penn was incorporated in Pennsylvania in 1916. It operates an electric T&D system in southwestern, south-central and northern Pennsylvania. West Penn serves approximately 702,800 customers in a service area of about 9,900 square miles with a population of approximately 1.5 million. West Penn’s 2005 total operating revenues were $1,184.1 million.

In April 2002, the Distribution Companies transferred operational control over their transmission systems to PJM. See “The Distribution Companies’ Obligations and the PJM Market” below.

• Allegheny Ventures is a nonutility, unregulated subsidiary of AE that was incorporated in Delaware in 1994. Allegheny Ventures engages in telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal wholly-owned subsidiaries, ACC and AE Solutions. Both ACC and AE Solutions are Delaware corporations. ACC develops fiber-optic projects, including fiber and data services. AE Solutions manages energy-related projects. Allegheny Ventures’s 2005 total operating revenues were $30.7 million.

During 2005, the Delivery and Services segment had operating revenues of $2,845.5 million and net income of $113.2 million. As of December 31, 2005, the Delivery and Services segment held $4.1 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 7, “Business Segments,” to the Consolidated Financial Statements.

The Generation and Marketing Segment

The principal companies and operations in AE’s Generation and Marketing segment include the following:

• AE Supply is a Delaware limited liability company formed in 1999. AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities. As of December 31, 2005, AE Supply owned or contractually controlled 8,245 MWs of generation capacity. AE Supply markets its electric generation capacity to various customers and markets. Currently, the majority of the Generation and Marketing segment’s normal operating capacity is committed to supplying the PLR and other obligations of the Distribution Companies. AE Supply’s 2005 total operating revenues were $1,371.1 million.

• Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment. As of December 31, 2005, Monongahela owned or contractually controlled 2,130 MWs of generation capacity. Monongahela’s Generation and Marketing segment had operating revenues of $415.5 million in 2005. Currently, the majority of Monongahela’s Generation and Marketing segment’s normal operating capacity is committed to supplying Monongahela’s Delivery and Services segment.

• AGC was incorporated in Virginia in 1981. AGC is owned approximately 77% by AE Supply and approximately 23% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric station and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,010 MWs share of generation capacity from the Bath County generation station to AE Supply and Monongahela. AGC’s 2005 total operating revenues were $66.6 million.

AE Supply is obligated under contracts with Potomac Edison and West Penn to provide Potomac Edison and West Penn with the power that they need to meet a majority of their PLR obligations. AE Supply sells power into the PJM market and purchases power from the PJM market to meet its obligations under these contracts. See “The Distribution Companies’ Obligations and the PJM Market” below.

Although most of the Generation and Marketing segment’s generation capacity is sold into the PJM market, its generation facility in Gleason, Tennessee is outside of PJM. The Gleason generation facility has been classified as held for sale, and its results have been presented as discontinued operations in the accompanying Consolidated Statements of Operations.

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During 2005, the Generation and Marketing segment had operating revenues of $1,703.3 million and a net loss of $50.1 million. As of December 31, 2005, the Generation and Marketing segment held $4.0 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 7, “Business Segments,” to the Consolidated Financial Statements.

Intersegment Services

AESC was incorporated in Maryland in 1963 as a service company for AE. AESC employs substantially all of the employees who provide services to AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures and their respective subsidiaries. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had approximately 4,460 employees as of December 31, 2005.

The Distribution Companies’ Obligations and the PJM Market

Allegheny’s business has been significantly influenced by state and federal deregulation initiatives, including the implementation of retail choice and plans to transition from cost-based to market-based rates, as well as by the development of wholesale electricity markets and RTOs, particularly PJM.

Each of the states in Allegheny’s service territory other than West Virginia has, to some extent, deregulated its electric utility industry. Pennsylvania, Maryland and Virginia have instituted retail customer choice and are transitioning to market-based, rather than cost-based pricing for generation. In West Virginia, the rates charged to retail customers are regulated by the West Virginia PSC and are determined through traditional, cost-based, regulated utility rate-making.

West Penn has PLR obligations to its customers in Pennsylvania. Potomac Edison has PLR obligations to its customers in Virginia and its residential customers in Maryland. As “providers of last resort,” West Penn and Potomac Edison must supply power to certain retail customers who have not chosen alternative suppliers (or have chosen to return to Allegheny service) at rates that are capped at various levels during the applicable transition period. The transition periods vary across Allegheny’s service area and across customer class:

• Potomac Edison. In Maryland, the transition period for residential customers ends on December 31, 2008. The transition period for commercial and industrial customers ended on December 31, 2004. The generation rates that Potomac Edison charges residential customers in Maryland are capped through December 31, 2008, while the T&D rate caps for all customers expired on December 31, 2004. A statewide settlement approved by the Maryland PSC in 2003 extends Potomac Edison’s obligation to provide residential “standard offer service” (“SOS”) at market based rates beyond the expiration of the transition periods. In Virginia, the transition period ends on December 31, 2010. For a more detailed discussion, see “Regulatory Framework Affecting Allegheny” below.

• West Penn. In Pennsylvania, the transition period terminates on December 31, 2010. As part of a May 11, 2005 order approving a settlement, the Pennsylvania PUC extended Pennsylvania’s generation rate caps from 2008 to 2010. The settlement approved by the Pennsylvania PUC also extended distribution rate caps from 2005 to 2007, with an additional rate cap in place for 2009 at the rate in effect on January 1, 2009, and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously-approved increases for 2006 and 2008. Rate caps on transmission services expired on December 31, 2005.

These transition periods could be altered by legislative, judicial or, in some cases, regulatory actions. See “Regulatory Framework Affecting Allegheny” below.

Potomac Edison and West Penn have contracts with AE Supply under which AE Supply provides Potomac Edison and West Penn with the majority of the power necessary to meet their PLR obligations. All but

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one of Allegheny’s generation facilities are located within the PJM market, and virtually all of the power that the Generation and Marketing segment generates is sold into the PJM market. AE Supply sells the power that it generates into the PJM market and purchases from the PJM market the power necessary to meet its obligations to supply power. Prevailing market prices are generally higher than the capped rates currently applicable to most of these PLR obligations.

To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets to AE Supply at PJM market prices, and that power is then sold into the PJM market. Monongahela purchases from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load.

In connection with the sale of its electric T&D operations in Ohio, Monongahela agreed to sell power at a fixed price to Columbus Southern to serve Monongahela’s former Ohio customers through May 2007. Monongahela purchases the power required to meet this obligation from the PJM market.

As an RTO, PJM coordinates the movement of electricity over the transmission grid in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

For a more detailed discussion, see “Fuel, Power and Resource Supply,” “Regulatory Framework Affecting Allegheny” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview” below.

Strategy

Allegheny’s long-term strategy is to focus on its core generation and T&D businesses. Allegheny’s management believes that this emphasis is enabling Allegheny to take advantage of its regional presence, operational expertise and knowledge of its markets.

Prior to 1999, Allegheny functioned as an integrated regulated utility within its service area. In response to federal and state deregulation initiatives, however, Allegheny separated part of its energy generation business from its T&D business by transferring a portion of its generation assets to AE Supply. Allegheny’s former senior management sought to transform AE Supply into a national power merchant in order to capitalize on these regulatory and other energy industry trends. As part of this strategy, AE Supply acquired generation assets, which collectively expanded Allegheny’s owned or controlled generation capacity by nearly one-third. AE Supply also began construction of new generation facilities. In addition, AE Supply purchased the energy trading division of Merrill Lynch in 2001. With this acquisition, the focus of AE Supply’s energy trading shifted from asset backed, short-term trading in and around its generation assets to more speculative trading activities. This expansion was financed primarily through debt. Beginning in 2002, difficult market conditions, changes in the regulatory environment and Allegheny’s worsening credit profile placed Allegheny in a weakened financial position. Beginning in June 2003, Allegheny’s new senior management implemented recovery plans and new long-term strategies.

Significant recent achievements include:

• Focusing on the Core Business.  Allegheny has reoriented its business to focus on its core businesses and assets. In 2005 and 2004, Allegheny completed a number of significant sales of non-core assets, including:

• the September 2005 sale by Monongahela of its West Virginia natural gas T&D business for cash proceeds of approximately $161 million and the assumption by the purchaser of approximately $87 million of debt;

• the August 2005 sale by AE Supply of its Wheatland generation facility for approximately $100 million;

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• the December 2004 sale by AE Supply of its 672 MW natural gas-fired Lincoln generation facility and an accompanying tolling agreement for approximately $175 million; and

• the December 2004 sale by AE of a 9% interest in OVEC (AE continues to hold a 3.5% interest in OVEC) for $102 million in cash, $96 million of which was received at the closing of the transaction and the remaining $6 million of which is expected to be received in April, 2006, upon the satisfaction of certain conditions.

In addition, in December 2005, Monongahela sold its electric T&D operations in Ohio for net cash proceeds of approximately $52 million.

Allegheny also exited its speculative trading activities in the Western U. S. and other energy markets in 2003 through, among other transactions, the sale of AE Supply’s contract with the CDWR and related hedge transactions to J. Aron & Company, a subsidiary of the Goldman Sachs Group, Inc., for $354 million. Allegheny continues to pursue the disposition of additional non-core assets, including its Gleason generating facility. See ‘Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and Note 4, “Asset Sales,” to the Consolidated Financial Statements.

In addition, Allegheny has announced a proposal to build the Trans-Allegheny Interstate Line. The proposed 500-kV line will span approximately 330 miles, all within Allegheny’s region of the PJM market, the APS Zone, from the Weirton, West Virginia area to near Kemptown, Maryland. The proposed line is subject to approval by PJM, as well as to various regulatory approvals. Initial engineering and planning is expected to begin in 2007, with the first segment in place in 2013. The projected cost is approximately $1.4 billion.

• Substantially Reducing and Proactively Managing Debt.  Between December 1, 2003 and December 31, 2005, Allegheny restructured much of its debt and reduced debt by approximately $1.9 billion, significantly exceeding its goal of reducing debt by $1.5 billion during this period. This restructuring effort included debt reductions of approximately $920 million in 2005 alone.

Through these restructuring efforts, Allegheny secured more favorable terms and conditions with respect to much of its debt, including reduced interest rates. The refinancings undertaken by Allegheny since 2003, together with lower debt balances, yielded a reduction in adjusted interest expense from 2004 to 2005 of approximately $60 million. The reductions in interest expense, coupled with the reductions in debt and general improvements in Allegheny’s financial condition, have led to multiple upgrades in Allegheny’s credit ratings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Changes in Credit Ratings” below and Note 2, “Capitalization,” to the Consolidated Financial Statements.

• Improving Liquidity.  Allegheny has improved its liquidity through prudent cash management, opportunistic sales of non-core assets, cutting costs and expenses, extending debt maturities and other financing strategies. The 2004 refinancing of AE’s credit facility established a revolving credit facility for AE, and an additional refinancing of that facility in 2005 doubled the size of the revolving credit facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” below and Note 2, “Capitalization,” to the Consolidated Financial Statements.

• Maximizing Operational Efficiency.  Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation facilities (those that utilize steam pressure in excess of 3,200 pounds per square inch). Allegheny also is seeking to optimize operations and maintenance costs for its other generation facilities, T&D assets and related corporate functions, to reduce costs and to pursue other productivity improvements necessary to build a high performance organization.

For example, as part of a program to improve its processes and technology, AE entered into a Professional Services Agreement in September 2005 with Electronic Data Systems Corporation and

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EDS Information Services, LLC (together, the “Service Provider”), under which, on November 1, 2005, the Service Provider assumed responsibility for many of Allegheny’s information technology functions. The Service Provider also will assist with the implementation of an enterprise resource planning system. Additionally, Allegheny has entered into various coal supply contracts in an effort to ensure a consistent supply of coal at predictable prices, and currently has contracts in place for the delivery of approximately 98% of its expected coal needs for 2006. See “Business—Fuel, Power and Resource Supply.”

• Maximizing Generation Value.  Allegheny is working to maximize the value of the power that it generates by ensuring full recovery of its costs and a reasonable return through the traditional rate-making process for its regulated utilities, as well as through the transition to market prices for AE Supply and its subsidiaries.

For example, in April 2005, Allegheny obtained approval from the Pennsylvania PUC for increases in applicable rate caps in 2007, 2009 and 2010 in connection with a two-year extension of the period during which Pennsylvania customers will transition to market prices. Together with previously approved rate cap increases for 2006 and 2008, these increases will gradually move generation rates in Pennsylvania closer to market prices. In addition, AE Supply won the contracts to serve the PLR customer load in Pennsylvania in 2009 and 2010 and entered into contracts to provide power to Potomac Edison to serve commercial, industrial and municipal customer loads in Maryland. See “Fuel, Power and Resource Supply” and “Regulatory Matters Affecting Allegheny” below.

• Managing Environmental Compliance and Risks.  Allegheny is working to effectively manage its environmental compliance efforts to ensure continuing compliance with applicable federal and state regulations while controlling its compliance costs, reducing emissions levels and minimizing its risk exposure. Among other initiatives, AE Supply and Monongahela are currently blending lower-sulfur Powder River Basin coal at several generation facilities and are working to implement the financing and construction of flue gas desulfurization units and related pollution control equipment at the Fort Martin generation facility in West Virginia and the Hatfield generation facility in Pennsylvania, as well as other pollution control projects at other facilities. See “Environmental Matters” and “Proposed Asset Swap and Securitization” below.

Allegheny’s management believes that it can continue to build on these successes in 2006 through ongoing debt reduction and other financial improvement efforts, further initiatives to improve operational efficiency and maximize generation value and continued environmental stewardship.

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Where You Can Find More Information

AE, Monongahela, Potomac Edison and AGC file or furnish Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements (for AE) and other information with or to the SEC. You may read and copy any document that the registrants file with the SEC at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. These SEC filings are also available to the public from the SEC’s website at http://www.sec.gov.

The Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements, statements of changes in beneficial ownership and other SEC filings, and any amendments to those reports, that AE, Monongahela, Potomac Edison and AGC file with or furnish to the SEC under the Exchange Act are made available free of charge on AE’s website at http://www.alleghenyenergy.com as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. Audited annual financial statements for AE Supply and West Penn, neither of which is a reporting company under the Exchange Act, also will be available on AE’s website. AE’s website and the information contained therein are not incorporated into this report.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

In addition to historical information, this report contains a number of forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Words such as anticipate, expect, project, intend, plan, believe and words and terms of similar substance used in connection with any discussion of future plans, actions or events identify forward-looking statements. These include statements with respect to:

• rate regulation and the status of retail generation service supply competition in states served by the Distribution Companies;

• financing plans;

• demand for energy and the cost and availability of raw materials, including coal;

• PLR and power supply contracts;

• results of litigation;

• results of operations;

• internal controls and procedures;

• capital expenditures;

• status and condition of plants and equipment;

• capacity purchase commitments;

• regulatory matters; and

• accounting issues.

Forward-looking statements involve estimates, expectations and projections and, as a result, are subject to risks and uncertainties. There can be no assurance that actual results will not differ materially from expectations. Actual results have varied materially and unpredictably from past expectations. Factors that could cause actual results to differ materially include, among others, the following:

• plant performance and unplanned outages;

• changes in the price of power and fuel for electric generation;

• general economic and business conditions;

• changes in access to capital markets;

• complications or other factors that make it difficult or impossible to obtain necessary lender consents or regulatory authorizations on a timely basis;

• environmental regulations;

• the results of regulatory proceedings, including proceedings related to rates;

• changes in industry capacity, development and other activities by Allegheny’s competitors;

• changes in the weather and other natural phenomena;

• changes in customer switching behavior and their resulting effects on existing and future PLR load requirements;

• changes in the underlying inputs and assumptions, including market conditions, used to estimate the fair values of commodity contracts;

• changes in laws and regulations applicable to Allegheny, its markets or its activities;

• the loss of any significant customers or suppliers;

• dependence on other electric transmission and gas transportation systems and their constraints on availability;

• changes in PJM, including changes to participant rules and tariffs;

• the effect of accounting guidance issued periodically by accounting standard-setting bodies; and

• the continuing effects of global instability, terrorism and war.

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ALLEGHENY’S SALES AND REVENUES

The Generation and Marketing Segment’s Sales and Revenues

The Generation and Marketing segment had operating revenues of $1,703.3 million and $1,538.7 million in 2005 and 2004, respectively. For more information regarding the Generation and Marketing segment’s operating revenues, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 7, “Business Segments,” to the Consolidated Financial Statements.

The Delivery and Services Segment’s Sales and Revenues

The Delivery and Services segment had operating revenues of $2,845.5 million and $2,764.1 million in 2005 and 2004, respectively. These revenues included revenue from electric sales and unregulated services. There were $1,510.9 million and $1,546.7 million of intersegment sales and revenues between the Generation and Marketing segment and the Delivery and Services segment in 2005 and 2004, respectively, which were eliminated for Allegheny’s consolidated results of operations. The following tables describe the segment’s kWh sales and revenues from electric sales:

kWh sales (in millions):	2005		2004		% Change
Retail:
Residential		16,923		16,047	5.5	%
Commercial and Industrial		31,249		31,052	0.6	%
Other		103		102	1.0	%
Total retail		48,275		47,201	2.3	%
Revenues (in millions):	2005		2004		% Change
Retail:
Residential	$	1,164.9	$	1,109.2	5.0	%
Commercial and industrial		1,490.4		1,447.4	3.0	%
Other		15.6		15.0	4.0	%
Subtotal retail	$	2,670.9	$	2,571.6	3.9	%
Transmission services and bulk power		115.9		127.8	(9.3	)%
Other affiliated and nonaffiliated energy services		58.7		64.7	(9.3	)%
Total Delivery and Services revenues	$	2,845.5	$	2,764.1	2.9	%

Allegheny had operating revenues from discontinued operations of $218.5 million and $335.7 million for the years ended December 31, 2005 and 2004, respectively. These revenues primarily related to its natural gas T&D business in West Virginia, which was sold on September 30, 2005. For more information regarding the Delivery and Services segment’s revenues, see “Management’s Discussion and Analysis of Financial Condition and Operating Results” and Note 7, “Business Segments,” to the Consolidated Financial Statements.

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CAPITAL EXPENDITURES

The table below shows total capital expenditures for Allegheny in 2005 and estimated capital expenditures for 2006 and 2007, as well as the environmental control expenditures that are included in these capital expenditures or estimated capital expenditures.

	2005		2006		2007
(In millions)	(Actual)		(Estimated)
Generation and Marketing:
AE Supply
Total	$	84.3	$	165.0	$	315.0
Environmental		44.3		118.0		253.0
Monongahela
Total		24.4		52.0		87.0
Environmental		13.8		38.0		81.0
AGC
Total		13.0		10.0		6.0
Environmental		—		—		—
Total Generation and Marketing capital expenditures	$	121.7	$	227.0	$	408.0
Delivery and Services:
Potomac Edison
Total	$	74.0	$	81.0	$	98.0
Environmental		—		—		—
West Penn
Total		63.4		72.0		83.0
Environmental		—		—		—
Monongahela
Total		47.3		49.0		54.0
Environmental		—		—		—
Allegheny Ventures
Total		0.1		1.0		1.0
Environmental		—		—		—
Total Delivery and Services capital expenditures	$	184.8	$	203.0	$	236.0
Total capital expenditures	$	306.5	$	430.0	$	644.0

The Generation and Marketing segment’s capital expenditures include projects at generation facilities for environmental control upgrades and to remediate or prevent equipment failure. The Delivery and Services segment’s capital expenditures include projects to upgrade distribution lines and substations, as well as transmission and subtransmission systems enhancements. The amounts shown above include allowance for funds used during construction (“AFUDC”) for the Distribution Companies and Monongahela’s generation and marketing segment and capitalized interest for AE Supply. AFUDC and capitalized interest include the non-cash cost, for the period of construction, of borrowed funds used for construction purposes and a reasonable rate on other funds used in construction.

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ELECTRIC FACILITIES

All of Allegheny’s owned or controlled generation capacity is part of the Generation and Marketing segment. The Distribution Companies are obligated to purchase 479 MWs of power through state utility commission-approved arrangements pursuant to PURPA. This PURPA capacity is part of the Delivery and Services segment. See “PURPA Capacity” below.

Allegheny’s owned and controlled capacity as of December 31, 2005 was 10,375 MWs, of which 7,830 MWs (75.5%) were coal-fired, 1,395 MWs (13.4%) were natural gas-fired, 1,068 MWs (10.3%) were pumped-storage and hydroelectric and 82 MWs (0.8%) were oil-fired.

AE holds a 3.5% equity stake in, and is a sponsoring company of, OVEC. Currently, AE Supply and Monongahela are entitled to 9% (202 MWs) and 3.5% (78 MWs), respectively, of OVEC generation. OVEC supplies power to its sponsoring companies under an intercompany power agreement that expires on March 12, 2006. A new intercompany power agreement will go into effect on March 13, 2006. In December 2004, AE sold a 9% equity interest in OVEC to Buckeye Power Generating, LLC (“Buckeye”). In connection with the sale, AE Supply retained its right to 9% of OVEC’s generation under the existing intercompany power agreement through March 12, 2006, but assigned to Buckeye all of its rights and obligations under the new intercompany power agreement effective on March 13, 2006.

In August 2005, AE Supply sold its Wheatland generation facility, a 512 MWs natural gas-fired peaking facility located in Knox County, Indiana. AE Supply is also currently seeking to sell its Gleason generation facility in Gleason, Tennessee.

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The table below shows the nominal maximum operational generation capacity owned or controlled by Allegheny, as of December 31, 2005. This generation is included in the Generation and Marketing segment. Allegheny is currently contemplating an intra-company transfer of assets that would realign generation ownership and contractual arrangements within the Allegheny system. See “Proposed Asset Swap and Securitization” below.

Nominal Maximum Operational Generation Capacity (MW)

	Units	Project Total	Regulated	Unregulated	Service Commencement Dates (a)
Stations			Monongahela	AE Supply and Other
Coal Fired-Supercritical (Steam):
Harrison (Haywood, WV)	3	1,972	419	1,553	1972-74
Hatfield’s Ferry (Masontown, PA)	3	1,710	400	1,310	1969-71
Pleasants (Willow Island, WV)	2	1,300	277	1,023	1979-80
Fort Martin (Maidsville, WV)	2	1,107	212	895	1967-68
Coal Fired-Other (Steam):
Armstrong (Adrian, PA)	2	356		356	1958-59
Albright (Albright, WV)	3	292	184	108	1952-54
Mitchell (Courtney, PA)	1	288		288	1963
Ohio Valley Electric Corp. (Chelsea, OH) (Madison, IN) (b)	11	280	78	202
Willow Island (Willow Island, WV)	2	243	207	36	1949-60
Rivesville (Rivesville, WV)	2	142	121	21	1943-51
R. Paul Smith (Williamsport, MD)	2	116		116	1947-58
Hunlock (Hunlock Creek, PA) (c)	1	24		24	1957
Pumped-Storage and Hydro:
Bath County (Warm Springs, VA) (d)	6	1,010	232	778	1985; 2001
Lake Lynn (Lake Lynn, PA) (e)	4	52		52	1926
Green Valley Hydro (f)	21	6		6	Various
Gas-Fired:
AE Nos. 3, 4 & 5 (Springdale, PA)	3	540		540	2003
Gleason (Gleason, TN)	3	526		526	2001
AE Nos. 1 & 2 (Springdale, PA)	2	88		88	1999
AE Nos. 8 & 9 (Gans, PA)	2	88		88	2000
AE Nos. 12 & 13 (Chambersburg, PA)	2	88		88	2001
Buchanan (Oakwood, VA) (g)	2	43		43	2002
Hunlock CT (Hunlock Creek, PA) (c)	1	22		22	2000
Oil-Fired (Steam):
Mitchell (Courtney, PA)	1	82		82	1949
Total Capacity	81	10,375	2,130	8,245

(a) When more than one year is listed as a commencement date for a particular station, the dates refer to the years in which operations commenced for the different units at that station.

(b) This figure represents capacity entitlement through AE’s ownership of OVEC shares. In December 2004, AE sold a 9% equity interest in OVEC. However, AE Supply will retain its right to 9% of the power from OVEC electric generation facilities through March 12, 2006. AE holds a 3.5% equity interest in OVEC, which entitles Monongahela to 3.5% of the power from OVEC generation facilities.

(c) This figure represents capacity entitlement of Allegheny Energy Supply Hunlock Creek, LLC (“Hunlock”) through its 50% ownership in Hunlock Creek Energy Ventures, LLC (“Hunlock Creek”). Hunlock’s entitlement to Hunlock Creek output at maximum generation capacity is indicated on the table for the steam and natural gas-fired facilities. This output is sold exclusively to AE Supply. Allegheny expects to enter into an agreement with UGI in the first quarter of 2006, although Allegheny can provide no assurance that it will

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enter into such an agreement. Under the agreement as anticipated, Allegheny will pay approximately $13.8 million (excluding closing price adjustments) and will relinquish its 50% interest in Hunlock’s coal fired generation facility (48 MWs) in exchange for full ownership of the gas fired combustion generating facility (44 MWs).

(d) This figure represents capacity entitlement through ownership of AGC.

(e) AE Supply has a license for Lake Lynn through 2024.

(f) Green Valley Hydro’s license for hydroelectric facilities Dam No. 4 and Dam No. 5, located in West Virginia and Maryland will expire November 30, 2024. Potomac Edison has licenses through 2024 for the Shenandoah, Warren, Luray and Newport projects located in Virginia.

(g) Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply (“Buchanan”), is part-owner of Buchanan Generation LLC (“Buchanan Generation”). Consol Energy, Inc. and Buchanan have equal ownership interests in Buchanan Generation. AE Supply operates and dispatches 100% of Buchanan Generation’s 86 MWs.

Proposed Asset Swap and Securitization

In May 2005, the state of West Virginia adopted legislation permitting securitization financing for the construction of certain types of pollution control equipment at facilities owned by public utilities that are regulated by the West Virginia PSC, subject to the satisfaction of certain criteria. AE Supply and Monongahela are currently contemplating an intra-company transfer of assets (the “Asset Swap”) that would realign generation ownership and contractual arrangements within the Allegheny system in order to, among other things, allow Monongahela to own 100% of the Fort Martin generation facility in West Virginia (“Fort Martin”) and, along with Potomac Edison, to finance the construction of flue gas desulfurization equipment (“Scrubbers”) at Fort Martin through the securitization of a charge that Monongahela and Potomac Edison will charge their retail customers in West Virginia.

As a result of the Asset Swap, Monongahela will also own 100% of the Albright, Rivesville and Willow Island generation facilities in West Virginia. In addition, Monongahela will be contractually entitled to a greater proportion of the generation (189 additional MWs) from the Bath County, Virginia generating facility. Also as a result of the Asset Swap, AE Supply will own 100% of the Hatfield’s Ferry generation facility in Pennsylvania (“Hatfield”), which currently is jointly owned by AE Supply and Monongahela, and will have a greater ownership interest in the Harrison and Pleasants generating facilities in West Virginia, for an additional 13 MWs and 176 MWs, respectively. AE Supply also will have contractual rights to a greater amount of generation (67 additional MWs) from OVEC.

In addition, in connection with the Asset Swap and Monongahela’s acquisition of additional generating capacity, Monongahela will become responsible for supplying the generation to meet Potomac Edison’s load obligations in West Virginia. Currently, Potomac Edison has a service agreement with AE Supply to supply Potomac Edison’s West Virginia load. That agreement will be amended and assigned to Monongahela simultaneously with the closing of the Asset Swap.

AE Supply and Monongahela expect to complete the Asset Swap by the fourth quarter of 2006. However, due to restrictions in certain debt agreements of Allegheny and AE Supply, Monongahela and AE Supply may be required to implement the Asset Swap in two phases.

On March 24, 2005, Monongahela and Potomac Edison filed an application with the West Virginia PSC for a Certificate of Public Convenience and Necessity to construct the Scrubbers at Fort Martin. On May 24, 2005 Monongahela and Potomac Edison filed an application with the West Virginia PSC requesting approval to issue $382 million in environmental control bonds to raise capital for the installation of the Scrubbers at Fort Martin and related costs. Monongahela and Potomac Edison have proposed to secure these environmental control bonds with the rights to collect an environmental control charge from customers over the term of the bonds. Allegheny entered into a settlement agreement with a group of interested parties, which was filed with the West Virginia PSC on January 11, 2006. Pursuant to the settlement agreement, the parties requested that the West Virginia PSC approve construction of the Scrubbers and the related securitization transaction, as well as the Asset Swap. Beginning on January 17, 2006, the West Virginia PSC held hearings on the applications filed by Monongahela and Potomac Edison related to the proposed Asset Swap and for a Certificate of Public Convenience and Necessity related to the proposed installation of the Scrubbers at Fort Martin. The statutory deadline for a ruling

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from the West Virginia PSC with respect to the proposed transactions is April 7, 2006. Allegheny received approval for the Asset Swap from FERC on October 21, 2005. Allegheny also may be required to obtain certain lender approvals and other third party consents in order to consummate the Asset Swap. See “Regulatory Framework Affecting Allegheny” below.

PURPA Capacity

The following table shows additional generation capacity available to the Distribution Companies through state utility commission-approved arrangements pursuant to PURPA. PURPA requires electric utility companies, such as the Distribution Companies, to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities. The amounts shown in this table are included in the Delivery and Services segment.

PURPA Stations	Project Total	Monongahela	Potomac Edison	West Penn	PURPA Contract Termination Date
Coal-Fired: Steam
AES Warrior Run (Cumberland, MD) (a)	180		180		02/10/2030
AES Beaver Valley (Monaca, PA)	125			125	12/31/2016
Grant Town (Grant Town, WV)	80	80			05/28/2028
West Virginia University (Morgantown, WV)	50	50			04/17/2027
Hydro:
Hannibal Lock and Dam (New Martinsville, WV)	31	31			06/01/2034
Allegheny Lock and Dam 6 (Freeport, PA)	7			7	06/30/2034
Allegheny Lock and Dam 5 (Freeport, PA)	6			6	09/30/2034
Total PURPA Capacity	479	161	180	138

(a) As required under the terms of a Maryland restructuring settlement, Potomac Edison began to offer the 180 MWs output of the AES Warrior Run project to the wholesale market beginning July 1, 2000 and will continue to do so for the term of the AES Warrior Run contract, which ends on February 10, 2030. Revenue received from the sale reduces the AES Warrior Run surcharge paid by Maryland customers. As of January 1, 2005, AES Warrior Run output is being sold to a non-affiliated third party.

The Energy Policy Act amended PURPA. Among other things, the amendments provide that electric utilities are no longer required to enter into any new contractual obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open-access transmission. See “Regulatory Framework Affecting Allegheny—Federal Regulation and Rate Matters—PUHCA.”

The following table sets forth the existing miles of tower and pole T&D lines and the number of substations of the Distribution Companies and AGC as of December 31, 2005:

	Underground	Above- Ground	Total Miles	Total Miles Consisting of 500-Kilovolt (kV) Lines	Number of Transmission and Distribution Substations
Monongahela	688	22,051	22,739	246	343
Potomac Edison	4,649	17,831	22,480	178	186
West Penn	2,618	24,187	26,805	276	603
AGC (a)	0	87	87	87	1
Total	7,955	64,156	72,111	787	1,133

(a) Total Bath County transmission lines, of which AGC owns an undivided 40% interest and Virginia Electric and Power Company owns the remainder.

The Distribution Companies’ transmission network has 12 extra-high-voltage (345 kV and above) and 31 lower-voltage interconnections with neighboring utility systems.

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15

FUEL, POWER AND RESOURCE SUPPLY

Generation and Marketing Segment

Coal Supply

Allegheny purchased 17.6 million tons of coal in 2005 at an average price of $35.40 per ton delivered. Allegheny purchased this coal primarily from mines in Pennsylvania, West Virginia and Ohio. However, Allegheny also purchases coal from other regions. During 2005, Allegheny initiated the blending of coal from the Powder River Basin with eastern bituminous coal at several generation facilities. The Powder River Basin is a major coal producing area in northeastern Wyoming and southeastern Montana. Allegheny currently intends to continue to blend Powder River Basin coal at several generation facilities.

Historically, Allegheny has purchased coal from a limited number of suppliers. Of Allegheny’s coal purchases in 2005, 79.0% came from subsidiaries of two companies, the larger of which represented 57.4% of the total tons purchased. As of February 22, 2006, Allegheny had contracts in place for the delivery of approximately 98% of the coal that Allegheny expects to consume in 2006, at an average price of approximately $37 per ton delivered. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties, may have negative effects on coal supplier performance.

In December 2005, Allegheny signed a coal lease and sales agreement with an affiliate of Alliance Resource Partners, L.P. to permit, develop and mine Allegheny’s coal reserve in Washington County, Pennsylvania. Alliance will evaluate the feasibility of mining the reserve and seek the necessary permits and other governmental approvals to mine the reserve. If the reserve is developed, it is expected to produce high BTU, “scrubber-quality” coal suitable for use in Allegheny’s power plants with SO₂ emission controls, and Allegheny has agreed to purchase up to two million tons annually of the mine’s output. Allegheny also will receive estimated royalty payments of $5 to $10 million per year on coal that is mined and sold from the reserve, depending upon production levels and coal prices, after the mine reaches full commercial operation.

Natural Gas Supply

AE Supply purchases natural gas to supply its natural gas-fired generation facilities. In 2005, AE Supply purchased its natural gas requirements principally in the spot market. One of AE Supply’s subsidiaries has a long-term natural gas agreement in place with a supplier. The natural gas provided under this agreement is used at the Buchanan generation facility.

Natural Gas Transportation Contracts

Dominion Transmission Transportation Contract.    AE Supply has a long-term agreement with Dominion Transmission, Inc. for the transportation of natural gas under a tariff approved by FERC. This agreement provides for the transportation of 95,000 decatherms of natural gas per day through May 31, 2013, from the Oakford, Pennsylvania interconnection to AE Supply’s combined cycle plant in Springdale, Pennsylvania.

Equitable Gas Transportation Contract.    AE Supply has a long-term agreement with Equitable Gas Company, a division of Equitable Resources, Inc., for the transportation of natural gas under a tariff approved by the Pennsylvania PUC. This agreement provides for transportation of 90,000 decatherms of natural gas per day until December 31, 2012 from Greene County, Pennsylvania to the Hatfield’s Ferry generation station in Masontown, Pennsylvania. This transportation agreement was purchased for anticipated natural gas reburn opportunities at Hatfield’s Ferry. Natural gas reburn reduces NOx emissions at a generation station by using natural gas instead of coal for a portion of the generation station’s anticipated fuel requirements. This process is used at Hatfield’s Ferry when the price of natural gas makes reburn economic relative to other NOx emission management activities.

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El Paso Transportation Contract.    AE Supply has a long-term agreement with El Paso Natural Gas Company for the transportation of natural gas under tariffs approved by FERC. This agreement provides for the transportation of gas from western Texas and northern New Mexico to the southern California border and was purchased for anticipated natural gas deliveries to a combined-cycle generation project that was contemplated in La Paz, Arizona. This project has been cancelled. In August 2003, AE Supply permanently turned back to the pipeline approximately 85% of its capacity obligation under this contract. In November 2004, AE Supply entered into a release for the balance of this capacity.

Kern River Transportation Contract.    AE Supply has a long-term agreement with Kern River Gas Transmission Company for the transportation of natural gas under a tariff approved by FERC. This agreement provides for the transportation of 45,122 decatherms of natural gas per day through April 30, 2018 from Opal, Wyoming to southern California. This transportation agreement was purchased for anticipated natural gas deliveries into southern California and at the Las Vegas Cogeneration II combined-cycle generation facility in Las Vegas, Nevada, in which Allegheny’s participation was terminated in 2003. In June 2004, AE Supply entered into a long-term capacity release for the full contract volume through October 2007. AE Supply recorded charges of $15.5 million related to this release in 2004.

The Delivery and Services Segment

Electric Power

Allegheny reorganized its corporate structure in response to electric utility deregulation within its service area between 1999 and 2001. The Distribution Companies, with the exception of Monongahela and its West Virginia generation assets, do not produce their own power. Monongahela transferred the portion of its generation assets dedicated to its previously-owned Ohio service territory to AE Supply in 2001. Potomac Edison transferred all of its generation assets to AE Supply in 2000. West Penn transferred all of its generation assets to AE Supply in 1999.

Each of the states in Allegheny’s service territory other than West Virginia has, to some extent, deregulated its electric utility industry. Pennsylvania, Maryland and Virginia have instituted retail customer choice and are transitioning to market-based, rather than cost-based pricing. West Penn has PLR obligations to its customers in Pennsylvania. Potomac Edison has PLR obligations to its customers in Virginia and its residential customers in Maryland.

As “providers of last resort,” West Penn and Potomac Edison must supply power (i.e., generation services) to certain retail customers who have not chosen alternative suppliers (or have chosen to return to Allegheny service) at rates that are capped at various levels during the applicable transition period. West Penn and Potomac Edison provide T&D services to customers in their service areas regardless of electricity generation supplier. See “The Distribution Companies’ Obligations and the PJM Market” above.

A significant portion of the power necessary to meet the PLR obligations of West Penn and Potomac Edison and Potomac Edison’s regulated service obligations in West Virginia is purchased from AE Supply. AE Supply is contractually obligated to provide power to West Penn and Potomac Edison during the relevant state deregulation transition periods under the terms of power sales agreements. These power sales agreements include both fixed price and market-based pricing components. These pricing components may not fully reflect the cost of supplying this power. As a result, AE Supply currently absorbs a portion of the risk of fuel price increases and increased costs of environmental compliance. AE Supply also sells power to Potomac Edison to serve customers in Potomac Edison’s West Virginia service territory. A portion of Allegheny’s PLR obligations is satisfied by PURPA contract purchases.

When existing power sales agreements with AE Supply terminate, Potomac Edison and West Penn will be unable to rely on the previously dedicated supply of power at specified contract prices to meet their respective power supply requirements. The arrangements to serve the applicable PLR obligations following the termination

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of these agreements have been determined in Maryland but are still under development in Pennsylvania and Virginia. AE Supply’s existing power sales agreements with West Penn and Potomac Edison will terminate as set forth in the chart below.

Distribution Company	State	Termination Date of Power Sale Agreement with AE Supply
Potomac Edison	Maryland	December 31, 2008
Potomac Edison	Virginia	June 30, 2007
Potomac Edison	West Virginia	See footnote (a)
West Penn	Pennsylvania	December 31, 2010

(a) Potomac Edison’s current power sales agreement with AE Supply for West Virginia expires on December 31, 2010. However, Potomac Edison and AE Supply have agreed to a new contract that expires on December 31, 2017. The effectiveness of that contract is subject to West Virginia PSC and FERC approval. As part of Allegheny’s contemplated intra-company exchange of assets, that agreement will be amended and assigned by AE Supply to Monongahela.

In connection with the sale of its electric T&D operations in Ohio, Monongahela agreed to sell power to Columbus Southern to serve its former Ohio customers through May 2007. Monongahela purchases the power required to meet this obligation from the PJM market.

To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets to AE Supply at PJM market prices, and that power is then sold into the PJM market. Monongahela purchases from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load.

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REGULATORY FRAMEWORK AFFECTING ALLEGHENY

The interstate transmission services and wholesale power sales of the Distribution Companies and AE Supply are regulated by FERC under the FPA. The Distribution Companies’ local distribution service and sales at the retail level are subject to state regulation. The statutory and regulatory framework affecting these companies has evolved significantly over the past decade, and these changes have exposed the companies to significant new risks and opportunities.

Prior to February 8, 2006, AE and all of its subsidiaries were also subject to the broad jurisdiction of the SEC under PUHCA 1935. The Energy Policy Act repealed PUHCA 1935, effective February 8, 2006, and replaced it with PUHCA 2005. As discussed in greater detail below, PUHCA 2005 provides for certain regulation of public utility holding companies by FERC. In addition, Allegheny’s communications subsidiary, ACC, is subject, to a limited extent, to the jurisdiction of the Federal Communications Commission and state regulatory commissions. Allegheny is subject to numerous other local, state and federal laws, regulations and rules.

Federal Regulation and Rate Matters

FERC, Competition and RTOs

FERC is an independent agency within the U.S. Department of Energy that regulates the U.S. electric utility industry under the FPA, PUHCA 2005 and PURPA.

The Federal Power Act

FERC regulates the transmission and wholesale sales of electricity under the authority of the FPA. Under the FPA, as amended by the Energy Policy Act, FERC regulates:

• the rates, terms and conditions of wholesale power sales and transmission services offered by public utilities;

• the development, operation and maintenance of hydroelectricity projects;

• the interconnection of transmission systems with other electric systems, including generation facilities;

• the disposition of public utility property and the merger, acquisition and consolidation of public utility systems;

• the issuance of certain securities and assumption of certain liabilities by public utilities;

• the system of accounts and methods of depreciation used by public utilities;

• the reliability of the transmission grid;

• the siting of certain transmission facilities;

• the allocation of long-term transmission rights;

• the types of incentives available to encourage new transmission investment;

• the transparency of power sales prices and market manipulation; and

• the holding of interlocking positions by directors and officers of public utilities.

In addition, FERC has the authority under the FPA to resolve complaints initiated on its own motion or by others as well as to conduct investigations. FERC also has the authority to enforce the FPA through the imposition of penalties.

The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity. Entities, such as the Distribution Companies and AE Supply, that sell electricity at wholesale or own transmission facilities are considered “public utilities” subject to FERC jurisdiction. Public utilities must obtain FERC acceptance for filing of their wholesale rate schedules. Rates for wholesale sales of electricity are determined on a cost-basis, or, if the

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seller demonstrates that it does not have market power, FERC may grant market-based rate authority, which allows transactions to be priced based on prevailing market conditions. Rates for transmission facilities are determined on a cost basis.

Over the past decade, FERC has taken a number of steps to foster increased competition within the electric industry. Among other things, FERC requires public utilities that own transmission facilities to offer non-discriminatory, open-access transmission services. In addition, FERC has imposed standards of conduct governing communications between employees conducting transmission functions and employees engaged in wholesale power sale activities. These standards of conduct are intended to prevent transmission-owning utilities from giving their power marketing businesses preferential access to the transmission system and transmission information. FERC also has taken steps to encourage utilities to participate in RTOs, such as PJM, by transferring functional control over their transmission assets to RTOs.

Following FERC’s initiative to promote competition, a number of states, including Pennsylvania, Maryland, Virginia and Ohio, adopted retail access legislation, which permitted utilities to transfer their generation assets to affiliated companies or third parties. Similar to many other utilities, the Distribution Companies restructured their businesses in Pennsylvania, Maryland, Virginia and Ohio between 1996 and 2001 to comply with retail restructuring requirements in those states by, among other things, transferring generation assets serving customers in those states to AE Supply.

However, this trend toward restructuring and increased competition for retail markets has slowed in response to events over the past several years. Among other things, significant price volatility (particularly in the California wholesale market), allegations of improper trading activities and overall declines in electricity demand and in the economy, generally, have contributed to this slowdown. Market-based competition within the wholesale markets is now continuing with greater FERC oversight, and some states have moved away from electricity choice at the retail level by delaying the implementation of retail competition (as in Virginia) or rejecting it outright (as in West Virginia). Delays, discontinuations or reversals of electricity marketing restructurings in states in which Allegheny operates could have a material adverse effect on its results of operation and financial condition.

Substantially all of Allegheny’s generation assets and power supply obligations are located within the PJM market, and PJM maintains functional control over the Distribution Companies’ transmission facilities. Changes in the PJM tariff, operating agreement, policies and/or market rules could adversely affect Allegheny’s financial results. These matters include changes involving: the terms, conditions and pricing of transmission services; construction of transmission enhancements; auction of financial transmission rights and the allocation mechanism for the auction revenues; changes in transmission congestion patterns due to the implementation of PJM’s regional transmission expansion planning protocol or other required transmission system upgrades; new generation retirement rules and reliability pricing issues.

Recent FERC actions with respect to the transmission rate design within PJM may impact the Distribution Companies. Beginning in July 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for these regions. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others. FERC concluded that neither the rate design proposals, nor the existing PJM rate design, had been shown to be just and reasonable. However, FERC ordered the continuation of the existing PJM rate design and the implementation of a transition charge for these regions through March 31, 2006 through filings made by transmission owners in both regions. FERC also authorized three transmission owners to submit filings that would enable them to assess additional transition charges against the Distribution Companies and other utilities in PJM. In February 2005, FERC accepted these transition charges, effective December 1, 2004, subject to an evidentiary hearing regarding the data and methodology used to determine the charges and proposed adjustments thereto.

These additional charges have resulted in net transmission charges to the Distribution Companies of approximately $6.4 million for the 13-month period ended December 31, 2005. Allegheny estimates that these

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additional charges will result in approximately $1.7 million of net transmission charges to the Distribution Companies for the three-month period ended March 31, 2006. The order following the evidentiary hearing on these transition charges may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of increases in the transition charges previously billed to the Distribution Companies.

In a May 2005 order, FERC again determined that the existing PJM rate design may not be just and reasonable. On September 30, 2005, the Distribution Companies, together with another PJM transmission owner, filed a proposed rate design with FERC to replace the existing rate design within PJM, effective April 1, 2006. Two other PJM transmission owners also filed a separate proposed rate design. A hearing is scheduled for April 2006 to determine whether the rate design is unjust and unreasonable and whether it should be replaced by either of the proposed rate designs.

In July 2005, Congress passed the Energy Policy Act, which the President signed into law on August 8, 2005. This far-reaching bill will affect many aspects of electric generation, transmission and distribution. The Energy Policy Act gives FERC significant new responsibilities, including oversight of the reliability of the transmission grid, backstop authority to site transmission facilities in national interest electric transmission corridors and the authority to provide incentive-based rates to promote transmission investment.

On August 11, 2005, AE Supply, the Distribution Companies and other Allegheny entities that have market-based rate authority granted by FERC filed a triennial analysis of market power with FERC. This filing is required as a condition to continuing to sell electric energy at wholesale market rates. FERC approved this filing on October 20, 2005.

PUHCA

The Energy Policy Act repealed PUHCA 1935, effective February 8, 2006, and replaced it with PUHCA 2005.

Under PUHCA 1935, any entity that owned, controlled or had the power to vote 10% or more of the outstanding voting securities of an “electric utility company,” or a holding company for an electric utility company, was subject to SEC regulation as a “holding company” under PUHCA. Holding companies were required to register under PUHCA 1935 unless they qualified for an exemption from registration.

Holding companies that did not qualify for an exemption from registration under PUHCA 1935 were subject to significant financial and operational conditions and restrictions. PUHCA 1935 restricted a registered holding company system from expanding into other businesses by requiring the system to confine itself to a single integrated public utility system, thereby prohibiting the system from engaging in activities that were not functionally related to its core business. Most important in light of Allegheny’s past liquidity issues and poor financial condition, PUHCA 1935 also required pre-approval from the SEC for, among other things, the issuance of debt or equity securities under certain circumstances and for the sale or acquisition of utility assets. The SEC, in certain matters, also required state consents as a condition to authorizations, even though such approvals might not be required under applicable state laws. Thus, the PUHCA 1935 approval process introduced significant lead times into routine transactions under normal circumstances. Many of Allegheny’s competitors were not regulated under PUHCA 1935 and, therefore, did not face these constraints.

Regulation under PUHCA 1935, however, did eliminate the need to obtain FERC approval for certain acquisitions and issuances of securities under Sections 203 and 204 of the FPA, as such transactions were otherwise subject to SEC jurisdiction under PUHCA 1935. With the repeal of PUHCA 1935, that exemption from Section 203 and 204 jurisdiction is no longer available effective February 8, 2006. Under rules promulgated by FERC pursuant to PUHCA 2005, FERC has permitted public utilities in a registered holding company system to engage in financing transactions previously authorized by the SEC under PUHCA 1935 without seeking

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additional FERC approval under Section 203 and 204 of the FPA during a transition period. Such holding companies are required to notify FERC of their status as holding companies and file with FERC all SEC financing authorizations on which they intend to rely for ongoing financing authority for their public utilities during the transition period, which ends on December 31, 2007. AE Supply and other Allegheny entities with market-based rate authority have been granted blanket authorization for security issuances under Section 204 and will not be required to seek additional financing authority from FERC.

Under PUHCA 2005, holding companies and their subsidiaries are subject to FERC jurisdiction with regard to affiliate transactions and cost allocations to public utilities within the holding company system. In addition, holding companies and their subsidiaries must make their books, accounts, memoranda and other records available for review by FERC and relevant state commissions and comply with FERC requirements concerning record retention.

PURPA

In the past, PURPA has required electric utility companies such as the Distribution Companies to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. State public service commissions or legislatures establish the rates paid for electric energy purchased from these qualifying facilities.

The Energy Policy Act has amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contract obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission. In February 2006, FERC finalized regulations that eliminate ownership restrictions for both new and existing facilities. A qualifying facility may now be owned by a traditional utility. The new rule also ensures that the thermal output of cogeneration facilities is used in a productive and beneficial manner.

The Distribution Companies have committed to purchase 479 MWs of qualifying PURPA capacity. In 2005, payments for PURPA capacity and energy pursuant to these contracts totaled approximately $209.0 million. The average cost to the Distribution Companies of these power purchases was 5.3 cents/kWh. The Distribution Companies are currently authorized to recover substantially all of these costs in their retail rates. The Distribution Companies’ obligations to purchase power from qualified PURPA projects in the future may exceed amounts they are authorized to recover from their customers, which could result in losses related to the PURPA contracts. However, the Energy Policy Act amendments to PURPA include a provision authorizing electric utility companies to petition FERC for relief from existing mandatory obligations to purchase electric capacity and energy from qualifying small power production and cogeneration facilities.

Pennsylvania

The Electricity Generation Customer Choice and Competition Act (the “Customer Choice Act”) gave all retail electricity customers in Pennsylvania the right to choose their electricity generation supplier as of January 2, 2000. Under the Customer Choice Act and a subsequent restructuring settlement approved by the Pennsylvania PUC, West Penn transferred its generation assets to AE Supply. West Penn retained its T&D assets. West Penn is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver, and its T&D assets are subject to traditional regulated utility ratemaking (i.e., cost-based rates).

In November 1999, under authority granted by the Pennsylvania PUC in its order approving West Penn’s original restructuring settlement, West Penn Funding, LLC, a subsidiary of West Penn, issued $600 million aggregate principal amount of Transition Bonds, Series 1999-A in order to securitize a portion of the anticipated loss in value of its generation-related assets resulting from deregulation, which are known as “stranded costs.”

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In November 2003, West Penn requested approval to issue additional transition bonds up to $115 million to securitize the portion of West Penn’s stranded costs that are not recoverable on a timely basis due to operation of the generation rate cap. In September 2004, West Penn, the Pennsylvania Office of Consumer Advocate, the Office of Small Business Advocate and The West Penn Power Industrial Intervenors filed a Joint Petition for Settlement and for Modification of the 1998 Restructuring Settlement (the “Joint Petition”). In March 2005, the parties filed an amendment to the Joint Petition, adding additional parties.

By order dated May 11, 2005, the Pennsylvania PUC approved the amended Joint Petition, allowing West Penn to securitize up to $115 million of additional transition costs through the issuance of transition bonds. On September 27, 2005, WPP Funding, LLC, a subsidiary of West Penn, issued $115 million aggregate principal amount of 4.46% Transition Bonds, Series 2005-A.

The Joint Petition approved by the Pennsylvania PUC extended generation rate caps from 2008 to 2010. The order approving the Joint Petition also extended distribution rate caps from 2005 to 2007 and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously approved rate cap increases for 2006 and 2008. These increases will gradually move generation rates closer to market prices. Rate caps on transmission services expired on December 31, 2005.

West Penn has long-term power purchase agreements with AE Supply to provide West Penn with the amount of electricity necessary to meet the majority of its PLR retail obligations during the Pennsylvania transition period. According to the terms of the amended Joint Petition described above, a Request for Proposal for full requirements wholesale electric power supply to serve load in 2009 and 2010 was issued May 31, 2005. AE Supply was the successful bidder and was awarded the contract on July 21, 2005. AE Supply filed a request with the FERC for authority to make these wholesale power sales, which FERC granted on October 25, 2005.

On August 30, 2005, West Penn filed its annual competitive transition charge reconciliation for the twelve months ended July 31, 2005. The reconciliation showed a twelve-month underrecovery of $14.6 million, for a cumulative underrecovery of approximately $92.9 million. The Pennsylvania PUC approved the reconciliation. The competitive transition charge was recovered by the securitization that was completed on September 27, 2005, concluding all competitive transition charge claims, with recovery from customers occurring from mid-2008 to 2010.

Recently enacted legislation requires the implementation of an alternative energy portfolio standard in Pennsylvania that will require electric distribution companies and retail electric suppliers in Pennsylvania to obtain certain percentages of their energy supplies from alternative sources. The new legislation includes an exemption from this requirement for companies, such as West Penn, that are operating within a transition period under the current regulations governing the transition to market competition in Pennsylvania. The full requirement will apply to those companies when the transition period ends. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative sources are not reasonably available. The law directs that all costs related to the purchase of electricity from alternative energy sources and payments for alternative energy credits will be fully recovered pursuant to an automatic energy adjustment clause. The Pennsylvania PUC initiated a proceeding in January 2005 regarding implementation and enforcement of the legislation.

West Virginia

In 1998, the West Virginia legislature passed legislation directing the West Virginia PSC to determine whether retail electric competition was in the best interests of West Virginia and its citizens. In response, the West Virginia PSC submitted a plan to introduce full retail competition on January 1, 2001. The West Virginia legislature approved, but never implemented, this plan. In March 2003, the West Virginia legislature passed a bill that clarified the jurisdiction of the West Virginia PSC over electric generation facilities. Based on these actions, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West

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Virginia. In 2000, Potomac Edison received approval to transfer its West Virginia generation assets to AE Supply. The West Virginia PSC never acted on a similar petition by Monongahela, and Monongahela agreed to withdraw its petition.

On March 24, 2005, Monongahela and Potomac Edison filed an application with the West Virginia PSC for a Certificate of Public Convenience and Necessity to construct the Scrubbers at Fort Martin. On May 24, 2005 Monongahela and Potomac Edison filed an application with the West Virginia PSC requesting approval to issue $382 million in environmental control bonds to raise capital for the installation of the Scrubbers at Fort Martin and related costs. Monongahela and Potomac Edison have proposed to secure these environmental control bonds with the rights to collect an environmental control charge from customers over the term of the bonds. Allegheny entered into a settlement agreement with a group of interested parties, which was filed with the West Virginia PSC on January 11, 2006. Pursuant to the settlement agreement, the parties requested that the West Virginia PSC approve construction of the Scrubbers and the related securitization transaction, as well as the Asset Swap. Beginning on January 17, 2006, the West Virginia PSC held hearings on the applications filed by Monongahela and Potomac Edison related to the proposed Asset Swap and for a Certificate of Public Convenience and Necessity related to the proposed installation of the pollution control equipment at Fort Martin. The statutory deadline for a ruling from the West Virginia PSC with respect to the proposed transactions is April 7, 2006. Allegheny may also be required to obtain certain lender approvals in order to consummate the Asset Swap. Currently, Allegheny plans to execute the Asset Swap and securitization only to the extent that it receives all of the regulatory and other approvals necessary for each aspect of the combined transaction.

On July 13, 2005, Monongahela, Potomac Edison and AE Supply filed a request at the FERC for approval of the proposed generation asset transfers and an amended and restated power purchase agreement, which FERC approved on October 21, 2005.

On September 27, 2004, Monongahela, Mountaineer Gas Company (“Mountaineer”) and Mountaineer Gas Holding Limited Partnership (“Mountaineer Holdings”) filed a joint petition with the West Virginia PSC for approval to transfer the stock of Mountaineer and certain other natural gas distribution assets owned by Monongahela to Mountaineer Holdings, the prospective buyer of Monongahela’s West Virginia natural gas business. On August 24, 2005, the West Virginia PSC approved the sale of Mountaineer and Allegheny’s other natural gas operations in West Virginia and a related increase in Mountaineer’s base rates. The sale of these assets was completed on September 30, 2005.

Maryland

Maryland adopted electric industry restructuring legislation in 1999, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation suppliers. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates for all customers were capped through 2004 and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates). In 2003, the Maryland PSC approved a statewide settlement relating to the future of PLR and SOS. The settlement extended Potomac Edison’s obligation to provide SOS after the expiration of the current generation rate cap periods. After expiration or the rate caps, SOS will be provided through 2012 for residential customers, through 2008 for smaller commercial and industrial customers and through 2006 for Potomac Edison’s large commercial customers. Potomac Edison’s obligation to provide SOS for its for its largest industrial customers expired at the end of 2005. A 2005 settlement extended Potomac Edison’s SOS obligations to its largest commercial customers through May 2007.

Potomac Edison has a power purchase agreement with AE Supply to provide the amount of electricity necessary to meet the majority of Potomac Edison’s PLR retail obligations during the Maryland transition period. Potomac Edison will procure the wholesale electric supply services necessary to serve its PLR obligations after the expiration of the transition period and before the expiration of its PLR obligations through a

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competitive bid process. Potomac Edison will be allowed to recover its costs for providing these services, including a return for its shareholder, through an administrative charge. In December 2005 and January 2006, AE Supply was awarded contracts under a competitive auction sell power to Potomac Edison to serve approximately 1.3 million MWhs of generation and associated services for certain small commercial and industrial customers in Maryland beginning in June 2006. These contracts expire at various times in 2007 and 2008.

Recently enacted legislation requires the implementation of a renewable energy portfolio standard in Maryland. Beginning upon the later of the expiration of the transition period for any particular customer class served by a supplier or January 1, 2006, retail electricity suppliers in Maryland will have to obtain certain percentages of their energy supplies from renewable energy resources. The law provides that if renewable resources are too expensive, or are not available in quantities sufficient to meet the standard in any given year, suppliers can instead opt to pay a “compliance fee.” The law directs the Maryland PSC to allow electric suppliers to recover their costs from customers, including any compliance fees that they incur.

Ohio

The Ohio General Assembly adopted legislation in 1999 to restructure its electric utility industry, provide retail electric customers the right to choose their electricity generation supplier and begin a transition to market rates. The 1999 legislation granted Ohio’s residential customers a 5% reduction in the generation portion of their rates until December 31, 2005, when the transition period ended. Pursuant to a settlement approved by the PUCO, Monongahela’s transition period for large industrial, commercial and street lighting customers was scheduled to end on December 31, 2003, but, as discussed below, was extended by the PUCO until December 31, 2005. Under the regulatory transition plan approved by the PUCO, Monongahela transferred its Ohio generation assets to AE Supply in June 2001. Monongahela retained its T&D assets. Monongahela’s T&D rates were capped through the end of the transition period.

In July 2003, the PUCO authorized Monongahela to issue a request for proposals for wholesale power to supply approximately 130 MW of new standard market-based retail rate service to its large industrial and commercial customers and to its street lighting customers. In October 2003, the PUCO denied approval of the wholesale bid and new retail rates and froze the current fixed rates for these customer classes until December 31, 2005. In February 2004, Monongahela appealed the PUCO’s decision to the Ohio Supreme Court. On December 30, 2004, the Ohio Supreme Court affirmed the PUCO’s October 2003 order extending Monongahela’s rate freeze for large commercial and industrial customers past the end of 2003. In January 2004, Monongahela began purchasing power at PJM market prices for these customers. The price Monongahela paid for that power was higher than the retail generation rates that it charged these customers during 2004 and 2005.

In February 2004, Monongahela filed for an injunction in federal court seeking to recover, in retail rates, its costs of purchasing power in the wholesale market. The court partially granted Monongahela’s request, ruling that the Ohio legislation adopted in 1999 to restructure the electric utility industry was unconstitutional to the extent it did not permit Monongahela to make a claim with the PUCO that its rates are confiscatory. Monongahela requested reconsideration of the court’s order, which the court partially granted by retaining jurisdiction over this matter. The PUCO initiated a proceeding in compliance with the federal court’s directive. In June 2004, Monongahela filed its application for rate relief, which the PUCO denied in December 2004. Monongahela appealed this decision to the Ohio Supreme Court and renewed its request for a preliminary injunction against the PUCO in federal court. Given the impeding sale of Monongahela’s electric T&D operations in Ohio, in September 2005, the federal court dismissed, without prejudice, Monongahela’s renewed motion.

In June 2005, the PUCO directed Monongahela to begin discussions with American Electric Power’s subsidiary, Columbus Southern, regarding the transfer of Monongahela’s Ohio service territory. On December 31, 2005, Monongahela completed the sale of its Ohio electric T&D assets to Columbus Southern for

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net cash proceeds of $51.8 million. The purchase price included $10 million for the termination of the legal and regulatory proceedings described above. In connection with the sale of these assets, Monongahela agreed to sell power to Columbus Southern at a fixed price to serve its former Ohio customers until May 31, 2007. See Note 3, “Discontinued Operations and Assets Held for Sale,” and Note 4, “Asset Sales,” in the Consolidated Financial Statements.

Virginia

Under the Virginia Electric Utility Restructuring Act of 1999 (as amended, the “Restructuring Act”), Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Potomac Edison transferred all of its ownership in generation assets in Virginia to AE Supply in 2000, except certain small hydro facilities, which were transferred to Green Valley Hydro, an unregulated subsidiary of AE. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates are capped through 2010, subject to certain exceptions. Potomac Edison has two opportunities to petition the Virginia SCC for changes to its T&D rates, between January 1, 2004 and June 30, 2007 and once again after July 1, 2007. The Restructuring Act requires the Virginia SCC to adjust Potomac Edison’s capped rates not more than once annually for the timely recovery of costs prudently incurred after July 1, 2004 for transmission or distribution system reliability or to comply with state or federal environmental laws or regulations. In addition, after July 1, 2007, Potomac Edison will have the right to recover annually certain purchased power expenses as an exception to capped rates. Potomac Edison is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver.

Potomac Edison has a power purchase agreement with AE Supply to provide Potomac Edison with the amount of electricity necessary to meet the majority of its PLR retail obligations through June 30, 2007. After that, Potomac Edison will purchase its PLR requirements from the wholesale market.

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EMPLOYEES

Substantially all of the registrants’ officers and employees are employed by AESC. As of December 31, 2005, AESC employed approximately 4,460 employees. Of these employees, approximately 29% are subject to collective bargaining arrangements. Approximately 74% of the unionized employees are at the Distribution Companies and approximately 26% are at AE’s other subsidiaries. Approximately 1,082 employees are represented by System Local 102 of the Utility Workers Union of America (the “UWUA”). The collective bargaining arrangement with UWUA Local 102 expires on May 1, 2006. Approximately 175 employees are represented by locals of the International Brotherhood of Electrical Workers (the “IBEW”). Collective bargaining arrangements with the IBEW expire at various dates during the first half of 2010. Each of the registrants believes that current relations between it and its unionized and non-unionized employees are satisfactory.

On September 19, 2005, AE entered into a Professional Services Agreement under which, on November 1, 2005, the Service Provider assumed responsibility for many of Allegheny’s information technology functions. The Service Provider also will assist Allegheny with the implementation of an enterprise resource planning system. Unless extended by AE, the Professional Services Agreement will expire on December 31, 2012. Most of the AESC employees performing Allegheny’s information technology functions were offered employment with the Service Provider.

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ENVIRONMENTAL MATTERS

The operations of Allegheny’s owned facilities, including its generation facilities, are subject to various federal, state and local laws, regulations and uncertainties as to air and water quality, hazardous and solid waste disposal and other environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities. These costs may adversely affect the cost of Allegheny’s future operations.

Information regarding capital expenditures and estimated capital expenditures associated with known environmental standards is provided in “Capital Expenditures” above. Additional legislation or regulatory control requirements have been proposed and, if enacted, may require modification, supplementation or replacement of equipment at existing generation facilities at substantial additional cost.

Air Standards

Clean Air Act Compliance.  Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through reduction of output. From time to time, minor excursions of stack emission opacity that are normal to fossil fuel operations are experienced and are accommodated by the regulatory process. Allegheny meets current emission standards for sulfer dioxide (“SO₂”) by using emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

Allegheny’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the EPA on March 10, 2005, may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Based on current forecasts, Allegheny estimates that it may have an SO₂ allowance market exposure of less than 10,000 tons in 2006 and exposure of approximately 20,000 tons and 75,000 tons in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Allegheny continues to evaluate options for compliance, and current plans include the potential installation of scrubbers at its Fort Martin generating facility by 2010, as well as the elimination of a scrubber bypass at its Pleasants generating facility by 2008 and consideration of scrubbers at its Hatfield generation facility.

Allegheny meets current emission standards for nitrogen oxides (“NO_X”) by using low NO_X burners, Selective Catalytic Reduction, Selective Non-Catalytic Reduction and over-fire air and optimization software, as well as through the use of emission allowances. Allegheny is currently evaluating its options for CAIR compliance. In 1998, the EPA finalized its NOx State Implementation Plan (“SIP”) call rule (known as the “NOx SIP call”), which addressed the regional transport of ground-level ozone and required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Pennsylvania, Maryland and West Virginia.

AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. Allegheny estimates that its

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emission control activities, in concert with its inventory of banked allowances, will facilitate its compliance with NOx limits established by the SIP through 2008. Allegheny’s current capital expenditure forecast includes the expenditure of $2 million of capital costs during 2007 for additional NO_X emission controls. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities. Therefore, there can be no assurance that Allegheny’s need to purchase NO_X allowances for these periods will not vary from current estimates.

On March 15, 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”) establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and its strategy for compliance.

Clean Air Act Litigation.  In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these generation facilities. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the NSR standards of the Clean Air Act, which can require the installation of additional air pollution control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues.

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology. There are three recent, significant federal court decisions that have addressed the application of NSR requirements to electric utility generation facilities: the Ohio Edison decision, the Duke Energy decision and the Alabama Power decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy and Alabama Power decisions support the industry’s understanding of NSR requirements. The U.S. Court of Appeals for the Fourth Circuit affirmed the Duke Energy decision on June 15, 2005.

In 2003, the EPA issued the Equipment Replacement Rule, which sets forth a clearer set of rules for projects that may be undertaken without triggering NSR requirement. This rule would apply the Routine Maintenance, Repair and Replacement (“RMRR”) exception to the NSR requirement in a manner that is more consistent with the energy industry’s historical compliance approach. That rule was challenged by some states and environmental groups and, on December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the implementation of that rule. At this time, AE and its subsidiaries are not able to determine the effect that these actions may have on them.

On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from the Pennsylvania Department of Environmental Protection (the “PA DEP”). The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

On January 6, 2005, AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal district court in West Virginia (“West Virginia DJ Action”). This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia comply with the Clean Air Act. The Attorneys General filed a

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motion to dismiss the West Virginia DJ Action. It is possible that the EPA and other state authorities may join or move to transfer the West Virginia DJ Action.

On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Distribution Companies in the United States District Court for the Western District of Pennsylvania (the “PA Enforcement Action”). This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the federal District Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. Allegheny’s motion to stay the PA Enforcement Action was denied on November 21, 2005. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On February 15, 2006, Allegheny filed a motion to dismiss the amended complaint.

On February 16, 2005, Citizens for Pennsylvania’s Future, an environmental group, sued Allegheny in the U.S. District Court for the Western District of Pennsylvania. The action alleges violations of opacity limits and particulate matter emission limits at the Hatfield’s Ferry generation facility.

Allegheny intends to vigorously pursue and defend against the environmental matters described above but cannot predict their outcomes.

Other Environmental Litigation

Canadian Toxic-Tort Class Action:  On June 30, 2005, AE Supply, Monongahela and AGC, along with 18 other companies with coal-fired generation facilities, were named as defendants in a toxic-tort, purported class action lawsuit filed in the Ontario Superior Court of Justice. On behalf of a purported class comprised of all persons residing in Ontario within the past six years (and/or their family members or heirs), the named plaintiffs allege that the defendants negligently failed to prevent their generation facilities from emitting air pollutants in such a manner as to cause death and multiple adverse health effects, as well as economic damages, to the plaintiff class. The plaintiffs seek damages in the approximate amount of Canadian $49.1 billion (approximately US $41.6 billion, assuming an exchange rate of 1.18 Canadian dollars per US dollar), along with continuing damages in the amount of Canadian $4.1 billion per year and punitive damages of Canadian $1.0 billion (approximately US $3.5 billion and US $850 million, respectively, assuming an exchange rate of 1.18 Canadian dollars per US dollar) along with such other relief as the court deems just. Allegheny has not yet been served with this lawsuit. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

Claims Related to Alleged Asbestos Exposure:  The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties in these actions are seeking an allocation of responsibility for historic and potential future asbestos liability.

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Allegheny and numerous others are plaintiffs in a similar action filed against Zurich Insurance Company in California, Fuller-Austin Asbestos Settlement Trust, et al. v. Zurich-American Insurance Co., et al., Case No. CGC 04 431719 (Superior Court of California, County of San Francisco).

In connection with a settlement, Allegheny received payment from one of its insurance companies in the amount of $625,000 on July 5, 2005, with the next payment of $625,000 due July 1, 2006. As part of the settlement, Allegheny released this insurance company from potential liabilities associated with claims against Allegheny alleging asbestos exposure.

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2005, Allegheny had 930 open cases remaining in West Virginia and five open cases remaining in Pennsylvania.

Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”) Claim: On March 4, 1994, Monongahela and certain affiliated companies received notice that the EPA had identified them as potentially responsible parties (“PRPs”) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site in Pennsylvania. Initially, approximately 175 PRPs were involved; however, the current number of active PRPs has been reduced as a result of settlements with de minimis contributors and other contributors to the site. The costs of remediation will be shared by all past and active responsible parties. In 1999, a PRP group that included Monongahela and certain affiliated companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30.0 million. Allegheny has an accrued liability representing its estimated share of the remediation costs as of December 31, 2005.

Pending Initiatives

Allegheny’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. CAIR may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

The EPA promulgated revisions to particulate matter and ozone standards in July 1997. On December 20, 2005, EPA proposed lowering the ambient air quality standards for particulates. EPA intends to issue final standards by September 27, 2006. The effect of these regulatory changes is unknown at this time, but could be substantial. The EPA also has promulgated final regional haze regulations to improve visibility in national parks and wilderness areas. The effect on Allegheny of these regulations is unknown at this time, but could be substantial.

CAMR established a cap and trade system designed to reduce mercury emissions from coal-fired generation facilities in two phases due 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. AE is currently assessing CAMR and its strategy for compliance.

The Kyoto Protocol went into effect on February 15, 2005. The Kyoto Protocol, which was signed by the Clinton Administration, but not ratified by the U.S. Senate, would require drastic reductions in greenhouse gas emissions in the United States in response to the perceived threat of global warming. If ratified and implemented by the United States, this treaty would likely require extensive mitigation efforts by Allegheny to reduce

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greenhouse gas emissions at its electric generation facilities and would raise considerable uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities. The Bush Administration has rejected the Kyoto Protocol and has proposed voluntary programs to reduce greenhouse gas intensity over the next decade. Various legislative proposals are under consideration at the international, federal and state level. The ultimate outcome of the global climate change debate and the Kyoto Protocol, which cannot be predicted at this time, could have a significant effect on Allegheny.

Water Standards

On July 9, 2004, the EPA finalized the Section 316(b) Phase II Cooling Water Intake Structure Rule. The requirements of the final rule will be implemented through National Pollutant Discharge Elimination System Permits. The rule requires site-specific comprehensive demonstration studies to determine the best technology available (as defined in the rule) for achieving compliance with national performance standards. Allegheny is currently developing compliance strategies for its affected facilities. The effect on Allegheny of these regulations are not fully known at this time but could be substantial.

RESEARCH AND DEVELOPMENT

Allegheny’s expenditures for research in 2005 and 2004 were minimal. In 2005 and 2004, Allegheny’s research and development activity addressed air emissions issues, and Allegheny expects that its research and development activity in 2006 will continue to address these issues. Allegheny spent approximately $0.6 million for research in 2003.

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ITEM 1A.    RISK FACTORS

Allegheny is subject to a variety of significant risks in addition to the matters set forth under “Special Note Regarding Forward-Looking Statements” above. Allegheny’s susceptibility to certain risks could exacerbate other risks. These risk factors should be considered carefully in evaluating Allegheny’s risk profile. Risks applicable to Allegheny include:

Risks Relating to Regulation

Allegheny is subject to substantial governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits and certificates may result in substantial costs to Allegheny.

Allegheny is subject to substantial regulation from federal, state and local regulatory agencies. Allegheny is required to comply with numerous laws and regulations and to obtain numerous authorizations, permits, approvals and certificates from governmental agencies. These agencies regulate various aspects of Allegheny’s business, including customer rates, services, retail service territories, generation plant operations, sales of securities, asset sales and accounting policies and practices.

Prior to February 8, 2006, Allegheny was also subject to regulation by the SEC under PUHCA 1935, which imposed a number of restrictions on the operations of registered utility holding companies and their subsidiaries. These restrictions included a requirement that, subject to a number of exceptions, the SEC approve in advance securities issuances, financings, acquisitions and dispositions of utility assets, or of securities of utility companies, and acquisitions of interests in other businesses, as well as a requirement that transactions between affiliated companies in a registered holding company system be performed at cost. Although the Energy Policy Act repealed PUHCA 1935 effective as of February 8, 2006, it replaced the repealed law with PUHCA 2005, which effectively extends limited jurisdiction over public utility holding companies to FERC. Although PUHCA 2005 grants FERC jurisdiction over public utility holding companies with respect to access to books and records and cost allocation methodologies, it does not impose restrictions as extensive as those imposed by the SEC under PUHCA 1935. See “Regulatory Framework Affecting Allegheny—Federal Regulation and Rate Matters” below.

Allegheny cannot predict the impact of any future revisions or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to it, including the Energy Policy Act. Changes in regulations or the imposition of additional regulations could influence Allegheny’s operating environment and may result in substantial costs to Allegheny.

Allegheny’s costs to comply with environmental laws are significant, and the cost of compliance with present and future environmental laws could adversely affect its cash flow and profitability.

Allegheny’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and site remediation. Compliance with these laws and regulations may require Allegheny to expend significant financial resources to, among other things, meet air emission standards, conduct site remediation, perform environmental monitoring, purchase emission allowances, use alternative fuels and modulate operations of its generation facilities in order to reduce emissions. If Allegheny fails to comply with applicable environmental laws and regulations, even if it is unable to do so due to factors beyond its control, it may be subject to civil liabilities or criminal penalties and may be required to incur significant expenditures to come into compliance. In addition, any alleged violations of environmental laws and regulations may require Allegheny to expend significant resources defending itself against such alleged violations.

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New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on Allegheny’s generation operations or require it to incur significant additional costs.

Applicable standards under the EPA’s NSR initiatives remain in flux. Under the Clean Air Act, modification of Allegheny’s generation facilities in a manner that causes increased emissions could subject Allegheny’s existing facilities to the far more stringent NSR standards applicable to new facilities. The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work believed by the companies to be routine maintenance. See “Regulatory Framework Affecting Allegheny” below.

On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP. The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the PSD provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

On January 6, 2005, AE Supply and Monongahela filed the West Virginia DJ Action. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia comply with the Clean Air Act. The Attorneys General filed a motion to dismiss the West Virginia DJ Action. It is possible that the EPA and other state authorities may join or move to transfer the West Virginia DJ Action.

On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed the PA Enforcement Action. This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. Allegheny’s motion to stay the PA Enforcement Action was denied on November 21, 2005. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On February 15, 2006 Allegheny filed a motion to dismiss the amended complaint.

On February 16, 2005, Citizens for Pennsylvania’s Future, an environmental group, sued Allegheny in the United States District Court for the Western District of Pennsylvania. The action alleges violations of opacity limits and particulate matter emission limits at the Hatfield’s Ferry generation facility.

Allegheny intends to vigorously pursue and defend against the environmental matters described above but cannot predict their outcomes.

In addition, Allegheny incurs costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if Allegheny fails to obtain, maintain or comply with any required approval, operations at affected facilities could be halted, curtailed or subjected to additional costs.

For additional information regarding environmental matters, see “Environmental Matters” below.

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Shifting state and federal regulatory policies impose risks on Allegheny’s operations.

Allegheny’s operations are subject to evolving regulatory policies, including initiatives regarding deregulation of the production and sale of electricity and the restructuring of transmission regulation. Any new requirements arising from these actions could lead to increased operating expenses and capital expenditures, the amount of which cannot be predicted at this time.

The continuation of below-market retail rate caps beyond the original scheduled end of transition periods could have adverse consequences for Allegheny. After the expiration of existing power supply contracts, West Penn and Potomac Edison must purchase their power requirements at market prices, whether from AE Supply or an alternative supplier. If retail rates are capped below the prices at which these utilities can obtain power, the power will be sold at a loss. Legislators, regulators and consumer and other groups have sought to extend retail rate regulation in the states in which West Penn and Potomac Edison do business through a variety of mechanisms, including through the extension of the current rate cap regimes, which are set below current market prices. Allegheny cannot predict to what extent these efforts will be successful. See “Regulatory Framework Affecting Allegheny” below.

Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have a material adverse effect on its results of operations and financial condition. At a minimum, these types of actions raise uncertainty concerning the continued development of competitive power markets. Given Allegheny’s multi-state operations and asset base, re-regulation of restructured obligations could prove intricate, time-consuming and costly to ongoing operations.

In addition, as a result of FERC’s efforts to implement a long-term rate design for the Midwest and Mid-Atlantic regions, the Distribution Companies may not fully recover their transmission costs and may have costs shifted to them from other transmission owners. Due to capped rates and the timing of state rate cases, the Distribution Companies may not be able to pass through increased transmission costs to these retail customers for some period of time.

Risks Related to Allegheny’s Substantial Debt

Covenants contained in Allegheny’s principal financing agreements restrict its operating, financing and investing activities.

Allegheny’s principal financing agreements contain restrictive covenants that limit its ability to, among other things:

• borrow funds;

• incur liens and guarantee debt;

• enter into a merger or other change of control transaction;

• make investments;

• dispose of assets; and

• pay dividends and other distributions on its equity securities.

These agreements limit Allegheny’s ability to implement strategic decisions, including its ability to access capital markets or sell assets without using the proceeds to reduce debt. In addition, Allegheny is required to meet certain financial tests under some of its loan agreements, including interest coverage ratios and leverage ratios. Allegheny’s failure to comply with the covenants contained in its financing agreements could result in an event of default, which could materially and adversely affect its financial condition.

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Allegheny’s substantial debt could adversely affect its ability to operate successfully and meet contractual obligations.

Although Allegheny reduced debt by approximately $1.9 billion between December 1, 2003 and December 31, 2005 and plans to continue its debt reduction program, Allegheny still has substantial debt. At December 31, 2005, Allegheny had $4.1 billion of debt on a consolidated basis. Approximately $199.0 million of that amount represented AE’s obligations, $2.4 billion represented debt of AE Supply and AGC and the remainder constituted debt of one or more of the Distribution Companies.

Allegheny’s substantial debt could have important consequences to it. For example, it could:

• make it more difficult for Allegheny to satisfy its obligations under the agreements governing its debt;

• require Allegheny to dedicate a substantial portion of its cash flow to payments on its debt, thereby reducing the availability of its cash flow for working capital, capital expenditures and other general corporate purposes;

• limit Allegheny’s flexibility in planning for, or reacting to, changes in its business, regulatory environment and the industry in which it operates;

• place Allegheny at a competitive disadvantage compared to its competitors that have less debt;

• limit Allegheny’s ability to borrow additional funds; and

• increase Allegheny’s vulnerability to general adverse economic, regulatory and industry conditions.

Allegheny may be unable to engage in desired financing transactions.

Allegheny has substantial debt service obligations for the foreseeable future and may need to engage in refinancing and capital-raising transactions in order to pay interest and retire principal. Allegheny also may undertake other types of financing transactions in order to meet its other financial needs and increase its equity ratios. Allegheny may be unable to successfully complete financing transactions due to a number of factors, including:

• its credit ratings, many of which are currently below investment grade;

• its overall financial condition and results of its operations; and

• volatility in the capital markets.

Allegheny currently anticipates that, in order to repay the principal of its outstanding debt, it may undertake one or more financing alternatives, such as refinancing or restructuring its debt, selling assets, reducing or delaying capital investments or raising additional capital. Allegheny can provide no assurance that it can complete any of these types of financing transactions on terms satisfactory to it or at all, that any financing transaction would enable it to pay the interest or principal on its debt or meet its other financial needs or that any of these alternatives would be permitted under the terms of the agreements governing its outstanding debt.

Changes in prevailing market conditions or in Allegheny’s access to commodities markets may make it difficult for Allegheny to hedge its physical power supply commitments and resource requirements.

In the past, unfavorable market conditions, coupled with Allegheny’s credit position, made it difficult for Allegheny to hedge its power supply obligations and fuel requirements. Although substantial improvements have been made in Allegheny’s market positions over the past few years, significant unanticipated changes in commodity market liquidity and/or Allegheny’s access to the commodity markets could adversely impact Allegheny’s ability to hedge its portfolio of physical generation assets and load obligations. In the absence of effective hedges for these purposes, Allegheny must balance its portfolio in the spot markets, which are volatile and can yield different results than expected.

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Allegheny’s risk management, wholesale marketing, fuel procurement and energy trading activities, including its decisions to enter into power sales or purchase agreements, rely on models that depend on judgments and assumptions regarding factors such as generating plant availability, future market prices, weather and the demand for electricity and other energy-related commodities. Even when Allegheny’s policies and procedures are followed and decisions are made based on these models, its financial position and results of operations may be adversely affected if the judgments and assumptions underlying those models prove to be inaccurate.

Risks Relating to Allegheny’s Operations

Allegheny’s generation facilities are subject to unplanned outages and significant maintenance requirements.

The operation of power generation facilities involves certain risks, including the risk of breakdown or failure of equipment, fuel interruption and performance below expected levels of output or efficiency. If Allegheny’s facilities, or the facilities of other parties upon which it depends, operate below expectations, Allegheny may lose revenues, have increased expenses or fail to receive or deliver the amount of power for which it has contracted.

Many of Allegheny’s facilities were originally constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to operate at peak efficiency or availability. If Allegheny underestimates required maintenance expenditures or is unable to make required capital expenditures due to liquidity constraints, it risks incurring more frequent unplanned outages, higher than anticipated maintenance expenditures, increased operation at higher cost of some of its less efficient generation facilities and the need to purchase power from third parties to meet its supply obligations, possibly at times when the market price for power is high.

Allegheny’s operating results are subject to seasonal and weather fluctuations.

The sale of power generation output is generally a seasonal business, and weather patterns can have a material impact on Allegheny’s operating results. Demand for electricity peaks during the summer and winter months, and market prices typically also peak during these times. During periods of peak demand, the capacity of Allegheny’s generation facilities may be inadequate to meet its contractual obligations, which could require it to purchase power at a time when the market price for power is high. In addition, although the operational costs associated with the Delivery and Services segment are not weather-sensitive, the segment’s revenues are subject to seasonal fluctuation. Accordingly, Allegheny’s annual results and liquidity position may depend disproportionately on its performance during the winter and summer.

Extreme weather or events outside of Allegheny’s service territory can also have a direct effect on the commodity markets. Events, such as hurricanes, that disrupt the supply of commodities used as fuel impact the price and availability of energy commodities and can have a material impact on Allegheny’s financial condition, cash flow and results of operations.

Allegheny’s revenues, costs and results of operations are subject to other risks beyond its control, including, but not limited to, accidents, storms, natural catastrophes and terrorism.

Much of the value of Allegheny’s business consists of its portfolio of power generation and T&D assets. Allegheny’s ability to conduct its operations depends on the integrity of these assets. The cost of repairing damage to its facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events may exceed available insurance, if any, for repairs, which may adversely impact Allegheny’s results of operations and financial condition. Although Allegheny has taken, and will continue to take, reasonable precautions to safeguard these assets, Allegheny can make no assurance that its facilities will not face damage or disruptions or that it will

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have sufficient insurance, if any, to cover the cost of repairs. In addition, in the current geopolitical climate, enhanced concern regarding the risks of terrorism throughout the economy may impact Allegheny’s operations in unpredictable ways. Insurance coverage may not cover costs associated with any of these risks adequately or at all. While T&D losses may be recoverable through regulatory proceedings, the delay and uncertainty of any such recovery could have a material adverse effect on Allegheny’s financial condition, cash flow and results of operations.

The terms of AE Supply’s power sale agreements with Potomac Edison and West Penn could require AE Supply to sell power below its costs or prevailing market prices or require Potomac Edison and West Penn to purchase power at a price above which they can sell power.

In connection with regulations governing the transition to market competition, Potomac Edison and West Penn are required to provide electricity at capped rates to certain retail customers who do not choose an alternate electricity generation supplier or who return to utility service from alternate suppliers. Potomac Edison and West Penn satisfy the majority of these obligations by purchasing power under contracts with external counterparties, or their affiliate, AE Supply. Those contracts provide for the supply of a significant portion of their energy needs at the mandated capped rates and for the supply of a specified remaining portion at rates based on market prices. The amount of energy priced at market rates increases over each contract term. The majority of AE Supply’s normal operating capacity is dedicated to these contracts.

These power supply agreements present risks for both AE Supply and the utilities. At times, AE Supply may not earn as much as it otherwise could by selling power priced at its contract rates to Potomac Edison and West Penn instead of into competitive wholesale markets. In addition, AE Supply’s obligations under these power supply agreements could exceed its available generation capacity, which may require AE Supply to buy power at prices that are higher than the sale prices in the power supply agreements. Changes in customer switching behavior could also alter both AE Supply’s and the utilities’ obligations under these agreements. Conversely, the utilities’ capped rates may be below current wholesale market prices through the applicable transition periods. As a consequence, Potomac Edison and West Penn may at times pay more for power than they can charge retail customers and may be unable to pass the excess costs on to their retail customers.

Rate regulation in West Virginia may delay or deny Monongahela’s full recovery of costs.

The West Virginia PSC sets Monongahela’s rates in West Virginia through traditional, cost-based regulated utility ratemaking. As part of Monongahela’s efforts to spur deregulation in West Virginia, it agreed to terminate its fuel clause effective July 1, 2000. Thus, to recover increased, unexpected or necessary costs, including increased coal and other raw material costs, Monongahela must file for approval from the West Virginia PSC to recover such costs or to reinstate its fuel clause. There can be no assurance that Monongahela will be able to recover such costs or reinstate its fuel clause under the ratemaking process. Even if Monongahela is able to recover costs, there may be a significant delay between the time that it incurs such costs and the time that it is allowed to recover such costs. Any inability to recover, or delay in the recovery of, these costs could have a material adverse effect on Monongahela’s financial condition, cash flows and results of operations.

Monongahela is required to supply power to serve its former Ohio customers at prices that may be below prevailing market prices.

In connection with the sale of its electric T&D operations in Ohio in December 2005, Monongahela entered into a power sales agreement to sell power to Columbus Southern to serve Monongahela’s former Ohio customers through May 31, 2007 (representing a total of approximately 2.5 million MWh over the term of the agreement) at a price of $45 per MWh. To meet its obligations under this agreement, Monongahela will purchase power at market prices, which may, at times, be higher than the $45 per MWh sales price fixed by this agreement.

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Monongahela recorded a charge of $29.3 million in 2005 in connection with the sale of its electric T&D operations in Ohio and its agreement to provide power to Columbus Southern at below-market prices. The amount of the charge was based on the estimated value, at December 31, 2005, of Monongahela’s power sales agreement with Columbus Southern, partially offset by approximately $8 million, representing the purchase price for the Ohio assets in excess of the book value of the assets at December 31, 2005 and approximately $2 million in expenses associated with the sale. However, market prices are volatile and can vary over time. Market prices, and therefore, the prices at which Monongahela will be required to purchase power in order to meet its obligations under its agreement with Columbus Southern, may vary significantly over the life of the agreement. Monongahela may incur losses in connection with its agreement with Columbus Southern in excess of those reflected in the $29.3 million charge.

The supply and price of fuel and emissions credits may impact Allegheny’s financial results.

Allegheny is dependent on coal for much of its electric generation capacity. Allegheny has coal supply contracts in place that partially mitigate its exposure to negative fluctuations in coal prices. Allegheny can provide no assurance, however, that the counterparties to these agreements will fulfill their obligations to supply coal. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties may have negative effects on coal supplier performance. In addition, the suppliers under these agreements may not be required to supply coal to Allegheny under certain circumstances, such as in the event of a natural disaster. If Allegheny is unable to obtain its coal requirements under these contracts, it may be required to purchase coal at higher prices, which could have a material adverse effect on its financial condition, cash flow and results of operations.

Based on current forecasts, Allegheny estimates that it may have an SO₂ allowance market exposure of less than 10,000 tons in 2006 and approximately 20,000 tons and 75,000 tons in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Fluctuations in the availability or cost of emission allowances could have a material adverse effect on Allegheny’s financial condition, cash flows and results of operations. See “Environmental Matters” below.

Allegheny is currently involved in significant litigation that, if not decided favorably to Allegheny, could have a material adverse effect on its results of operations, cash flows and financial condition.

Allegheny is currently involved in a number of lawsuits, some of which may be significant. Allegheny intends to vigorously pursue these matters, but the results of these lawsuits cannot be determined. Adverse outcomes in these lawsuits could require Allegheny to make significant expenditures and could have a material adverse effect on its financial condition, cash flow and results of operations. See “Legal Proceedings” below.

The Distribution Companies and other AE subsidiaries are and may become subject to legal claims arising from the presence of asbestos or other regulated substances at some of their facilities.

The Distribution Companies have been named as defendants in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at Allegheny-owned facilities where suitable alternative materials are not available. Allegheny’s management believes that any remaining asbestos at Allegheny-owned facilities is contained. The continued presence of asbestos and other regulated substances at Allegheny-owned facilities, however, could result in additional actions being brought against Allegheny. See “Legal Proceedings” below and Note 6, “Asset Retirement Obligations,” to the Consolidated Financial Statements.

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Adverse investment returns and other factors may increase Allegheny’s pension liability and pension funding requirements.

Substantially all of Allegheny’s employees are covered by a defined benefit pension plan. At present, the pension plan is underfunded in that the projected pension benefit obligation exceeds the aggregate fair value of plan assets. Under applicable law, Allegheny is required to make cash contributions to the extent necessary to comply with minimum funding requirements imposed by regulatory requirements. The amount of such required cash contribution is based on an actuarial valuation of the plan. The funded status of the plan can be affected by investment returns on plan assets, discount rates, mortality rates of plan participants, pending pension reform legislation and a number of other factors. There can be no assurance that the value of Allegheny’s pension plan assets will be sufficient to cover future liabilities. It is possible that Allegheny could incur a significant pension liability adjustment, or could be required to make significant additional cash contributions to its plan, which would reduce the cash available for business and other needs.

Changes in PJM market policies and rules may impact Allegheny’s financial results.

Substantially all of Allegheny’s generation assets and power supply obligations are located within the PJM region. Any changes in PJM policies or market rules, including changes that are currently under consideration by FERC, could adversely affect Allegheny’s financial results.

Energy companies are subject to adverse publicity, which may make Allegheny vulnerable to negative regulatory and litigation outcomes.

The energy sector has been the subject of highly-publicized allegations of misconduct. Negative publicity of this nature may make legislators, regulators and courts less likely to view energy companies favorably, which could cause them to make decisions or take actions that are adverse to Allegheny.

Allegheny is dependent on its ability to successfully access capital markets. Any inability to access capital may adversely affect Allegheny’s business.

Allegheny relies on access to the capital markets as a source of liquidity and to satisfy any of its capital requirements that are not met by the cash flow from its operations. Capital market disruptions, or a downgrade in Allegheny’s credit ratings, could increase Allegheny’s cost of borrowing or could adversely affect its ability to access one or more financial markets. Disruptions to the capital markets could include, but are not limited to:

• a recession or an economic slowdown;

• the bankruptcy of one or more energy companies or highly-leveraged companies;

• significant increases in the prices for oil or other fuel;

• a terrorist attack or threatened attacks;

• a significant transmission failure; or

• changes in technology.

Risks Relating to Operational Enhancements

Refocusing its business subjects Allegheny to risks and uncertainties.

Allegheny has implemented significant changes to its operations as part of its overall strategy to function as an integrated utility company, to the extent practicable and permissible under relevant regulatory constraints. For example, Allegheny has disposed of certain non-core assets, reduced the size of its workforce, made substantial

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changes to senior management and undertaken the implementation of a new company-wide enterprise resource planning system. Additional changes to Allegheny’s business will be considered as management seeks to strengthen financial and operational performance. These changes may be disruptive to Allegheny’s established organizational culture and systems. In addition, consideration and planning of strategic changes diverts management attention and other resources from day to day operations.

Allegheny may engage in sales of assets and businesses; however, market conditions and other factors may hinder this strategy.

Allegheny may continue to sell non-core assets. Sales prices for energy assets and businesses could fluctuate due to prevailing conditions. Asset sales under poor market conditions could result in substantial losses. Buyers also may find it difficult to obtain financing to purchase these assets. As part of any asset sale, Allegheny faces challenges associated with valuing the assets correctly and limiting its environmental or other retained liabilities. These transactions also may divert management attention and other resources from day-to-day operations.

Several factors specific to Allegheny could make asset sales particularly challenging. Allegheny and potential purchasers are subject to regulatory approvals, which can impose delays and structuring complications on asset sale transactions. Potential buyers may be reluctant to enter into agreements to purchase assets from Allegheny if they believe that required consents and approvals will result in significant delays or uncertainties in the transaction process.

Allegheny may fail to realize the benefits that it expects from its cost-savings initiatives.

Allegheny has undertaken and expects to continue to undertake cost-savings initiatives. However, Allegheny can make no assurance that it will realize ongoing cost savings or any other benefits from these initiatives. Even if Allegheny realizes the benefits of its cost savings initiatives, any cash savings that it achieves may be offset by other costs, such as environmental compliance costs and higher fuel, operating and maintenance costs, or could be passed on to customers through revised rates. Staff reductions may reduce Allegheny’s workforce below the level needed to effectively manage its business and service its customers. Allegheny’s failure to realize the anticipated benefits of its cost-savings initiatives could have a material adverse effect on its business, results of operations and financial condition.

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ITEM 2.    PROPERTIES

Substantially all of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations. Substantially all of Monongahela’s and Potomac Edison’s properties are held subject to the lien of indentures securing their first mortgage bonds. Certain of the properties and other assets owned by AE Supply and Monongahela that were financed by solid waste disposal and pollution control notes are subject to liens securing the obligations under those notes. In many cases, the properties of Monongahela, Potomac Edison and other AE subsidiaries may be subject to certain reservations, minor encumbrances and title defects that do not materially interfere with their use. The indenture under which AGC’s unsecured debentures are issued prohibits AGC, with certain limited exceptions, from incurring or permitting liens to exist on any of its properties or assets unless the debentures are contemporaneously secured equally and ratably with all other debt secured by the lien. Most T&D lines, some substations and switching stations and some ancillary facilities at generation facilities are on lands of others, in some cases by sufferance but, in most instances, pursuant to leases, easements, rights-of-way, permits or other arrangements, many of which have not been recorded and some of which are not evidenced by formal grants. In some cases, no examination of titles has been made as to lands on which T&D lines and substations are located. Each of the Distribution Companies possesses the power of eminent domain with respect to its public utility operations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” below and Note 2, “Capitalization” to the Consolidated Financial Statements.

Allegheny’s principal corporate headquarters is located in Greensburg, Pennsylvania, in a building that is owned by West Penn. Allegheny also has a corporate center located in Fairmont, West Virginia, in a building owned by Monongahela. Additional ancillary offices exist throughout the Distribution Companies’ service territories.

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ITEM 3.    LEGAL PROCEEDINGS

Putative Class Actions Under California Statutes

Eight related putative class action lawsuits were filed against and served on AE Supply and more than two dozen other named defendant power suppliers in various California superior courts during 2002. These class action suits were removed from state court and transferred to the U.S. District Court for the Southern District of California. Seven of the suits were commenced by consumers of wholesale electricity in California. The eighth, Millar v. Allegheny Energy Supply Co., et al., was filed on behalf of California consumers and taxpayers. The complaints allege, among other things, that AE Supply and the other defendant power suppliers violated California’s antitrust statute and the California unfair business practices statutes by manipulating the California electricity market. The suits also challenge the validity of various long-term power contracts with the State of California, including the CDWR contract.

On August 25, 2003, the U.S. District Court granted AE Supply’s motion to dismiss the seven consumer class actions with prejudice. On February 25, 2005, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s judgment dismissing the seven class actions with prejudice.

The District Court separately granted plaintiffs’ motion to remand in the eighth action, Millar, on July 9, 2003. On December 18, 2003, the plaintiffs filed an amended complaint in California state court, solely on behalf of consumers, naming certain additional defendants, including The Goldman Sachs Group, Inc. (“Goldman Sachs”). The case was removed to federal court based on the amended complaint. On January 11, 2005, the federal district court remanded the case back to the state court in San Francisco. On May 6, 2005, the defendants in the Millar action filed a series of demurrers seeking to have the action dismissed. On September 7, 2005, the state court ruled that the plaintiff’s complaint would be dismissed without leave to amend. On October 7, 2005, the state court entered judgment dismissing the complaint without leave to amend. Plaintiffs have agreed not to appeal the state court’s judgment. Thus, the eight actions filed against and served on AE Supply each have been dismissed.

Nevada Power Contracts

On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with FERC against AE Supply seeking action by FERC to modify prices payable to AE Supply under three trade confirmations between Merrill Lynch and NPC. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with Merrill Lynch under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers. On December 19, 2002, the Administrative Law Judge (“ALJ”) issued findings that no contract modification was warranted. The ALJ determined in favor of NPC that AE Supply, rather than Merrill Lynch, was a proper subject of NPC’s complaint.

On June 26, 2003, FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others. FERC did not decide whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, FERC issued an order, on rehearing, affirming its conclusion that the long-term contracts should not be modified. Snohomish County and other parties filed petitions for review of FERC’s June 26, 2003 order with the U.S. Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. The Ninth Circuit heard oral argument in these cases on December 8, 2004.

AE Supply intends to vigorously defend against these actions but cannot predict their outcomes.

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Sierra/Nevada

On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted claims against AE and AE Supply for: (a) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (b) conspiracy and (c) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada filed an amended complaint on May 30, 2003, which asserted a fourth cause of action against AE and AE Supply for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys’ fees and seeks in excess of $850 million under the RICO count. AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. Thereafter, plaintiffs filed a motion to stay the action, pending the outcome of certain state court proceedings in which they are seeking to reverse the Nevada PUC’s disallowance of expenses. The District Court granted the stay motion, and the action is currently stayed.

AE Supply intends to vigorously defend against this action but cannot predict its outcome.

Litigation Involving Merrill Lynch

AE and AE Supply entered into an asset purchase agreement with Merrill Lynch and affiliated parties in 2001, under which AE and AE Supply purchased Merrill Lynch’s energy marketing and trading business for approximately $489 million and an equity interest in AE Supply of nearly 2%. The asset purchase agreement provided that Merrill Lynch would have the right to require AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest calculated from March 16, 2001 in the event that certain conditions were not met.

On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the U.S. District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million. On September 25, 2002, AE and AE Supply filed an action against Merrill Lynch in New York state court alleging fraudulent inducement and breach of representations and warranties in the purchase agreement.

On May 29, 2003, the U.S. District Court for the Southern District of New York ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York state court, as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply dismissed the New York state action and filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the U.S. District Court for the Southern District of New York. The counterclaims, as amended, alleged that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, that Merrill Lynch negligently misrepresented certain facts relating to the purchase agreement and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims sought damages in excess of $605 million, among other relief.

On April 12, 2005, the court granted Merrill Lynch’s motion for summary judgment on its breach of contract claim, thereby requiring AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest from March 16, 2001, to be offset by any judgment in favor of AE and AE Supply on their counterclaims. The court denied Merrill Lynch’s summary judgment motion with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of contract, and granted Merrill Lynch’s motion with respect to the counterclaims for breach of fiduciary duty and negligent misrepresentations.

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In May and June of 2005, the District Court conducted a trial with respect to the damages owed Merrill Lynch on its breach of contract claim and with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of contract. Following the trial, on July 18, 2005, the District Court entered an order: (a) ruling against AE and AE Supply on their fraudulent inducement and breach of contract claims; (b) requiring AE to pay $115 million plus interest to Merrill Lynch; and (c) requiring Merrill Lynch to return its equity interest in AE Supply to AE. On August 26, 2005, the court entered its final judgment in accordance with its July 18, 2005 ruling. On September 22, 2005, AE and AE Supply filed a notice of appeal of the District Court’s judgment to the U.S. Court of Appeals for the Second Circuit. Although AE will not be required to pay Merrill Lynch the amount of the judgment while the appeal is pending, AE has posted a letter of credit to secure the judgment.

As a result of the District Court’s ruling, AE recorded a charge during the first quarter of 2005 in the amount of $38.5 million, representing interest from March 16, 2001 through March 31, 2005, and continues to accrue interest expense thereafter.

The federal government is holding certain assets of Daniel L. Gordon, the former head of energy trading for AE Supply. Both AE and AE Supply, on the one hand, and Merrill Lynch, on the other hand, filed petitions with the U.S. District Court for the Southern District of New York claiming rights to the funds. In June 2005, AE, AE Supply, Merrill Lynch and the U.S. Attorney’s Office entered into a settlement agreement pursuant to which AE Supply and Merrill Lynch will receive equal portions of certain of the assets held by the federal government. AE Supply has received approximately $11 million from the forfeited assets and may receive additional amounts if certain funds are released from a separate escrow.

Putative Shareholder, Benefit Plan Class Actions and Derivative Action

From October 2002 through December 2002, plaintiffs claiming to represent purchasers of AE’s securities filed 14 putative class action lawsuits against AE and several of its former senior managers in U.S. District Courts for the Southern District of New York and the District of Maryland. The complaints alleged that AE and senior management violated federal securities laws when AE purchased Merrill Lynch’s energy marketing and trading business with the knowledge that the business was built on illegal wash or round-trip trades with Enron, which the complaints alleged artificially inflated trading revenue, volume and growth. All of the securities cases were transferred to the District of Maryland and consolidated. The plaintiffs filed an amended complaint on May 3, 2004 that alleged that the defendants violated federal securities laws by failing to disclose weaknesses in Merrill Lynch’s energy marketing and trading business, as well as other internal control and accounting deficiencies.

In June 2003, a shareholder derivative action was filed against AE’s Board of Directors and several former senior managers in the Supreme Court of the State of New York for the County of New York. The suit alleges that the Board and former senior management breached fiduciary duties to AE that exposed AE to the securities class action lawsuits. On April 8, 2005, a second shareholder derivative action was filed against AE’s Board of Directors and several former senior managers and former directors. The action was filed in the U.S. District Court for the District of Maryland and consolidated with the securities class actions pending in that court. The Maryland derivative action contains allegations similar to the New York state court derivative action.

AE entered into agreements to settle the consolidated securities class action as well as the related shareholder derivative actions. The proposed settlements remain subject to a number of conditions, including court approval following notice to shareholders and class members. Under the proposed settlement in the consolidated securities class action, the action will be dismissed with prejudice in exchange for a cash payment of $15.05 million, which will be made by AE’s insurance carrier. Pursuant to the proposed settlement of the shareholder derivative actions, those actions will be dismissed with prejudice in exchange for a cash payment of $450,000, which will be made by AE’s insurance carrier, and AE’s agreement to adopt certain corporate governance changes. In connection with the settlements, AE and the other settling defendants continue to deny

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allegations of wrongdoing, and, if the settlements are approved, they will receive a full release of all claims asserted in the litigation. Pursuant to AE’s charter and bylaws and Section 2-418 of the Maryland General Corporation Law, AE has agreed to advance reasonable expenses to members of its Board of Directors in connection with the shareholder derivative actions.

In February and March 2003, two putative class action lawsuits were filed against AE in U.S. District Courts for the Southern District of New York and the District of Maryland. The suits alleged that AE and a senior manager violated ERISA by: (a) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (b) failing to diversify plan assets; (c) failing to monitor investment alternatives; (d) failing to avoid conflicts of interest and (e) violating fiduciary duties. The ERISA cases were consolidated in the District of Maryland. On April 26, 2004, the plaintiffs in the ERISA cases filed an amended complaint, adding a number of current and former directors of AE as defendants and clarifying the nature of their claims. On June 25, 2004, the defendants filed a motion to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding. AE intends to vigorously defend against these actions but cannot predict their outcome.

Suits Related to the Gleason Generating Facility

Allegheny Energy Supply Gleason Generating Facility, LLC, a subsidiary of AE Supply, is the defendant in a suit brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generation facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the generation facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generation facility. They seek a restraining order with respect to the operation of the plant and damages of $200 million. Mediation sessions were held on June 17, 2004 and February 22 and 23, 2006 but the parties did not reach settlement. AE has undertaken property purchases and other mitigation measures. AE intends to vigorously defend against this action but cannot predict its outcome.

AE Supply demanded indemnification from Siemens Westinghouse, the manufacturer of the turbines used in the Gleason Generating Facility, pursuant to the terms of the related equipment purchase agreement. On October 17, 2002, Siemens Westinghouse filed a declaratory judgment action in the Court of Common Pleas of Allegheny County, Pennsylvania, against AE Supply and its subsidiary seeking a declaration that the prior owner released Siemens Westinghouse from this liability through a release executed after AE Supply purchased the Gleason facility. On September 23, 2005, AE Supply entered into a confidential Settlement Agreement with Siemens Westinghouse that resolved various disputes between the parties. As a result, the declaratory judgment action filed by Siemens Westinghouse was dismissed with prejudice.

SEC Matters

On October 9, October 25 and November 5, 2002, AE received subpoenas from the SEC. The subpoenas principally concerned: (a) the departure of Daniel L. Gordon; (b) AE’s litigation with Merrill Lynch; (c) AE Supply’s valuation and management of its trading business; (d) AE’s November 4, 2002 press release concerning its financial statements; (e) the departure of AE’s and its subsidiaries’ Controller, Thomas Kloc, in June 2002 and (f) AE’s acquisition of power plants from Enron. AE and AE Supply responded to the subpoenas.

On January 16, 2004, the SEC requested that AE voluntarily produce certain documents in connection with an informal investigation of AE that focused on various accounting, internal control, and disclosure issues. In the course of its formal investigation, the SEC requested, and received, various documents. The SEC also took testimony from several current and former employees. Throughout the investigation, AE cooperated fully with the SEC. In its letter dated February 24, 2006, the SEC Division of Enforcement said, “This investigation has been terminated, and no enforcement action has been recommended to the Commission.”

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LTI Arbitration

On April 22, 2004, Leasing Technologies International, Inc. and its shareholders (collectively, “LTI”) filed a demand for arbitration against Allegheny Ventures and AE before the American Arbitration Association. In December 2000, Allegheny Ventures entered into an agreement to acquire LTI, an equipment leasing company. Allegheny Ventures terminated the agreement on May 4, 2001 based on the existence of a material adverse change under the agreement. LTI alleged that the termination of the agreement was unjustified and sought damages in an unspecified amount for breach of the agreement, as well as other consequential damages. On June 11, 2004, AE and Allegheny Ventures filed an answer to LTI’s demand, denying all claims. On December 15, 2005, AE and Allegheny Ventures entered into a settlement agreement with LTI pursuant to which they paid $15 million in exchange for a full release of all claims asserted by LTI and the dismissal with prejudice of the arbitration. The settlement does not constitute an admission of fault, and Allegheny continues to deny the allegations made by LTI in the arbitration.

Litigation with Mobotec

On July 20, 2004, MobotecUSA, Inc. (“MobotecUSA”) filed a lawsuit in the Court of Common Pleas of Greene County, Pennsylvania, against AE, AE Supply and an Allegheny employee (the “MobotecUSA Action”). Allegheny had contracted with MobotecUSA for the installation of NO_x emissions reduction equipment at certain Allegheny facilities. MobotecUSA’s complaint alleged that AE and AE Supply had breached the contracts by failing to pay MobotecUSA approximately $3.3 million. The complaint also asserted claims for enforcement of mechanics’ liens and claims for (a) intentional interference with prospective business relations; (b) trade libel and defamation; (c) breach of the covenant of good faith and fair dealing; (d) unjust enrichment and quantum meruit; and (e) civil conspiracy. MobotecUSA alleges that Allegheny falsely told third parties that MobotecUSA was unsuccessful in installing equipment and claims that it lost approximately $50 million in prospective business as a result.

On September 9, 2004, AE and AE Supply filed an answer denying MobotecUSA’s claims and asserting a counterclaim for breach of contract based on MobotecUSA’s failure to achieve the emissions reduction levels guaranteed in the agreements. On September 23, 2005, MobotecUSA filed a Second Amended Complaint, which added AESC as a party and added claims for breaches of confidentiality agreements and misappropriation of trade secrets. The Allegheny defendants have filed an answer denying MobotecUSA’s claims. On October 19, 2005, AE Supply and Monongahela commenced in the Court of Common Pleas of Greene County, Pennsylvania, a separate but related action against MobotecUSA, Mobotec AB (MobotecUSA’s parent company) and certain individuals affiliated with Mobotec (the “Mobotec Parties”). This separate action was soon thereafter consolidated with the Mobotec Action for all purposes. In their amended complaint, AE Supply and Monongahela asserted claims for breach of contract, restitution, breach of warranty, negligence and negligent misrepresentation, based on Mobotec’s conduct. The Mobotec Parties have filed a motion seeking dismissal of certain claims and certain parties with respect to the amended complaint filed by AE Supply and Monongahela. Allegheny intends to vigorously defend against MobotecUSA’s claims and pursue its affirmative claims in the consolidated action, but cannot predict the outcome.

Ordinary Course of Business

The registrants and other entities within the Allegheny system are from time to time involved in litigation and other legal disputes in the ordinary course of business. Each registrant is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders of AE, AGC, Monongahela or Potomac Edison during the fourth quarter of 2005.

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PART II

ITEM 5.    MARKET FOR THE REGISTRANTS’ COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

AE’s common stock is publicly traded. There are no established trading markets for the common equity securities of AGC, Monongahela or Potomac Edison.

AE

“AYE” is the trading symbol for AE’s common stock on the New York, Chicago and Pacific Stock Exchanges. As of February 24, 2006, there were 25,722 holders of record of AE’s common stock. The table below shows the high and low sales prices of AE’s common stock on the New York Stock Exchange for the periods indicated:

	2005				2004
	High		Low		High		Low
1st Quarter	$	21.28	$	18.25	$	13.96	$	11.75
2nd Quarter	$	25.85	$	20.28	$	15.46	$	13.00
3rd Quarter	$	31.35	$	25.25	$	16.20	$	13.99
4th Quarter	$	32.32	$	26.40	$	20.20	$	15.60

AE did not pay any dividends on its common stock during 2004 or 2005.

In July 2003, AE’s Board of Directors voted to redeem the share purchase rights issued under AE’s Stockholder Protection Rights Agreement (the “Rights Agreement”). AE terminated the Rights Agreement, effective December 6, 2004, and the share purchase rights issued under it became null and void.

Monongahela

AE owns 100% of the outstanding shares of common stock of Monongahela. Monongahela did not pay dividends on its common stock in 2005. Monongahela paid dividends on its common stock of approximately $8.2 million, $5.0 million, $9.0 million and $11.0 million on March 31, 2004, June 30, 2004, September 30, 2004 and December 31, 2004, respectively. Monongahela’s charter limits the payment of dividends on common stock.

Potomac Edison

AE owns 100% of the outstanding common stock of Potomac Edison. Potomac Edison paid dividends on its common stock of approximately $21.0 million, $10.0 million, $16.0 million and $16.0 million on March 31, 2005, June 30, 2005, September 30, 2005 and December 31, 2005, respectively. Potomac Edison paid dividends on its common stock of approximately $8.7 million, $8.1 million, $12.1 million and $14.1 million on March 31, 2004, June 30, 2004, September 30, 2004 and December 31, 2004, respectively.

AGC

Monongahela and AE Supply own approximately 23% and 77%, respectively, of the outstanding shares of common stock of AGC. AGC paid dividends on its common stock of approximately $7.2 million, $9.0 million and $5.6 million on June 30, 2005, September 30, 2005 and December 31, 2005, respectively. AGC did not pay a dividend on its common stock for the first quarter of 2005. AGC paid dividends on its common stock of approximately $5.5 million and $7.0 million on March 31, 2004 and June 30, 2004, respectively. AGC did not pay any dividends on its common stock for the third and fourth quarters of 2004.

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ITEM 6.    SELECTED FINANCIAL DATA

	Page No.
Allegheny Energy, Inc. and Subsidiaries	50
Monongahela Power Company and Subsidiaries	51
The Potomac Edison Company and Subsidiaries	51
Allegheny Generating Company	52

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ITEM 6.    SELECTED FINANCIAL DATA

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Year ended December 31, (a)	2005			2004			2003			2002			2001
(In millions except per share data)
Operating revenues	$	3,037.9		$	2,756.1		$	2,182.3		$	2,743.8		$	3,165.3
Operating expenses	$	2,501.1		$	2,166.9		$	2,378.7		$	3,216.4		$	2,214.1
Operating income (loss)	$	536.8		$	589.2		$	(196.4	)	$	(472.6	)	$	951.2
Income (loss) from continuing operations	$	75.1		$	129.7		$	(308.9	)	$	(465.8	)	$	458.1
Loss from discontinued operations	$	(6.1	)	$	(440.3	)	$	(25.3	)	$	(36.4	)	$	(9.2	)
Net income (loss)	$	63.1		$	(310.6	)	$	(355.0	)	$	(632.7	)	$	417.8
Earnings per share:
Income (loss) from continuing operations, net of tax
—basic	$	0.48		$	1.00		$	(2.44	)	$	(3.71	)	$	3.81
—diluted	$	0.47		$	0.99		$	(2.44	)	$	(3.71	)	$	3.80
Loss from discontinued operations, net of tax
—basic	$	(0.04	)	$	(3.40	)	$	(0.20	)	$	(0.29	)	$	(0.07	)
—diluted	$	(0.04	)	$	(2.82	)	$	(0.20	)	$	(0.29	)	$	(0.07	)
Net income (loss)
—basic	$	0.40		$	(2.40	)	$	(2.80	)	$	(5.04	)	$	3.48
—diluted	$	0.40		$	(1.83	)	$	(2.80	)	$	(5.04	)	$	3.47
Dividends declared per share	$	—		$	—		$	—		$	1.29		$	1.72
Short-term debt	$	—		$	—		$	53.6		$	1,132.0		$	1,238.7
Long-term debt due within one year (b)		477.2			385.1			544.9			257.2			353.1
Debentures, notes and bonds (b)		—			—			—			3,662.2			—
Total short-term debt (b)	$	477.2		$	385.1		$	598.5		$	5,051.4		$	1,591.8
Long-term debt and quarterly income debt securities (b)	$	3,624.5		$	4,540.8		$	5,127.4		$	115.9		$	3,200.4
Capital leases		16.4			23.8			32.5			39.1			35.3
Total long-term obligations (b)	$	3,640.9		$	4,564.6		$	5,159.9		$	155.0		$	3,235.7
Total assets	$	8,558.8		$	9,045.1		$	10,171.9		$	10,973.2		$	11,032.5

Notes:

(a) In 2004, Allegheny decided to sell certain non-core assets. The results of operations related to these assets have been reclassified to discontinued operations for all prior periods presented. See Note 3, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements for additional information.

(b) Long-term debt at December 31, 2002 of $3,662.2 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003, the violations had been waived or cured and the debt was classified as long-term.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Year ended December 31, (a)	2005		2004			2003		2002			2001
(In millions)
Operating revenues	$	789.9	$	683.8		$	718.9	$	695.5		$	704.9
Operating expenses	$	765.0	$	637.0		$	633.8	$	621.5		$	561.0
Operating income	$	24.9	$	46.8		$	85.1	$	74.0		$	143.9
Income from continuing operations	$	9.2	$	16.4		$	72.0	$	32.4		$	79.3
Income (loss) from discontinued operations	$	1.0	$	(13.9	)	$	9.2	$	1.3		$	10.2
Net income (loss)	$	10.2	$	2.5		$	80.7	$	(81.7	)	$	89.5
Short-term debt	$	—	$	—		$	53.6	$	—		$	14.3
Long-term debt due within one year (b)		300.0		—			3.4		65.9			30.4
Notes and bonds (b)		—		—			—		690.1			—
Total short-term debt (b)	$	300.0	$	—		$	57.0	$	756.0		$	44.7
Long-term debt (b)	$	385.1	$	684.0		$	715.5	$	28.5		$	784.3
Capital leases		5.6		8.7			12.2		14.3			11.6
Total long-term obligations (b)	$	390.7	$	692.7		$	727.7	$	42.8		$	795.9
Total assets	$	1,859.2	$	2,081.4		$	2,073.1	$	2,042.2		$	2,017.2

Notes:

(a) In 2004, Monongahela decided to sell certain non-core assets. The results of operations related to these assets have been reclassified to discontinued operations for all prior periods presented, as applicable. See Note 3, “Discontinued Operations and Assets Held for Sale,” to Monongahela’s Consolidated Financial Statements for additional information.

(b) Long-term debt at December 31, 2002 of $690.1 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003, the violations had been waived or cured and the debt was classified as long-term.

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

Year ended December 31,	2005		2004		2003		2002		2001
(In millions)
Operating revenues	$	971.2	$	924.4	$	905.2	$	870.2	$	864.5
Operating expenses	$	851.1	$	826.0	$	833.9	$	789.8	$	752.3
Operating income	$	120.1	$	98.4	$	71.3	$	80.4	$	112.2
Net income	$	66.4	$	38.0	$	40.5	$	32.7	$	48.0
Short-term debt	$	—	$	—	$	—	$	—	$	24.2
Long-term debt due within one year		100.0		—		—		—		—
Notes and bonds (a)		—		—		—		416.0		—
Total short-term debt (a)	$	100.0	$	—	$	—	$	416.0	$	24.2
Long-term debt (a)	$	318.6	$	417.9	$	416.3	$	—	$	415.8
Capital leases		4.7		6.2		8.5		10.3		9.2
Total long-term obligations (a)	$	323.3	$	424.1	$	424.8	$	10.3	$	425.0
Total assets	$	1,366.4	$	1,365.6	$	1,341.7	$	1,309.6	$	1,110.4

Notes:

(a) Long-term debt at December 31, 2002 of $416.0 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003 the violations were waived or cured, and the debt was classified as long-term.

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ALLEGHENY GENERATING COMPANY

Year ended December 31,	2005		2004		2003		2002		2001
(In millions)
Operating revenues	$	66.6	$	69.2	$	70.5	$	64.1	$	68.5
Operating expenses	$	24.8	$	26.1	$	25.4	$	25.8	$	25.5
Operating income	$	41.9	$	43.1	$	45.1	$	38.3	$	43.0
Net income	$	31.1	$	27.4	$	20.8	$	18.6	$	20.3
Short-term debt	$	—	$	—	$	—	$	55.0	$	—
Long-term debt due within one year		—		—		—		50.0		—
Debentures (a)		—		—		—		99.3		—
Total short-term debt (a)	$	—	$	—	$	—	$	204.3	$	—
Long-term debt (a)	$	99.4	$	99.4	$	99.4	$	—	$	149.2
Long-term note payable to parent		—		15.0		30.0		—		—
Total long-term obligations (a)	$	99.4	$	114.4	$	129.4	$	—	$	149.2
Total assets	$	550.2	$	557.2	$	562.4	$	597.6	$	591.6

Notes:

(a) Long-term debt at December 31, 2002 of $99.3 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003 the violations were waived or cured, and the debt was classified as long-term.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	Page No.
EXECUTIVE SUMMARY:
Business Overview	54
Key Indicators and Performance Factors	58
Operating Statistics	60
Primary Factors Affecting Allegheny’s Performance	60
Critical Accounting Policies and Estimates	61
RESULTS OF OPERATIONS:
Allegheny Energy, Inc. and Subsidiaries	64
Monongahela Power Company and Subsidiaries	83
The Potomac Edison Company and Subsidiaries	94
Allegheny Generating Company	99
FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES:
Liquidity and Capital Requirements	101
2005 Asset Sales	105
2004 Asset Sales	106
Anticipated Asset Sales	106
Dividends	106
Other Matters Concerning Liquidity and Capital Requirements	106
Cash Flows	111
Financing	116
Change in Credit Ratings	117
Derivative Instruments and Hedging Activities	119
RECENT ACCOUNTING PRONOUNCEMENTS	119
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK:
Allegheny Energy, Inc. and Subsidiaries	121
Monongahela Power Company and Subsidiaries	122
The Potomac Edison Company and Subsidiaries	123
Allegheny Generating Company	123

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

Allegheny is an integrated energy business that owns and operates electric generation facilities and delivers electric services to customers in Pennsylvania, West Virginia, Maryland and Virginia. Allegheny operates its business primarily through AE’s various directly and indirectly owned subsidiaries.

Allegheny has two business segments:

• The Delivery and Services segment includes Allegheny’s electric T&D operations.

• The Generation and Marketing segment includes Allegheny’s power generation operations.

Allegheny also conducted electric T&D operations in Ohio and natural gas T&D operations in West Virginia until it sold these operations as of December 31, 2005 and September 30, 2005, respectively. Monongahela agreed to sell power at a fixed price to Columbus Southern to serve its former Ohio customers until May 31, 2007. See “Liquidity and Capital Resources—2005 Asset Sales” below.

The Delivery and Services Segment

The principal companies and operations in AE’s Delivery and Services segment include the following:

• The Distribution Companies include Monongahela (excluding its West Virginia generation assets), Potomac Edison and West Penn. Each of the Distribution Companies is a public utility company and does business under the trade name Allegheny Power. Allegheny Power’s principal business is the operation of electric public utility systems.

• Monongahela conducts an electric T&D business in northern West Virginia. Monongahela also has generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below. Monongahela also conducted electric T&D operations in Ohio and natural gas T&D operations in West Virginia until it sold the assets related to these operations as of December 31, 2005 and September 30, 2005, respectively. Monongahela agreed to sell power to Columbus Southern to serve Monongahela’s former Ohio customers until May 31, 2007.

• Potomac Edison operates an electric T&D system in portions of West Virginia, Maryland and Virginia.

• West Penn operates an electric T&D system in southwestern, south-central and northern Pennsylvania.

In April 2002, the Distribution Companies transferred operational control over their transmission systems to PJM. See “The Distribution Companies’ Obligations and the PJM Market” below.

• Allegheny Ventures is a nonutility, unregulated subsidiary of AE that engages in telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal wholly-owned subsidiaries, ACC and AE Solutions. ACC develops fiber-optic projects, including fiber and data services. AE Solutions manages energy-related projects.

The Generation and Marketing Segment

The principal companies and operations in AE’s Generation and Marketing segment include the following:

• AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities. AE Supply markets its electric generation capacity to various customers and markets. Currently, the majority of the Generation and Marketing segment’s normal operating capacity is committed to supplying the PLR and other obligations of the Distribution Companies.

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• Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment. Currently, the majority of Monongahela’s Generation and Marketing segment’s normal operating capacity is committed to supplying Monongahela’s Delivery and Services segment.

• AGC is owned approximately 77% by AE Supply and approximately 23% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric station and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,010 MWs share of generation capacity from the Bath County generation station to AE Supply and Monongahela.

AE Supply is obligated under contracts with Potomac Edison and West Penn to provide Potomac Edison and West Penn with the power that they need to meet a majority of their PLR obligations. AE Supply sells power into the PJM market and purchases power from the PJM market to meet its obligations under these contracts. See “The Distribution Companies’ Obligations and the PJM Market” below.

Although most of the Generation and Marketing segment’s generation capacity is sold into the PJM market, its generation facility in Gleason, Tennessee is outside of PJM. The Gleason generation facility has been classified as held for sale, and its results have been presented as discontinued operations in the accompanying Consolidated Statements of Operations.

For more information regarding the AE segments and subsidiaries discussed above, see “Business—Overview.”

Intersegment Services

AESC was incorporated in Maryland in 1963 as a service company for AE. AESC employs substantially all of the employees who provide services to AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures and their respective subsidiaries. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had approximately 4,460 employees as of December 31, 2005.

The Distribution Companies’ Obligations and the PJM Market

Allegheny’s business has been significantly influenced by state and federal deregulation initiatives, including the implementation of retail choice and plans to transition from cost-based to market-based rates, as well as by the development of wholesale electricity markets and RTOs, particularly PJM.

Each of the states in Allegheny’s service territory other than West Virginia has, to some extent, deregulated its electric utility industry. Pennsylvania, Maryland and Virginia have instituted retail customer choice and are transitioning to market-based, rather than cost-based pricing for generation. In West Virginia, the rates charged to retail customers are regulated by the West Virginia PSC and are determined through traditional, cost-based, regulated utility rate-making.

West Penn has PLR obligations to its customers in Pennsylvania. Potomac Edison has PLR obligations to its customers in Virginia and its residential customers in Maryland. As “providers of last resort,” West Penn and Potomac Edison must supply power to certain retail customers who have not chosen alternative suppliers (or have chosen to return to Allegheny service) at rates that are capped at various levels during the applicable transition period. The transition periods vary across Allegheny’s service area and across customer class:

• Potomac Edison.  In Maryland, the transition period for residential customers ends on December 31, 2008. The transition period for commercial and industrial customers ended on December 31, 2004. The generation rates that Potomac Edison charges residential customers in Maryland are capped through December 31, 2008, while the T&D rate caps for all customers expired on December 31, 2004. A

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statewide settlement approved by the Maryland PSC in 2003 extends Potomac Edison’s obligation to provide SOS at market based rates beyond the expiration of the transition periods. In Virginia, the transition period ends on December 31, 2010. For a more detailed discussion, see “Regulatory Framework Affecting Allegheny” above.

• West Penn.  In Pennsylvania, the transition period terminates on December 31, 2010. As part of a May 11, 2005 order approving a settlement, the Pennsylvania PUC extended Pennsylvania’s generation rate caps from 2008 to 2010. The settlement approved by the Pennsylvania PUC also extended distribution rate caps from 2005 to 2007, with an additional rate cap in place for 2009 at the rate in effect on January 1, 2009, and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously-approved increases for 2006 and 2008. Rate caps on transmission services expired on December 31, 2005.

These transition periods could be altered by legislative, judicial or, in some cases, regulatory actions. See “Regulatory Framework Affecting Allegheny” above.

Potomac Edison and West Penn have contracts with AE Supply under which AE Supply provides Potomac Edison and West Penn with the majority of the power necessary to meet their PLR obligations. All but one of Allegheny’s generation facilities are located within the PJM region, and virtually all of the power that the Generation and Marketing segment generates is sold into the PJM market. AE Supply sells the power that it generates into the PJM market and purchases from the PJM market the power necessary to meet its obligations to supply power. Prevailing market prices are generally higher than the capped rates currently applicable to most of these PLR obligations.

To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets to AE Supply at PJM market prices, and that power is then sold into the PJM market. Monongahela purchases from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load.

In connection with the sale of its electric T&D operations in Ohio, Monongahela agreed to sell power at a fixed price to Columbus Southern to serve Monongahela’s former Ohio customers through May 2007. Monongahela currently purchases the power required to meet this obligation from the PJM market.

As an RTO, PJM coordinates the movement of electricity over the transmission grid in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

Strategy

Allegheny’s long-term strategy is to focus on its core generation and T&D businesses. Allegheny’s management believes that this emphasis is enabling Allegheny to take advantage of its regional presence, operational expertise and knowledge of its markets.

Prior to 1999, Allegheny functioned as an integrated regulated utility within its service area. In response to federal and state deregulation initiatives, however, Allegheny separated part of its energy generation business from its T&D business by transferring a portion of its generation assets to AE Supply. Allegheny’s former senior management sought to transform AE Supply into a national power merchant in order to capitalize on these regulatory and other energy industry trends. As part of this strategy, AE Supply acquired generation assets, which collectively expanded Allegheny’s owned or controlled generation capacity by nearly one-third. AE Supply also began construction of new generation facilities. In addition, AE Supply purchased the energy trading division of Merrill Lynch in 2001. With this acquisition, the focus of AE Supply’s energy trading shifted from asset backed, short-term trading in and around its generation assets to more speculative trading activities. This expansion was financed primarily through debt. Beginning in 2002, difficult market conditions, changes in the regulatory environment and Allegheny’s worsening credit profile placed Allegheny in a weakened financial position. Beginning in June 2003, Allegheny’s new senior management implemented recovery plans and new long-term strategies.

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Significant recent achievements include:

• Focusing on the Core Business.  Allegheny has reoriented its business to focus on its core businesses and assets. In 2005 and 2004, Allegheny completed a number of significant sales of non-core assets, including:

• the September 2005 sale by Monongahela of its West Virginia natural gas T&D business for cash proceeds of approximately $161 million and the assumption by the purchaser of approximately $87 million of debt;

• the August 2005 sale by AE Supply of its Wheatland generation facility for approximately $100 million;

• the December 2004, sale by AE Supply of its 672 MWs natural gas-fired Lincoln generation facility and an accompanying tolling agreement for approximately $175 million; and

• the December 2004, sale by AE of a 9% interest in OVEC (AE continues to hold a 3.5% interest in OVEC) for $102 million in cash, $96 million of which was received at the closing of the transaction and the remaining $6 million of which is expected to be received in April 2006, upon the satisfaction of certain conditions.

In addition, in December 2005 Monongahela sold its electric T&D business in Ohio for net cash proceeds of approximately $52 million.

Allegheny also exited its speculative trading activities in the Western U. S. and other energy markets in 2003 through, among other transactions, the sale of AE Supply contract with the CDWR and related hedge transactions to J. Aron & Company, as subsidiary of The Goldman Sachs Group, Inc., for $354 million. Allegheny continues to pursue the disposition of additional non-core assets, including its Gleason generating facility. See “Liquidity and Capital Resources” below and Note 4, “Asset Sales,” to the Consolidated Financial Statements.

In addition, Allegheny has announced a proposal to build the Trans-Allegheny Interstate Line. The proposed 500-kV line will span approximately 330 miles, all within Allegheny’s region of the PJM market, the APS Zone, from the Weirton, West Virginia area to near Kemptown, Maryland. The proposed line is subject to approval by PJM, as well as to various regulatory approvals. Initial engineering and planning is expected to begin in 2007, with the first segment in place in 2013. The projected cost is approximately $1.4 billion.

• Substantially Reducing and Proactively Managing Debt.  Between December 1, 2003 and December 31, 2005, Allegheny restructured much of its debt and reduced debt by approximately $1.9 billion, significantly exceeding its goal of reducing debt by $1.5 billion during this period. This restructuring effort included debt reductions of approximately $920 million in 2005 alone.

Through these restructuring efforts, Allegheny secured more favorable terms and conditions with respect to much of its debt, including reduced interest rates. The refinancings undertaken by Allegheny since 2003, together with lower debt balances, yielded a reduction in adjusted interest expense from 2004 to 2005 of approximately $60 million. The reductions in interest expense, coupled with the reductions in debt and general improvements in Allegheny’s financial condition, have led to multiple upgrades of Allegheny’s credit ratings. See “Changes in Credit Ratings” below and Note 2, “Capitalization,” to the Consolidated Financial Statements.

• Improving Liquidity.  Allegheny has improved its liquidity through prudent cash management, opportunistic sales of non-core assets, cutting costs and expenses, extending debt maturities and other financing strategies. The 2004 refinancing of AE’s credit facility established a revolving credit facility for AE, and an additional refinancing of that facility in 2005 doubled the size of the revolving credit facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” below and Note 2, “Capitalization,” to the Consolidated Financial Statements.

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• Maximizing Operational Efficiency.  Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation facilities (those that utilize steam pressure in excess of 3,200 pounds per square inch). Allegheny also is seeking to optimize operations and maintenance costs for its other generation facilities, T&D assets and related corporate functions, to reduce costs and to pursue other productivity improvements necessary to build a high performance organization.

For example, as part of a program to improve its processes and technology, AE entered into a Professional Services agreement in September 2005, under which, on November 1, 2005, the Service Provider assumed responsibility for many of Allegheny’s information technology functions. The Service Provider also will assist with the implementation of an enterprise resource planning system. Additionally, Allegheny has entered into various coal supply contracts in an effort to ensure a consistent supply of coal at predictable prices, and currently has contracts in place for the delivery of approximately 98% of its expected coal needs for 2006. See “Business—Fuel, Power and Resource Supply.”

• Maximizing Generation Value.  Allegheny is working to maximize the value of the power that it generates by ensuring full recovery of its costs and a reasonable return through the traditional rate-making process for its regulated utilities, as well as through the transition to market prices rates for AE Supply and its subsidiaries.

For example, in April 2005, Allegheny obtained approval from the Pennsylvania PUC for increases in applicable generation rate caps in 2007, 2009 and 2010 in connection with a two-year extension of the period during which Pennsylvania customers will transition to market prices. Together with previously approved rate cap increases for 2006 and 2008, these increases will gradually move generation rates in Pennsylvania closer to market prices. In addition, AE Supply won the contracts to serve the PLR customer load in Pennsylvania in 2009 and 2010 and entered into contracts to provide power to Potomac Edison to serve commercial, industrial and municipal customer loads in Maryland. See “Business—Fuel, Power and Resource Supply” and “Business—Regulatory Matters Affecting Allegheny.”

• Managing Environmental Compliance and Risks.  Allegheny is working to effectively manage its environmental compliance efforts to ensure continuing compliance with applicable federal and state regulations while controlling its compliance costs, reducing emissions levels and minimizing its risk exposure. Among other initiatives, AE Supply and Monongahela are currently blending lower-sulfur Powder River Basin coal at several generation facilities and are working to implement the financing and construction of flue gas desulfurization units and related pollution control equipment at the Fort Martin generation facility in West Virginia and the Hatfield generation facility in Pennsylvania, as well as other pollution control projects at other facilities. See “Business—Environmental Matters” and “Business—Proposed Asset Swap and Securitization.”

Allegheny’s management believes that it can continue to build on these successes in 2006 through ongoing debt reduction and other financial improvement efforts, further initiatives to improve operational efficiency and maximize generation value and continued environmental stewardship.

Key Indicators and Performance Factors

The Delivery and Services Segment

Allegheny monitors the financial and operating performance of its Delivery and Services segment using a number of indicators and performance statistics, including the following:

Revenue per MWh sold.    This measure is calculated by dividing total revenues from retail sales of electricity by total MWhs sold to retail customers. Revenue per MWh sold in 2005, 2004 and 2003 was as follows:

	2005		2004		2003
Revenue per MWh sold	$	55.32	$	54.48	$	54.44

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Operations and maintenance costs (“O&M”).    Management closely monitors and manages O&M in absolute terms, as well as in relation to total revenues.

Capital expenditures.    Management manages and prioritizes capital expenditures to meet operational needs and regulatory requirements within available cash flow constraints.

The Generation and Marketing Segment

Allegheny monitors the financial and operating performance of its Generation and Marketing segment using a number of indicators and performance statistics, including the following:

kWhs generated.    This is a measure of the total physical quantity of electricity generated and is monitored at the individual unit level, as well as various unit groupings.

Equivalent availability factor (“EAF”).    The EAF measures the percentage of time that a generation unit is available to generate electricity if called upon in the marketplace. A unit’s availability is commonly less than 100%, primarily as a result of unplanned outages or scheduled outages for planned maintenance. Allegheny monitors EAF by individual unit, as well as by various unit groupings. One such grouping is all “supercritical” units. A supercritical unit utilizes steam pressure in excess of 3,200 pounds per square inch. This design characteristic enables these units to be larger and more efficient than other generation units. Fort Martin, Harrison, Hatfield’s Ferry and Pleasants are supercritical generation facilities that have supercritical units. These units generally operate at high capacity for extended periods of time.

Station operations and maintenance costs (“Station O&M”).    Station O&M includes base maintenance, operations and special maintenance costs. Base maintenance and operations costs consist of normal recurring expenses related to the day-to-day on-going operation of the generation facility. Special maintenance includes outage related maintenance and projects that relate to all of the generating facilities.

Capital expenditures.    Management manages and prioritizes capital expenditures to meet operational needs and regulatory requirements within available cash flow constraints.

The following table shows EAFs and Station O&M for supercritical units and for all generating units:

	2005			2004			2003
Supercritical Units:
EAF		82.8	%		75.6	%		78.1	%
Station O&M: (in millions)
Base	$	118.3		$	117.4		$	118.4
Special		77.5	*		99.5			75.9
Total Station O&M	$	195.8		$	216.9		$	194.3
All Generation Units:
EAF		85.4	%		82.4	%		83.8	%
Station O&M: (in millions)
Base	$	190.0		$	189.0		$	179.8
Special		96.3	*		125.6			89.0
Total Station O&M	$	286.3		$	314.6		$	268.8

* Amounts are net of insurance recoveries of $17.7 million related to Hatfield’s Ferry.

Contracted coal position.    This measure represents the number of tons of coal under firm purchase contracts in force, expressed as a percentage of the estimated quantity of coal that will be consumed in that same future period. As of February 22, 2006, Allegheny’s contracted coal positions for 2006, 2007 and 2008 were approximately 98%, 85% and 70%, respectively.

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Operating Statistics

The following table provides kWh sales information for electricity.

	2005	2004	2003	2005 % Increase (Decrease)		2004 % Increase (Decrease)
Delivery and Services:
kWhs sold (in millions) (a)	48,276	47,222	46,514	2.2	%	1.5	%
Usage per average number of customers (kWhs):
Residential	12,538	12,038	11,835	4.2	%	1.7	%
Commercial	61,458	59,757	58,713	2.8	%	1.8	%
Industrial	739,892	759,305	749,959	(2.6	)%	1.2	%
HDD (b)	5,333	5,205	5,622	2.5	%	(7.4	)%
CDD (b)	1,087	789	663	37.8	%	19.0	%

(a) Includes retail and wholesale.

(b) Heating degree-days (“HDD”) and cooling degree-days (“CDD”).    The operations of the Distribution Companies are weather sensitive. Weather conditions directly influence the volume of electricity delivered by the Distribution Companies but represent only one of several factors that impact the volume of electricity. Accordingly, deviations in weather from normal levels can affect Allegheny’s financial performance. HDD and CDD are most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. Normal (historical) HDD are 5,605 and normal (historical) CDD are 776, calculated on a weighted-average basis across the geographic areas served by the Distribution Companies.

	2005	2004	2003	2005 % Increase (Decrease)		2004 % Increase (Decrease)
Generation and Marketing:
kWhs generated (in millions)	48,100	46,162	48,334	4.2	%	(4.5	)%

Primary Factors Affecting Allegheny’s Performance

The principal business, economic and other factors that affect Allegheny’s operations and financial performance include:

• changes in regulatory policies and rates,

• changes in the competitive electricity marketplace,

• coal plant availability,

• weather conditions,

• environmental compliance costs,

• changes in the PJM market, rules and policies,

• availability and access to liquidity and changes in interest rates,

• cost of fuel (natural gas and coal),

• wholesale commodity prices and

• labor costs.

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Critical Accounting Policies and Estimates

Use of Estimates:  Allegheny prepares its financial statements in accordance with GAAP. Application of these accounting principles often requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. Allegheny regularly evaluates its estimates, including those related to the calculation of the fair value of commodity contracts and derivative instruments, unbilled revenues, goodwill, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Allegheny bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Commodity Contracts:  AE Supply records any commodity contract related to energy trading that is a derivative instrument at its fair value as a component of operating revenues, unless the contract falls within the “normal purchases and normal sales” scope exception of SFAS No. 133 or is designated as a hedge for accounting purposes. The normal purchases and normal sales scope exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under accrual accounting and, therefore, are not recorded on the balance sheet at fair value. For certain transactions that are designed to hedge the cash flows of a forecasted transaction, the effective portion of the hedge is recorded as a separate component of stockholders’ equity under the caption “Accumulated other comprehensive income (loss)” and subsequently reclassified into earnings when the forecasted transaction is completed or settled. The ineffective portion of the hedge is immediately reflected in earnings.

Fair values for exchange-traded instruments, principally futures and certain options, are based on quoted market prices. In establishing the fair value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options and swaps, management makes estimates using available market data and pricing models. Factors such as commodity price risk, operational risk and credit risk of counterparties are evaluated in establishing the fair value of commodity contracts. The commodity contracts include certain financial instruments, such as interest rate swaps, which are used to mitigate the effect of interest rate changes.

Allegheny had unique contracts due to their long-term nature and terms that were valued using proprietary pricing models prior to 2004. Inputs to the models included estimated forward natural gas and power prices, interest rates, estimates of market volatility for natural gas and power prices and the correlation of natural gas and power prices. These inputs depended heavily on judgments and assumptions by management. These inputs became more difficult to predict, and the models became less precise, the further into the future these estimates were made. There may have been an adverse effect on Allegheny’s financial position and results of operations if the judgments and assumptions underlying those models’ inputs proved to be wrong or inaccurate. Exposure to these types of contracts has declined significantly as a result of AE Supply’s 2003 exit from the Western U.S. energy markets. Approximately $0.7 million of Allegheny’s contracts were classified as “prices based on models” at December 31, 2005.

See Note 5, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements and “Financial Condition, Requirements and Resources—Derivative Instruments and Hedging Activities” below, for additional information regarding Allegheny’s accounting for derivative instruments under SFAS No. 133.

Excess of Cost Over Net Assets Acquired (Goodwill):  The goodwill of $367.3 million at December 31, 2005 and 2004 was attributable to the Generation and Marketing segment. There were no additions to, or disposals of, goodwill during 2005 and 2004. Allegheny tests goodwill for impairment at least annually. The annual impairment test used a discounted cash flow methodology to determine the fair value of the Generation and Marketing segment and indicated no impairment of goodwill. This test result reflects that AE Supply’s fleet of generation facilities, comprised primarily of low-cost coal-fired steam generation facilities, has a fair value in excess of the carrying value of those assets sufficient to cover goodwill associated with the 2001 acquisition of the energy trading business, and no impairment of goodwill is required.

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Revenue Recognition:  Allegheny follows the accrual method of accounting for revenues and recognizes revenue for electricity that has been delivered to customers but not yet billed through the end of its accounting period. Unbilled revenues are primarily associated with the Distribution Companies. Energy sales to individual customers are based on their meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of energy delivered to each customer after the last meter reading is estimated, and the Distribution Companies recognize unbilled revenues related to these amounts. The unbilled revenue estimates are based on daily generation, purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses and the most recent consumer rates. A change in these estimates and assumptions could have a significant effect on Allegheny’s consolidated results of operations and financial position.

Regulatory Accounting:  The Distribution Companies are subject to regulations that set the rates that the Distribution Companies are permitted to charge customers. These rates are based on costs the regulatory agencies determine the Distribution Companies are permitted to recover. At times, regulators permit the future recovery through rates of costs that would otherwise be charged to expense by an unregulated company. Regulators also require that a regulatory liability be established for amounts that will be refunded to customers for various reasons. This ratemaking process often results in the recording of regulatory assets based on estimated future cash inflows and the recording of regulatory liabilities based on estimated future cash outflows.

Allegheny regularly reviews its regulatory assets and liabilities and the estimates and assumptions from which they were calculated to assess the ultimate recoverability of the assets and anticipated customer refunds within approved regulatory guidelines. A change in these estimates and assumptions could have a significant effect on Allegheny’s results of operations, cash flows and financial position.

Accounting for Pensions and Postretirement Benefits Other Than Pensions:  There are a number of significant estimates and assumptions involved in determining Allegheny’s pension and other postretirement benefit (“OPEB”) obligations and costs each period, such as employee demographics, discount rates, expected rates of return on plan assets, estimated rates of future compensation increases, medical inflation and the fair value of assets funded for the plan. Changes made to provisions for pension or other postretirement benefit plans may also affect current and future pension and OPEB costs. Allegheny’s assumptions are supported by historical data and reasonable projections and are reviewed annually with an outside actuarial firm. See Note 10, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to the Consolidated Financial Statements for additional information concerning these assumptions.

In selecting an assumed discount rate, Allegheny uses a modeling process that involves selecting a portfolio of high-quality bonds (AA- or better) whose cash flows (via coupons and maturities) match the timing and amount of Allegheny’s expected future benefit payments. Allegheny considers the results of this modeling process, as well as overall rates of return on high quality corporate bonds and changes in such rates over time, in the determination of its assumed discount rate.

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The following table shows the effect that a one percentage point increase or decrease in the 5.6% discount rate and the 8.25% expected rate of return on plan assets for 2006 would have on Allegheny’s pension and OPEB obligations and costs:

(In millions)	1-Percentage-Point Increase			1-Percentage-Point Decrease
Change in the discount rate:
Pension and OPEB obligation	$	(157.8	)	$	193.3
Net periodic pension and OPEB cost	$	(12.2	)	$	14.4
Change in expected rate of return on plan assets:
Net periodic pension and OPEB cost	$	(9.2	)	$	9.2

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Depreciation:  Depreciation expense is determined generally on a straight-line group method over the estimated service lives of depreciable assets for unregulated operations. For regulated utility operations, depreciation expense is determined using a straight-line group method in accordance with currently enacted regulatory rates. Under the straight-line group method, plant components are categorized as “retirement units” or “minor items of property.” As retirement units are replaced, the cost of the replacement is capitalized and the original component is retired. Replacements of minor units of property are expensed as maintenance.

Allegheny engaged a third party to assist in a review of the estimated remaining service lives and depreciation practices relating to the generating assets of its unregulated operations during 2005. Allegheny anticipates that the estimated service lives of its unregulated coal-fired generation facilities will be extended prospectively beginning January 1, 2006 for periods ranging from 5 to 15 years to match the estimated remaining economic lives of these generation facilities. Allegheny also expects to concurrently adjust certain other depreciation related practices. Had the changes been made as of January 1, 2005, depreciation expense would have been approximately $32 million lower and operations and maintenance expense would have been approximately $13 million lower than amounts reflected on the Consolidated Statement of Operations for the year ended December 31, 2005. The effect of this change in accounting estimate is expected to reduce depreciation and operations and maintenance expenses $50 million to $60 million, before tax effects, in 2006.

Long-Lived Assets:  Allegheny’s Consolidated Balance Sheets include significant long-lived assets that are not subject to recovery under SFAS No. 71. As a result, Allegheny must generate future cash flows from these assets in a non-regulated environment to ensure that the carrying values of these assets are not impaired. Some of these assets are the result of capital investments that have been made in recent years and have not yet reached a mature life cycle. Allegheny assesses the carrying amount and potential impairment of these assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors Allegheny considers in determining if an impairment review is necessary include significant underperformance of the assets relative to historical or projected future operating results, a significant change in Allegheny’s use of the assets or business strategy related to the assets and significant negative industry or economic trends. When Allegheny determines that an impairment review is necessary, it compares the expected undiscounted future cash flows to the carrying amount of the asset. If the carrying amount of the asset is larger, Allegheny recognizes an impairment loss equal to the amount by which the carrying amount of the asset exceeds the fair value of the asset. In these cases, Allegheny determines fair value by the use of quoted market prices, appraisals or valuation techniques, such as expected discounted future cash flows. Allegheny must make assumptions regarding these estimated future cash flows and other factors to determine the fair value of the asset. Significant changes to these assumptions could have a material effect on Allegheny’s consolidated results of operations and financial position.

Contingent Liabilities:  Allegheny has established reserves for estimated loss contingencies when management has determined that a loss is probable and the amount can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known, or circumstances change, that affect the previous assumptions with respect to the likelihood or the amount of loss. Reserves for contingent liabilities are based upon management’s assumptions and estimates and advice of legal counsel or other third parties regarding the probable outcomes of the matter. If the ultimate outcome were to differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be recognized. Contingent liabilities for Allegheny include, but are not limited to, restructuring liabilities, legal, environmental and other commitments and contingencies.

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ALLEGHENY ENERGY, INC.—RESULTS OF OPERATIONS

Income (Loss) Summary

(In millions)	Delivery and Services			Generation and Marketing
2005							Eliminations			Total
Operating revenues	$	2,845.5		$	1,703.3		$	(1,510.9	)	$	3,037.9
Fuel consumed in electric generation		—			(736.6	)		—			(736.6	)
Purchased power and transmission		(1,878.7	)		(81.0	)		1,501.4			(458.3	)
Loss on sale of Ohio T&D assets		(29.3	)		—			—			(29.3	)
Deferred energy costs, net		1.5			—			—			1.5
Operations and maintenance		(388.5	)		(378.7	)		9.5			(757.7	)
Depreciation and amortization		(153.6	)		(154.6	)		—			(308.2	)
Taxes other than income taxes		(130.4	)		(82.1	)		—			(212.5	)
Operating income		266.5			270.3			—			536.8
Other income and expenses, net		24.2			21.1			(1.1	)		44.2
Interest expense and preferred dividends		(123.3	)		(318.2	)		1.0			(440.5	)
Income (loss) from continuing operations before income taxes and minority interest		167.4			(26.8	)		(0.1	)		140.5
Income tax expense from continuing operations		(55.2	)		(9.6	)		—			(64.8	)
Minority interest in net income of subsidiaries		—			(0.6	)		—			(0.6	)
Income (loss) from continuing operations		112.2			(37.0	)		(0.1	)		75.1
Income (loss) from discontinued operations, net of tax		1.0			(7.2	)		0.1			(6.1	)
Cumulative effect of accounting change, net of tax		—			(5.9	)		—			(5.9	)
Net income (loss)	$	113.2		$	(50.1	)	$	—		$	63.1
2004
Operating revenues	$	2,764.1		$	1,538.7		$	(1,546.7	)	$	2,756.1
Fuel consumed in electric generation		—			(614.4	)		—			(614.4	)
Purchased power and transmission		(1,779.0	)		(86.2	)		1,536.8			(328.4	)
Gain on sale of OVEC power agreement and shares		—			94.8			—			94.8
Deferred energy costs, net		(0.2	)		—			—			(0.2	)
Operations and maintenance		(404.3	)		(424.1	)		9.9			(818.5	)
Depreciation and amortization		(148.8	)		(150.6	)		—			(299.4	)
Taxes other than income taxes		(128.5	)		(72.3	)		—			(200.8	)
Operating income		303.3			285.9			—			589.2
Other income and expenses, net		23.1			1.7			(0.3	)		24.5
Interest expense and preferred dividends		(129.2	)		(276.2	)		0.2			(405.2	)
Income from continuing operations before income taxes and minority interest		197.2			11.4			(0.1	)		208.5
Income tax benefit (expense) from continuing operations		(79.9	)		0.2			—			(79.7	)
Minority interest in net loss of subsidiaries		—			0.9			—			0.9
Income (loss) from continuing operations		117.3			12.5			(0.1	)		129.7
Loss from discontinued operations, net of tax		(14.0	)		(426.4	)		0.1			(440.3	)
Net income (loss)	$	103.3		$	(413.9	)	$	—		$	(310.6	)

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(In millions)	Delivery and Services			Generation and Marketing
2003							Eliminations			Total
Operating revenues	$	2,705.8		$	956.2		$	(1,479.7	)	$	2,182.3
Fuel consumed in electric generation		—			(592.0	)		—			(592.0	)
Purchased power and transmission		(1,709.2	)		(76.1	)		1,472.4			(312.9	)
Deferred energy costs, net		1.6			—			—			1.6
Operations and maintenance		(454.5	)		(538.2	)		7.3			(985.4	)
Depreciation and amortization		(152.2	)		(134.0	)		—			(286.2	)
Taxes other than income taxes		(128.1	)		(75.8	)		—			(203.9	)
Operating income (loss)		263.4			(459.9	)		—			(196.5	)
Other income and expenses, net		42.1			63.9			—			106.0
Interest expense and preferred dividends		(126.8	)		(301.0	)		—			(427.8	)
Income (loss) from continuing operations before income taxes and minority interest		178.7			(697.0	)		—			(518.3	)
Income tax benefit (expense) from continuing operations		(76.1	)		278.3			—			202.2
Minority interest in net loss of subsidiaries		—			7.2			—			7.2
Income (loss) from continuing operations		102.6			(411.5	)		—			(308.9	)
Income (loss) from discontinued operations, net of tax		9.2			(34.5	)		—			(25.3	)
Cumulative effect of accounting changes, net of tax		(1.2	)		(19.6	)		—			(20.8	)
Net income (loss)	$	110.6		$	(465.6	)	$	—		$	(355.0	)

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ALLEGHENY ENERGY, INC.—CONSOLIDATED RESULTS OF OPERATIONS:

This section is an overview of AE’s consolidated results of operations, which are discussed in greater detail for each segment in “Allegheny Energy, Inc.—Discussion of Segment Results of Operations” below.

Operating Revenues

Operating revenues increased $281.8 million for 2005, compared to 2004, primarily because:

• generation revenue increased during 2005 compared to 2004, when unplanned outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 during the first half of 2004 negatively impacted generation,

• generation revenue increased due to colder weather during 2005 and higher PJM market prices during 2005, which enabled some of Allegheny’s smaller coal and gas generation facilities to be dispatched,

• generation revenue increased as a result of the sale into the PJM market at market prices of power that, during 2004, would have been sold at below-market prices to serve certain Maryland and Ohio commercial and industrial PLR contracts and

• retail revenues increased due to the implementation of market-based rates for Maryland commercial and industrial customers, customer growth and increased customer usage as a result of a 37.8% increase in CDD.

These increases were partially offset by an increase in planned outage weeks at Allegheny’s supercritical generation facilities, from 15 to 20 weeks during the fourth quarter of 2005, and unplanned outages at Pleasants Units No. 1 and No. 2 and Hatfield Unit No. 3 during the fourth quarter of 2005. These outages came at a time when Allegheny’s service territory was experiencing unusually cold weather, increased demand and high market prices. As a result, Allegheny was a net purchaser of power at a period of high power prices within the PJM market. In addition, 2004 revenues included $68.1 million of proceeds associated with the sale of the CDWR contract and related hedge transactions that did not recur during 2005.

Operating revenues increased $573.8 million for 2004 compared to 2003, primarily due to:

• increased revenues compared to 2003, when AE Supply experienced energy trading losses associated with its exit from speculative trading activities in the U.S. energy markets,

• increased revenues due to the receipt of $68.1 million of proceeds associated with the sale of the CDWR contract and related hedge transactions and

• increased revenues resulting from increases in residential, commercial and industrial revenues due to customer growth and increased customer usage as a result of a 19.0% increase in CDD.

Operating Income

Operating income decreased $52.4 million for 2005, compared to 2004, due to:

• a $334.2 million increase in operating expenses,

• offset by a $281.8 million increase in operating revenues, as discussed above.

Operating expenses increased primarily as a result of a non-recurring $94.8 million gain on the sale of OVEC recorded during 2004, a $29.3 million loss related to the sale of Monongahela’s electric T&D operations in Ohio in 2005, increases in fuel consumed in electric generation and purchased power and transmission expense. These increases were partially offset by a $60.8 million decrease in operations and maintenance expense. Fuel consumed in electric generation increased due to increased coal prices and an increase in MWhs generated at Allegheny’s coal-fired generation facilities. Purchased power and transmission expense increased as a result of the commencement in 2005 of market-based purchase contracts for large commercial and industrial customers in Maryland, increased prices to serve commercial and industrial customers in Ohio and

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increased MWhs purchased to service PLR load. The qualifying of certain contracts as normal purchase normal sale contracts also contributed to the increase in purchased power and transmission expense. Operations and maintenance expense decreased in part due to decreased contract work, primarily due to the receipt of insurance recoveries related to Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 and decreased outside service expense due to a reduction in the use of outside consultants. The operations and maintenance expense decrease was partially offset by increased special maintenance for planned and unplanned outages during the fourth quarter of 2005. Decreased insurance expense as a result of reduced claims and lower insurance premiums also contributed to the decrease in operations and maintenance expense.

Operating income increased $785.7 million for 2004 compared to 2003, due to:

• a $573.8 million increase in operating revenues, as discussed above and

• a $211.9 million decrease in operating expenses, due to decreases in salaries and wages, employee benefits, outside services and other expenses.

Income Tax Expense

The effective tax rates for Allegheny’s continuing operations were 44.8%, 37.3% and 39.4% for 2005, 2004 and 2003, respectively.

Income tax expense for 2005 was higher than tax expense calculated at the federal statutory tax rate, primarily due to:

• a $6.9 million charge required to reflect a reduction in tax benefits for deferred compensation due to changes in the timing of payments permitted under the American Jobs Creation Act of 2004,

• a $3.8 million charge to adjust state deferred income tax assets relating to 2003, as described in Note 9, “Income Taxes,” to the Consolidated Financial Statements and

• a $1.9 million charge to adjust state deferred income tax assets resulting from a change in Ohio tax law, as described in Note 9, “Income Taxes,” to the Consolidated Financial Statements,

• partially offset by a $3.8 million benefit resulting from a bond issuance by a subsidiary of West Penn, state income taxes, tax credits, the effects of utility rate-making and certain non-deductible expenses.

The effective tax rate for 2004 was higher than the federal statutory tax rate, primarily as a result of state income taxes.

The effective tax rate for 2003 was higher than the federal statutory tax rate, primarily as a result of state income taxes, the reapplication of SFAS No. 71 and the amortization of deferred investment tax credits.

Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. Management believes that Allegheny’s accrued tax liabilities are adequate and does not expect any settlement related to this examination to have a material impact on Allegheny’s consolidated statement of operations, financial position or cash flow.

See Note 9, “Income Taxes,” to the Consolidated Financial Statements for additional information.

Income from Continuing Operations

Income from continuing operations decreased $54.6 million for 2005 compared to 2004, primarily due to:

• a $52.4 million decrease in operating income, as discussed above and

• a $35.3 million increase in interest expense and preferred dividends,

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• partially offset by a $19.7 million increase in other income and expenses, net and

• a $14.9 million decrease in income tax expense, as discussed above.

Interest expense and preferred dividends increased primarily due to the premium and associated costs to redeem AE Supply’s outstanding 10.25% and 13% Senior Notes, interest recorded in connection with a court decision in the litigation involving Merrill Lynch and interest related to the April 2005 tender offer by AE and Allegheny Capital Trust I (“Capital Trust”) for Capital Trust’s outstanding Trust Preferred Securities. These amounts were partially offset by lower interest rates and a reduction in average debt outstanding. For 2005, other income and expenses, net, increased, primarily as a result of $11.2 million in cash received from a former trading executive’s forfeited assets and increased interest income on investments.

Income from continuing operations increased $438.6 million for 2004 compared to 2003, primarily due to:

• a $785.7 million increase in operating income, as discussed above and

• a $22.6 million decrease in interest expense and preferred dividends,

• partially offset by an $81.5 million decrease in other income and expenses, net and

• a $281.9 million increase in income tax expense, as discussed above.

Interest expense decreased as a result of lower interest rates and lower average debt outstanding. Other income and expenses, net decreased primarily as a result of a $75.8 million gain recognized during 2003 on the reapplication of SFAS No. 71 by Monongahela and Potomac Edison.

Discontinued Operations

Allegheny recorded losses from discontinued operations of $6.1 million, $440.3 million and $25.3 million for the years ended December 31, 2005, 2004 and 2003, respectively, related to agreements to sell, or decisions to sell, certain non-core assets.

The $434.2 million decrease in losses from discontinued operations for 2005 compared to 2004 and the $415.0 million increase in losses from discontinued operations for 2004 compared to 2003 were primarily due to approximately $425 million of net impairment charges recorded during the third and fourth quarters of 2004 related to AE Supply’s Lincoln, Wheatland and Gleason generating facilities and Monongahela’s West Virginia natural gas operations.

See Note 3, “Discontinued Operations and Assets Held for Sale,” for additional information.

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ALLEGHENY ENERGY, INC.—DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

AE’s Delivery and Services Segment

Net income for the Delivery and Services segment increased $9.9 million for 2005 compared to 2004, primarily due to:

• a $24.7 million decrease in income tax expense,

• a $5.9 million decrease in interest expense and preferred dividends and

• a $15.0 million decrease in losses from discontinued operations,

• partially offset by a $36.8 million decrease in operating income.

Net income for the Delivery and Services segment decreased $7.3 million for 2004 compared to 2003, primarily due to:

• a $19.0 million decrease in other income and expenses, net,

• a $2.4 million increase in interest expense and preferred dividends,

• a $3.8 million increase in income tax expense and

• a $23.2 million increase in loss from discontinued operations,

• partially offset by a $39.9 million increase in operating income.

Operating Revenues

The following table provides retail electricity sales information related to the Delivery and Services segment:

	2005	2004	2003	2005 Change		2004 Change
Retail electricity sales (million kWhs):
Residential	16,923	16,047	15,633	5.5	%	2.6	%
Commercial	11,017	10,514	10,172	4.8	%	3.4	%
Industrial	20,232	20,538	20,117	(1.5	)%	2.1	%
Other	103	102	102	1.0	%	—	%
Total retail electricity sales	48,275	47,201	46,024	2.3	%	2.6	%
HDD (a)	5,333	5,205	5,622	2.5	%	(7.4	)%
CDD (a)	1,087	789	663	37.8	%	19.0	%

(a) Normal (historical) HDD are 5,605 and normal (historical) CDD are 776, calculated on a weighted-average basis across the geographic areas served by the Distribution Companies.

Operating Revenues

(In millions)	2005		2004		2003
Retail electric:
Residential	$	1,164.9	$	1,109.2	$	1,078.4
Commercial and industrial		1,490.4		1,447.4		1,412.3
Other		15.6		15.0		14.8
Total retail electric		2,670.9		2,571.6		2,505.5
Transmission services and bulk power		115.9		127.8		135.6
Other affiliated and nonaffiliated energy services		58.7		64.7		64.7
Total Delivery and Services revenues	$	2,845.5	$	2,764.1	$	2,705.8

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Operating revenues increased $81.4 million for 2005 compared to 2004 and increased $58.3 million for 2004 compared to 2003. These increases were primarily due to increased retail electric revenues, partially offset by decreased transmission services and bulk power revenues.

Retail electric revenues increased $99.3 million for 2005 compared to 2004, primarily due to:

• a $22.9 million increase in generation revenues as a result of a 1.3% increase in the average number of customers,

• a $22.8 million aggregate increase for Monongahela, Potomac Edison and West Penn generation revenues as a result of overall 37.8% and 2.5% increases in CDD and HDD, respectively,

• a $47.0 million increase in generation revenues as a result of the transition to market-based rates for Maryland commercial and industrial customers and

• a $50.9 million increase in distribution revenues as a result of a 37.8% increase in CDD, a 1.3% increase in the average number of customers and the discontinuance of certain customer choice credits in West Virginia that were in effect during 2004,

• partially offset by a $34.5 million decrease due to customers who chose alternate electricity generation providers at Potomac Edison, a significant reduction in electric usage by one industrial customer related to the curtailment of its operations in December 2005 and an $8.9 million decrease in revenues associated with the AES Warrior Run Surcharge in Maryland, as described below.

Retail electric revenues increased $66.1 million for 2004 compared to 2003, primarily due to:

• a $30.8 million increase in residential revenues and

• a $35.1 million increase in commercial and industrial revenues.

Residential revenues increased due to higher MWh sales resulting from increases in customer usage and in the average number of customers served. The increase in residential and commercial customer usage was primarily due to an increase in CDD, partially offset by a decrease in HDD. Commercial and industrial revenues increased due to higher MWh sales resulting from increases in customer usage and in the average number of customers served.

Retail electric revenues include T&D revenues from customers who chose alternate electricity generation suppliers. Less than 1% of Allegheny’s regulated customers in Pennsylvania, Maryland, Virginia and Ohio in 2005, 2004 and 2003 chose alternate electricity generation suppliers.

The return of customers to full service results in an increase in revenues due to the addition of a generation charge that Allegheny did not collect while those customers were using an alternative electricity supplier. The return of customers to PLR service does not affect T&D sales, because Allegheny determines T&D sales on the basis of kWhs delivered to customers, regardless of their electricity supplier.

Transmission services and bulk power revenues decreased by $11.9 million for 2005 compared to 2004, primarily due to:

• a $29.5 million decrease in transmission revenues, primarily as a result of the expiration of certain transition credits that were related to Allegheny’s entry into the PJM regional transmission system,

• partially offset by an $18.2 million increase in bulk power revenues, primarily resulting from increased power sales at higher prices related to the AES Warrior Run PURPA generation facility.

Transmission services and bulk power revenues decreased by $7.8 million for 2004 compared to 2003, primarily due to:

• a $13.1 million decrease in wholesale revenues as a result of the expiration of certain wholesale contracts in 2003 and

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• a $1.6 million decrease in bulk power revenues as a result of outages,

• partially offset by a $6.9 million increase in transmission revenues due to an increase in PJM transmission service revenue, as discussed below.

On April 2, 2002, the Distribution Companies transferred functional control of their transmission assets to PJM. As part of its approval of the transfer of control, FERC permitted a transmission rate surcharge designed to allow the Distribution Companies to recover $85.0 million in revenues that would otherwise not be collectible once they joined PJM. In 2004 and 2003, the Distribution Companies recovered approximately $35.0 million and $27.0 million of these surcharges, respectively. These amounts are included in transmission services and bulk power revenues. The Distribution Companies fully recovered all of these surcharges as of December 31, 2004.

Other affiliated and nonaffiliated energy services revenues decreased by $6.0 million for 2005 compared to 2004, primarily due to decreased revenues associated with Allegheny Energy Solutions’ engineering and construction project for Southern Mississippi Electric Power Association (“SMEPA”), as that project is in the final stages of completion.

Operating Expenses

Purchased Power and Transmission:  Purchased power and transmission represents power purchases from, and exchanges with, other companies (primarily AE Supply), as well as purchases from qualified facilities under PURPA. Purchased power and transmission consists of the following items:

(In millions)	2005		2004		2003
Other purchased power and transmission	$	1,669.7	$	1,581.2	$	1,512.8
From PURPA generation *		209.0		197.8		196.4
Total purchased power and transmission	$	1,878.7	$	1,779.0	$	1,709.2
* PURPA cost (cents per kWh sold)		5.3		5.2		5.6

Other purchased power and transmission primarily consists of the Distribution Companies’ purchases of energy from AE Supply. West Penn and Potomac Edison have power purchase agreements with AE Supply, under which AE Supply provides West Penn and Potomac Edison with the majority of the power necessary to meet their PLR obligations. These agreements have both fixed-price and market-based pricing components. The amount of power purchased under these agreements that is subject to the market-based pricing component increases each year through the applicable transition period. The transition period for large commercial and industrial customers in Maryland has ended. As of January 1, 2005, Potomac Edison is purchasing power at market prices from AE Supply and other nonaffiliated companies to satisfy these customer obligations in Maryland. To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchases from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load.

Other purchased power and transmission increased by $88.5 million for 2005 compared to 2004, primarily due to increased purchased power expense at Monongahela and Potomac Edison related to market purchases for certain customers in Ohio and Maryland, partially offset by customers who chose alternate electricity generation providers.

Other purchased power and transmission increased $68.4 million for 2004 compared to 2003, primarily due to an increase in prices resulting from the market-based pricing component of the power purchase agreements described above and an increase in volume. The increase in volume was due to higher MWhs purchased in response to increased demand from the Distribution Companies.

Purchased power from PURPA generation increased $11.2 million for 2005 compared to 2004, primarily due to increased purchased power from the AES Warrior Run PURPA generation facility, resulting from increased MWhs generated during 2005, compared to 2004.

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Purchased power and transmission from PURPA generation increased $1.4 million for 2004 compared to 2003, primarily due to:

• the receipt during 2003 of a $7.7 million contractually required payment which did not recur in 2004,

• partially offset by an aggregate $6.4 million decrease in expenses at West Penn and Potomac Edison due to lower power prices and MWhs purchased.

Loss on Sale of Ohio T&D Assets:  During 2005, the Delivery and Services segment recorded a loss of $29.3 million in connection with the sale of Monongahela’s electric T&D operations in Ohio. The loss was recorded based on the estimated value, at December 31, 2005, of Monongahela’s power sales agreement with Columbus Southern to provide power at below-market prices from December 31, 2005 through May 31, 2007, partially offset by approximately $8.0 million, representing the purchase price less the net book value of the assets at December 31, 2005 and approximately $2.0 million in expenses associated with the sale. The sale was completed as of December 31, 2005.

Deferred Energy Costs, Net:  Deferred energy costs net, were as follows:

(In millions)	2005			2004		2003
Deferred energy costs (benefit), net	$	(1.5	)	$	0.2	$	(1.6	)

Deferred energy costs, net, are primarily related to the recovery of net costs associated with purchases from the AES Warrior Run PURPA generation facility and the deferral of market-based generation costs.

To satisfy certain of its obligations under PURPA, Allegheny, through its subsidiary, Potomac Edison, entered into a long-term contract to purchase capacity and energy from the AES Warrior Run PURPA generation facility through the beginning of 2030. Potomac Edison is authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run PURPA generation facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, by means of a retail revenue surcharge (the “AES Warrior Run Surcharge”). Any under-recovery or over-recovery of net costs is being deferred on Potomac Edison’s Consolidated Balance Sheets as deferred energy costs, pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge. Because the AES Warrior Run Surcharge represents a dollar-for-dollar recovery of net contract costs, AES Warrior Run Surcharge revenues or revenues from sales of AES Warrior Run output do not impact Potomac Edison’s net income. Effective January 1, 2005, Allegheny sells all of the output it purchases from the AES Warrior Run facility to a non-affiliated third party, through a competitive bidding process approved by the Maryland PSC. During 2004 and 2003 the output purchased from the AES Warrior Run facility was sold to AE Supply.

Beginning on January 1, 2005, Maryland commercial and industrial generation rates transitioned to market-based rates. Potomac Edison is authorized by the Maryland PSC to recover the generation component of power sold to these customers. An asset or liability is recorded on Potomac Edison’s balance sheet relative to any under-recovery or over-recovery for the generation component of costs charged to Maryland commercial and industrial customers. Deferred energy costs relate to the recovery from or payment to customers related to these generation costs.

Operations and Maintenance:  Operations and maintenance expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:

(In millions)	2005		2004		2003
Operations and maintenance	$	388.5	$	404.3	$	454.5

Operations and maintenance expenses decreased $15.8 million 2005 compared to 2004, primarily due to:

• a $3.4 million decrease in salaries and wages,

• a $4.8 million decrease in contract work and outside services,

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• $4.3 million of certain inventory write-offs during 2004, which did not recur during 2005,

• a $4.2 million decrease in uncollectible expense,

• a $9.8 million decrease in cost of goods sold and

• an $8.6 million decrease in insurance expenses,

• partially offset by approximately $15 million associated with the settlement of the LTI arbitration and

• a $4.2 million increase in employee benefits expense.

The decrease in salaries and wages was a result of decreases in the number of employees and severance costs. The decrease in contract work and outside services was a result of a reduction in the use of outside consultants, partially offset by certain costs associated with an outside service provider assuming responsibility for many of Allegheny’s information technology functions and agreement to assist Allegheny with the installation of an enterprise resource planning system. The decrease in uncollectible expense was a result of improved collections and increased use of security deposits. The decrease in cost of goods sold was due to reductions in equipment procurement and subcontracting costs associated with Allegheny Energy Solutions’ engineering and construction project for SMEPA, as that project is in the final stages of completion. The decrease in insurance expense resulted from a decrease in the amount of claims and a reduction in the amount of premiums paid. The increase in employee benefits expense was due to increased pension and OPEB expense as a result of a reduction in the discount rate associated with computing net periodic costs of Allegheny’s pension and OPEB plans.

For additional information regarding the LTI arbitration, see Note 23, “Commitments and Contingencies,” to the Consolidated Financial Statements. For additional information regarding pension and OPEB expenditures, See Note 10, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to the Consolidated Financial Statements.

Operations and maintenance expenses decreased $50.2 million for 2004 compared to 2003, primarily due to:

• a $15.4 million decrease in insurance expense,

• a $15.2 million decrease in outside services and contract work expense,

• an $11.3 million decrease in employee benefits expense and

• a $7.4 million decrease in salaries and wages expense.

The decrease in insurance expense was due to a reduction in costs for potential claims alleging exposure to asbestos. The decrease in outside service and contract work expense was the result of decreased use of independent contractors and consultants. The decrease in employee benefits expense reflects a $10.0 million decrease in Supplemental Executive Retirement Plan (“SERP”) and Executive Life Insurance Plan (“ELIP”) expenses, primarily due to costs recorded in 2003 for certain executives, and a $6.3 million decrease in disability costs, principally related to costs recorded in 2003 that did not recur in 2004. These amounts were partially offset by a $5.4 million increase in pension expense resulting from reductions in both the discount rate and expected long-term rate of return on pension plan assets. The decrease in salaries and wages expense was the result of a decrease in the number of employees.

Depreciation and Amortization:  Depreciation and amortization expenses were as follows:

(In millions)	2005		2004		2003
Depreciation and amortization	$	153.6	$	148.8	$	152.2

Depreciation and amortization expenses increased $4.8 million for 2005 compared to 2004, primarily as a result of net property, plant and equipment additions.

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Depreciation and amortization expense decreased $3.4 million for 2004 compared to 2003, primarily due to an adjustment to the remaining useful life of software and a decrease in the amortization of regulatory assets. These decreases were partially offset by increased depreciation and amortization resulting from additions to property, plant and equipment.

Taxes Other Than Income Taxes:  Taxes other than income taxes primarily include West Virginia business and occupation taxes, payroll taxes and property taxes. Taxes other than income taxes were as follows:

(In millions)	2005		2004		2003
Taxes other than income taxes	$	130.4	$	128.5	$	128.1

Taxes other than income taxes increased $1.9 million for 2005 compared to 2004, primarily as a result of an increase in state gross receipts taxes due to an increase in regulated utility revenues.

Other Income and Expenses, Net:  Other income and expenses, net represents non-operating income and expenses before income taxes. Other income and expenses, net were as follows:

(In millions)	2005		2004		2003
Other income and expenses, net	$	24.2	$	23.1	$	42.1

Other income and expenses, net increased $1.1 million for 2005 compared to 2004, primarily as the result of proceeds received from unregulated investments, as well as increased interest and dividend income on investments, partially offset by decreased gains on the disposal of non-operating assets.

Other income and expenses, net decreased $19.0 million for 2004 compared to 2003, primarily as a result of a gain recognized in 2003 related to the reapplication of the provisions of SFAS No. 71 by Potomac Edison to generation assets in West Virginia and sales of land.

See Note 19, “Other Income and Expenses, Net,” to the Consolidated Financial Statements for additional details.

Interest Expense and Preferred Dividends:  Interest expense and preferred dividends were as follows:

(In millions)	2005		2004		2003
Interest expense and preferred dividends	$	123.3	$	129.2	$	126.8

Interest expense and preferred dividends decreased $5.9 million for 2005 compared to 2004, primarily due to:

• interest expense savings of $28.4 million on long-term debt,

• partially offset by $21.0 million in non-recurring expense related to the April 2005 tender offer by AE and Capital Trust for Capital Trust’s outstanding Trust Preferred Securities.

Interest expense decreased primarily due to the refinancing at lower rates during November 2004 of $175 million of Potomac Edison’s outstanding First Mortgage Bonds, the tender offer for and conversion of Capital Trust’s Trust Preferred Securities during the second quarter of 2005 and the repayment of notes and bonds by West Penn during 2004 and 2005.

Interest expense and preferred dividends increased $2.4 million for 2004 compared to 2003, primarily due to:

• an $8.5 million increase in interest expense associated with the July 2003 issuance by Capital Trust of Trust Preferred Securities and

• a $4.3 million increase in interest expense on first mortgage bonds,

• partially offset by a $10.5 million decrease in interest expense as a result of the repayment of notes and bonds by West Penn.

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The increase in interest expense on first mortgage bonds is due primarily to Monongahela’s June 2004 issuance of first mortgage bonds and one-month overlaps between Monongahela’s and Potomac Edison’s issuances of new first mortgage bonds and their redemptions of outstanding first mortgage bonds.

See Note 2, “Capitalization,” to the Consolidated Financial Statements for additional information regarding Allegheny’s short-term and long-term debt.

Discontinued Operations:  Income (loss) from discontinued operations for the Delivery and Services segment was as follows:

(In millions)	2005		2004			2003
Discontinued operations	$	1.0	$	(14.0	)	$	9.2

The $15.0 million increase in income from discontinued operations for 2005 compared to 2004 was primarily a result of impairment charges on Monongahela’s West Virginia natural gas operations of $21.7 million, net of tax, recorded during the third and fourth quarters of 2004, compared to impairment charges of $7.0 million, net of tax, during 2005.

The $23.2 million increase in loss from discontinued operations for 2004 compared to 2003 was primarily a result of impairment charges on Monongahela’s West Virginia natural gas operations of $21.7 million, net of tax, recorded during the third and fourth quarters of 2004. See Note 3, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements for additional information.

Cumulative Effect of Accounting Changes, Net

In connection with their adoption of SFAS No. 143 on January 1, 2003, entities within Allegheny’s Delivery and Services segment recorded charges of $1.2 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2003. See Note 6, “Asset Retirement Obligations,” to the Consolidated Financial Statements for additional information.

AE’s Generation and Marketing Segment:

Net loss for the Generation and Marketing segment decreased $363.8 million for 2005 compared to 2004, primarily due to:

• a $419.2 million decrease in loss from discontinued operations and

• a $19.4 million increase in other income and expenses, net,

• partially offset by a $15.6 million decrease in operating income,

• a $42.0 million increase in interest expense and preferred dividends and

• a $9.8 million increase in income tax expense.

Net loss for the Generation and Marketing segment decreased $51.7 million for 2004 compared to 2003, primarily due to:

• a $745.8 million increase in operating income,

• a $24.8 million decrease in interest expense and preferred dividends and

• a $19.6 million charge related to the cumulative effect of accounting change, net of tax, recorded in 2003,

• partially offset by a $62.2 million decrease in other income and expenses, net,

• a $278.1 million increase in income tax expense and

• a $391.9 million increase in loss from discontinued operations, net of tax.

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Operating Revenues

The following table provides electricity sales information related to the Generation and Marketing segment:

	2005	2004	2003	2005 Change		2004 Change
Generation (million kWhs)	48,100	46,162	48,334	4.2	%	(4.5	)%

Operating revenues for the Generation and Marketing segment were as follows:

(In millions)	2005		2004		2003
Revenue from affiliates	$	1,501.5	$	1,491.8	$	1,425.7
Wholesale and other, net *		201.8		46.9		(469.5	)
Total Generation and Marketing revenues	$	1,703.3	$	1,538.7	$	956.2

* Amounts are net of energy trading gains and losses as described in Note 5, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements. Energy trading gains (losses) are presented in the wholesale and other revenues table.

Operating revenues increased $164.6 million for 2005 compared to 2004 and increased $582.5 million for 2004 compared to 2003. These increases were primarily due to increased wholesale and other revenue, net, as discussed below.

Revenue from affiliates:  Revenue from affiliates results primarily from the sale of power to the Distribution Companies.

AE Supply has power sales agreements with Potomac Edison and West Penn under which AE Supply provides Potomac Edison and West Penn with a majority of the power necessary to meet their PLR obligations. These legacy agreements have both fixed-price and market-based pricing components. The amount of power purchased under certain of these agreements that is subject to the market-based pricing component increases each year through the applicable transition period.

To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets to AE Supply and purchases from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. During 2004, Monongahela’s West Virginia generation facilities also provided power to Monongahela’s Delivery and Services segment to meet its West Virginia regulated load obligations. During 2004, Monongahela’s Delivery and Services Segment purchased power from AE Supply to serve Monongahela’s large commercial and industrial customers in Ohio. During 2005, Monongahela’s Delivery and Services Segment purchased power directly from the PJM market to serve its large commercial and industrial customers in Ohio.

The average rate at which the Generation and Marketing segment sold power to the Distribution Companies was $33.01, $32.41 and $31.80 per MWh for the years ended December 31, 2005, 2004 and 2003, respectively.

Revenue from affiliates increased $9.7 million for 2005 compared to 2004, primarily due to:

• increases of $45.1 million in affiliated bulk power revenues for 2005, as a result of the expiration in December 2004 of a contract between AE Supply and Potomac Edison for the purchase by AE Supply of output related to the AES Warrior Run PURPA generation facility, which reduced revenue in 2004 as a result of accounting for derivatives and

• sales to Monongahela’s Delivery and Services segment of additional power to satisfy load requirements in West Virginia, which previously was obtained from a third party,

• partially offset by decreased sales volumes in Ohio and from certain of Potomac Edison’s customers in Maryland who chose alternate service providers, both beginning January 1, 2005. These power sales were previously provided by the Generation and Marketing segment to the Delivery and Services segment and are now being provided by nonaffiliated suppliers.

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Revenue from affiliates increased $66.1 million in 2004 compared to 2003, primarily due to increased sales volume and increased prices under power sales agreements with the Distribution Companies.

Wholesale and other revenues, net:  The table below describes the significant components of wholesale revenues for the Generation and Marketing segment. Wholesale and other revenues, net have been accumulated in these categories beginning in 2004 in connection with the Generation and Marketing segment’s change in strategy to eliminate speculative trading. Comparative amounts for these components are not available for 2003.

(In millions)	2005			2004
PJM Revenue:
Generation sold into PJM market	$	2,536.1		$	1,837.9
Power purchased from PJM		(2,375.5	)		(1,930.2	)
Net		160.6			(92.3	)
Release of escrow proceeds		2.7			68.1
Trading activities:
Realized gains (losses)		(24.9	)		59.9
Unrealized gains (losses)		20.6			(5.7	)
Net		(4.3	)		54.2	*
Other revenues		42.8			16.9
Total wholesale and other revenues	$	201.8		$	46.9

* Does not include a $45.1 million loss on a contract with an affiliate that was included in affiliated revenues. This contract expired on December 31, 2004 and was not renewed. The net trading gain, including this affiliated transaction, was $9.1 million.

Wholesale and other revenues increased $154.9 million for 2005 compared to 2004, primarily due to:

• a $252.9 million increase in net PJM revenues,

• partially offset by the receipt of $65.4 million associated with the sale of the CDWR contract and related hedge transactions, which was recorded during the three months ended March 31, 2004, and $2.7 million related to a guarantee liability that was released during the three months ended September 30, 2005 and

• a $58.5 million decrease in gains from trading activities.

The increase in net PJM revenues is due to higher generation revenues relative to the cost to serve the PLR load. During 2005, the weighted average “round-the-clock” price for power in Allegheny’s region of PJM, the APS Zone of the PJM market, was approximately $58 per MWh, which represents an increase of approximately 45% compared to 2004. Also during 2005, total MWhs generated increased by 4.2% compared to 2004. This increase in total MWhs generated was due to increased average market prices and increased availability of Allegheny’s coal-fired plants as a result of the return to service of Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 in June 2004. In addition, power purchased from PJM expense increased due to higher average market prices, partially offset by lower MWhs as a result of no longer serving certain customer classes, primarily Potomac Edison’s commercial and industrial customers in Maryland. The Generation and Marketing segment also did not serve Monongahela’s large commercial and industrial customers in Ohio for 2005.

Net gains from trading activities decreased due to the expiration on December 31, 2004 of an affiliated contract designed to sell the output from the AES Warrior Run generation facility into the wholesale market, which resulted in non-affiliated revenues of $51.7 million for 2004.

Wholesale and other revenues increased $516.4 million for 2004 compared to 2003, primarily due to a decrease in energy trading losses in 2004 as a result of AE Supply’s exit from speculative trading activities in the

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Western U.S. energy markets in 2003. Revenues in 2004 include $68.1 million in proceeds related to the sale of the CDWR contract and related hedge transactions that were released from escrow in 2004. The net PJM purchases component of 2004 revenues was negatively impacted by outages at the Hatfield’s Ferry and Pleasants generating facilities.

The realized and unrealized components of wholesale and other revenues in 2003 were as follows:

(In millions)	2003
Realized losses	$	(1.1	)
Unrealized losses		(468.4	)
Total wholesale and other revenues	$	(469.5	)

The table below outlines components of total trading losses associated with the Generation and Marketing segment’s exit from the Western U.S. energy markets during 2003. These losses were partially offset by trading gains associated with trading and wholesale operations in other national energy markets, net of trading losses associated with terminating or selling other energy trading positions.

(In millions)	2003
Unrealized loss—Sale and termination of energy trading contracts in the Western U.S., net	$	(394.0	)
Unrealized loss—Renegotiation of contract terms prior to sale (Western U.S.)		(152.2	)
Total net unrealized loss	$	(546.2	)
Realized gain—Sale and termination of energy trading contracts in the Western U.S., net		11.0
Total trading losses associated with exiting the Western U.S. energy markets	$	(535.2	)

Fair Value of Contracts:  AE Supply is currently qualifying certain of its new contracts under the “normal purchase and normal sale” scope exception under SFAS No. 133. As a result, AE accounts for these contracts on the accrual method, rather than marking these contracts to market value. AE uses derivative accounting for energy contracts that do not qualify under the scope exception. These energy contracts are recorded at fair value in the Consolidated Balance Sheets. The realized and unrealized revenues from energy trading activities are recorded on a net basis in “Operating revenues” in the Consolidated Statements of Operations. The fair value of the remaining trading portfolio consists primarily of interest rate swap agreements and commodity cash flow hedges as of December 31, 2005. The commodity cash flow hedges are reflected in other comprehensive income.

The fair values of trading contracts, which represent the net unrealized gain and loss on open positions, are recorded as assets and liabilities in the Consolidated Balance Sheets, after applying the appropriate counterparty netting agreements. At December 31, 2005, the fair values of trading contract assets and liabilities were $9.3 million and $115.9 million, respectively. At December 31, 2004, the fair values of trading contract assets and liabilities were $17.2 million and $97.3 million, respectively.

The following table disaggregates the net fair values of derivative contract assets and liabilities for the Generation and Marketing segment, based on the underlying market price source and the contract settlement periods. The table excludes non-derivatives such as AE Supply’s generation assets, PLR requirements and SFAS No. 133 scope exceptions under the normal purchase and normal sale election:

	Fair value of contracts at December 31, 2005
Classification of contracts by source of fair value (In millions)	Settlement by:															Settlement In Excess of Five Years			Total
	2006			2007			2008			2009			2010
Prices actively quoted	$	(84.3	)	$	(5.7	)	$	(5.5	)	$	(5.2	)	$	(5.0	)	$	(1.6	)	$	(107.3	)
Prices based on models		0.7			—			—			—			—			—			0.7
Total	$	(83.6	)	$	(5.7	)	$	(5.5	)	$	(5.2	)	$	(5.0	)	$	(1.6	)	$	(106.6	)

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The fair value of AE Supply’s contracts that are scheduled to settle by December 31, 2006 was a net liability of $83.6 million, primarily related to interest rate swaps and commodity cash flow hedges.

See Note 5, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements for additional information.

Changes in Fair Value:    Net unrealized gains (losses) of $20.6 million and $(5.7) million for 2005 and 2004, respectively, were recorded on the Consolidated Statements of Operations in “Operating revenues” to reflect the change in fair value of the trading contracts. The following table provides a summary of changes in the net fair value, or trading contract assets less trading contract liabilities, of AE Supply’s trading contracts:

(In millions)	2005			2004
Net fair value of contract liabilities at January 1,	$	(80.1	)	$	(72.7	)
Changes in fair value of cash flow hedges		(47.1	)		(3.3	)
Unrealized gains (losses) on contracts, net		20.6			(5.7	)
Net options received *		—			1.6
Net fair value of contract liabilities at December 31,	$	(106.6	)	$	(80.1	)

* Amount reflects $(2.3) million of option premium expirations for 2004.

As shown in the table above, the net fair value of AE Supply’s trading contracts decreased by $26.5 million for 2005, compared to 2004. The decreases in the fair values was primarily due to changes in the fair values of cash flow hedges, partially offset by settlements on interest rate and commodity contracts.

There has been, and may continue to be, significant volatility in the market prices for electricity and natural gas at the wholesale level, which will affect AE Supply’s operating results and cash flows. Similarly, volatility in interest rates will affect AE Supply’s operating results and cash flows.

Operating Expenses

Fuel Consumed in Electric Generation:  Fuel consumed in electric generation represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power and emission allowances. Fuel consumed in electric generation was as follows:

(In millions)	2005		2004		2003
Fuel consumed in electric generation	$	736.6	$	614.4	$	592.0

Total fuel consumed in electric generation increased by $122.2 million for 2005 compared to 2004, primarily due to a $114.3 million increase in coal expense. The increase in coal expense was due to an increase in the price of coal of approximately $4.50 per ton, from approximately $30.00 per ton to approximately $34.50 per ton, and a 1.2 million ton increase in the amount of coal burned. The increase in the amount of coal burned was primarily due to a 4.2% increase in total MWhs generated as a result of increased availability at Allegheny’s coal-fired plants.

Total fuel expenses increased by $22.4 million for 2004 compared to 2003, primarily due to:

• a $34.1 million increase in natural gas costs for the gas-fired units,

• an $8.5 million increase due to the consolidation of Hunlock Creek Energy Ventures, LLC (“Hunlock Creek”) in 2004 and

• a $7.1 million increase in emission allowances,

• partially offset by a $27.4 million decrease in costs for coal and oil fired units, primarily due to reduced generation as a result of the outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1, which was partially offset by a 2.1% increase in average fuel prices.

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Purchased Power and Transmission:  Purchased power and transmission expenses were as follows:

(In millions)	2005		2004		2003
Purchased power and transmission	$	81.0	$	86.2	$	76.1

Purchased power and transmission expenses decreased $5.2 million for 2005 compared to 2004, primarily due to certain pipeline contracts that were released during 2004, partially offset by increased normal purchase normal sale expense and increased purchased power related to OVEC.

Purchased power and transmission increased $10.1 million for 2004 compared to 2003, primarily due to an increase of $10.8 million related to the release to a third party of Kern River pipeline capacity. AE Supply’s election of normal purchase and normal sale scope exception also contributed to the increase in purchased power and transmission. However, this increase was offset by the impact of the consolidation of Hunlock Creek. See Note 22, “Variable Interest Entities,” to the Consolidated Financial Statements for additional information.

Gain on Sale of OVEC Power Agreement and Shares:  On December 31, 2004, AE sold a 9% equity interest in OVEC to Buckeye. In addition, AE Supply assigned to Buckeye all of its rights and obligations under a new OVEC inter-company power agreement that is effective on March 13, 2006. However, AE Supply will retain its rights under the current agreement to 9% of the power from the OVEC electric generation facilities through March 12, 2006. The sale resulted in a gain of $94.8 million, before income taxes, which is recorded in “Gain on sale of OVEC power agreement and shares” on the Consolidated Statements of Operations. AE recorded a gain of $6.2 million, before income taxes, and AE Supply recorded a gain of $88.6 million, before income taxes. Cash proceeds from the sale were $102.0 million, of which $6.0 million is expected to be received in April 2006 upon the fulfillment of certain post-closing obligations. The remaining $96.0 million in proceeds was used to reduce debt in the first quarter of 2005. AE retained a 3.5% equity interest in OVEC, and Monongahela retained its rights to 3.5% of OVEC’s power output.

Operations and Maintenance:  Operations and maintenance expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:

(In millions)	2005		2004		2003
Operations and maintenance	$	378.7	$	424.1	$	538.2

Operations and maintenance expenses decreased $45.4 million for 2005 compared to 2004, primarily due to:

• a $35.0 million decrease in contract work and outside services expenses,

• a $6.4 million decrease in insurance expense and

• a $4.8 million decrease in rent expense.

The decrease in contract work expense was primarily a result of the receipt of insurance recoveries related to Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 and decreased outside service expense due to a reduction in the use of outside consultants. The decrease in insurance expense is a result of reduced claims and lower premiums. The decrease in rent expense is the result of certain non-recurring impairment charges on New York office space during 2004 and lease cancellation fees incurred during 2004.

Operations and maintenance expenses decreased $114.1 million for 2004 compared to 2003, primarily due to:

• a decrease of $41.1 million in outside services expense,

• $33.5 million in impairment charges related to assets held for sale recorded during 2003 and

• $32.0 million of contract termination costs recorded during 2003.

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Depreciation and Amortization:  Depreciation and amortization expenses were as follows:

(In millions)	2005		2004		2003
Depreciation and amortization	$	154.6	$	150.6	$	134.0

Depreciation and amortization expense increased $4.0 million for 2005 compared to 2004, primarily due to increased depreciation resulting from net property plant and equipment additions.

Depreciation and amortization expense increased $16.6 million for 2004 compared to 2003, primarily due to additions of facilities, including the Springdale generation facility, which was placed in service in July 2003, and the installation of environmental control equipment.

Taxes Other Than Income Taxes:  Taxes other than income taxes primarily includes West Virginia business and occupation taxes, payroll taxes and property taxes. Taxes other than income taxes were as follows:

(In millions)	2005		2004		2003
Taxes other than income taxes	$	82.1	$	72.3	$	75.8

Taxes other than income taxes increased $9.8 million for 2005 compared to 2004, primarily due to:

• a $5.4 million increase in capital stock/franchise taxes due to a $1.6 million change in the payroll tax apportionment factor and $3.7 million in adjustments recorded during 2004,

• a $3.7 million increase in local property taxes due to favorable settlements of $4.4 million, which were recorded during 2004 and

• a $1.5 million increase in business and occupation taxes due to a decrease in the tax credits compared to 2004.

Taxes other than income taxes decreased $3.5 million for 2004 compared to 2003, primarily due to decreases in property taxes as a result of lower assessed values and tax settlements. These amounts were partially offset by increases in business and occupation taxes and payroll taxes.

Other Income and Expenses, Net:  Other income and expenses, net, represent non-operating income and expenses before income taxes. Other income and expenses, net were as follows:

(In millions)	2005		2004		2003
Other income and expenses, net	$	21.1	$	1.7	$	63.9

Other income and expenses, net, increased $19.4 million for 2005 compared to 2004, primarily as a result of $11.2 million in cash received from a former trading executive’s forfeited assets and a $5.5 million increase in interest income on investments.

Other income and expenses, net, decreased $62.2 million for 2004 compared to 2003, primarily as a result of a $61.7 million gain recognized in 2003 related to the reapplication of provisions of SFAS No. 71 by Monongahela to its generation assets in West Virginia.

Interest Expense and Preferred Dividends:  Interest expense and preferred dividends were as follows:

(In millions)	2005		2004		2003
Interest expense and preferred dividends	$	318.2	$	276.2	$	301.0

Interest expense and preferred dividends increased $42.0 million for 2005 compared to 2004, primarily due to:

• charges of approximately $32.6 million reflecting the premium and associated costs to redeem AE Supply’s outstanding 10.25% and 13% Senior Notes,

• $45.0 million in interest expense related to a court decision in the litigation involving Merrill Lynch and

• $26.2 million in non-recurring interest expense related to the tender offer for Trust Preferred Securities in April 2005,

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• partially offset by interest expense savings of $42.0 million on long-term debt resulting from lower interest rates due to debt refinancing and lower average debt outstanding and

• a $19.8 million decrease in amortization of debt expense primarily as a result of write-offs of deferred financing costs during 2004 in connection with debt.

Interest expense and preferred dividends decreased $24.8 million for 2004 compared to 2003, primarily due to:

• interest expense savings of $57.9 million resulting from lower interest rates and lower average debt outstanding,

• partially offset by $11.6 million of increased interest expense associated with the July 2003 issuance by Capital Trust of Trust Preferred Securities,

• a $9.8 million increase in the amortization of debt expenses resulting from the write-off of deferred financing costs due to the refinancing of credit facilities in 2004 and

• a $12.0 million decrease in capitalized interest primarily resulting from the Springdale generation facility, which was placed in service in July 2003.

For additional information regarding Allegheny’s short-term and long-term debt, see Note 2, “Capitalization,” to the Consolidated Financial Statements. For additional information regarding the litigation involving Merrill Lynch, see Note 23, “Commitments and Contingencies,” to the Consolidated Financial Statements.

Minority Interest in Net Loss (Income)

Minority interest in net loss (income) was $(0.6) million, $0.9 million and $7.2 million for 2005, 2004 and 2003, respectively, which primarily represents Merrill Lynch’s equity interest in AE Supply.

Discontinued Operations:  Losses from discontinued operations for the Generation and Marketing segment were as follows:

(In millions)	2005			2004			2003
Discontinued operations	$	(7.2	)	$	(426.4	)	$	(34.5	)

Loss from discontinued operations decreased $419.2 million for 2005 compared to 2004 and increased $391.9 million for 2004 compared to 2003, primarily due to approximately $404 million of impairment charges that were recorded during the third quarter of 2004.

See Note 3, “Discontinued Operations and Assets Held For Sale,” to the Consolidated Financial Statements for additional information.

Cumulative Effect of Accounting Changes, Net

In connection with its adoption of FIN 47, Allegheny recorded a charge of $5.9 million, net of income taxes, as the cumulative effect of an accounting change as of December 31, 2005.

In connection with its adoption of SFAS No. 143, Allegheny recorded a charge of $7.4 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2003.

See Note 6, “Asset Retirement Obligations,” to the Consolidated Financial Statements for additional information.

In connection with its adoption of Emerging Issues Task Force Issue No. 02-3 “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” (“EITF 02-3”), AE Supply recorded a charge of $12.2 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2003.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES—RESULTS OF OPERATIONS

Income (Loss) Summary

(In millions)	Delivery and Services			Generation and Marketing			Eliminations			Total
2005
Operating revenues	$	691.4		$	415.5		$	(317.0	)	$	789.9
Fuel consumed in electric generation		—			(148.4	)		—			(148.4	)
Purchased power and transmission		(460.9	)		(126.6	)		317.0			(270.5	)
Loss on sale of Ohio T&D assets		(29.3	)		—			—			(29.3	)
Operations and maintenance		(115.5	)		(85.3	)		—			(200.8	)
Depreciation and amortization		(31.5	)		(34.8	)		—			(66.3	)
Taxes other than income taxes		(26.2	)		(23.5	)		—			(49.7	)
Operating income (loss)		28.0			(3.1	)		—			24.9
Other income and expenses, net		4.2			8.7			—			12.9
Interest expense		(25.1	)		(18.3	)		—			(43.4	)
Income (loss) from continuing operations before income taxes		7.1			(12.7	)		—			(5.6	)
Income tax benefit from continuing operations		1.3			13.5			—			14.8
Income from continuing operations		8.4			0.8			—			9.2
Income from discontinued operations, net of tax		1.0			—			—			1.0
Net income	$	9.4		$	0.8		$	—		$	10.2
2004
Operating revenues	$	669.0		$	312.8		$	(298.0	)	$	683.8
Fuel consumed in electric generation		—			(119.1	)		—			(119.1	)
Purchased power and transmission		(428.5	)		(57.0	)		298.0			(187.5	)
Operations and maintenance		(117.9	)		(96.6	)		—			(214.5	)
Depreciation and amortization		(31.4	)		(34.4	)		—			(65.8	)
Taxes other than income taxes		(27.0	)		(23.1	)		—			(50.1	)
Operating income (loss)		64.2			(17.4	)		—			46.8
Other income and expenses, net		2.4			6.7			—			9.1
Interest expense		(24.8	)		(18.5	)		—			(43.3	)
Income (loss) from continuing operations before income taxes		41.8			(29.2	)		—			12.6
Income tax benefit (expense) from continuing operations		(11.4	)		15.2			—			3.8
Income (loss) from continuing operations		30.4			(14.0	)		—			16.4
Loss from discontinued operations, net of tax		(13.9	)		—			—			(13.9	)
Net income (loss)	$	16.5		$	(14.0	)	$	—		$	2.5

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(In millions)	Delivery and Services			Generation and Marketing			Eliminations			Total
2003
Operating revenues	$	655.4		$	350.9		$	(287.4	)	$	718.9
Fuel consumed in electric generation		—			(135.1	)		—			(135.1	)
Purchased power and transmission		(407.0	)		(44.6	)		287.4			(164.2	)
Operations and maintenance		(145.4	)		(83.6	)		—			(229.0	)
Depreciation and amortization		(29.8	)		(33.9	)		—			(63.7	)
Taxes other than income taxes		(22.0	)		(19.8	)		—			(41.8	)
Operating income		51.2			33.9			—			85.1
Other income and expenses, net		2.5			67.0			—			69.5
Interest expense		(22.2	)		(21.2	)		—			(43.4	)
Income from continuing operations before income taxes		31.5			79.7			—			111.2
Income tax expense from continuing operations		(15.3	)		(23.9	)		—			(39.2	)
Income from continuing operations		16.2			55.8			—			72.0
Income from discontinued operations, net of tax		9.2			—			—			9.2
Cumulative effect of accounting change, net of tax		(0.5	)		—			—			(0.5	)
Net income	$	24.9		$	55.8		$	—		$	80.7

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MONONGAHELA POWER COMPANY—CONSOLIDATED RESULTS OF OPERATIONS:

This section is an overview of Monongahela’s consolidated results of operations, which are discussed in greater detail for each segment in “Monongahela Power Company—Discussion of Segment Results of Operations” below.

Operating Revenues

Operating revenues increased $106.1 million for 2005 compared to 2004, primarily because:

• generation revenue increased during 2005 compared to 2004, when unplanned outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 during the first half of 2004 negatively impacted generation,

• generation revenue increased due to colder weather during 2005 and higher PJM market prices during 2005, which enabled some of Monongahela’s smaller generation facilities to be dispatched and

• retail revenues increased due to customer growth and increased customer usage as a result of a 57.5% increase in CDD.

These increases were partially offset by an increase in planned outage weeks at Allegheny’s supercritical generation facilities, from 15 weeks to 20 weeks, during the fourth quarter of 2005 and unplanned outages at Pleasants Units No. 1 and No. 2 and Hatfield’s Ferry Unit No. 3 during the fourth quarter of 2005. These outages came at a time when Monongahela’s service territory was experiencing unusually cold weather, increased demand and high market prices. As a result, Monongahela was a net purchaser of power during a period of high power prices in the PJM market.

Operating revenues decreased $35.1 million for 2004 compared to 2003, primarily due to:

• decreased revenues resulting from unplanned outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 during 2004,

• partially offset by increased revenues resulting from increases in residential, commercial and industrial revenues due to customer growth and increased customer usage as a result of a 28.0% increase in CDD.

Operating Income

Operating income decreased $21.9 million for 2005 compared to 2004, primarily due to:

• a $128.0 million increase in operating expenses,

• offset by a $106.1 million increase in total operating revenues, as discussed above.

Operating expenses increased primarily as a result of a $29.3 million loss recorded in connection with the sale of the Ohio T&D assets and increases in fuel consumed in electric generation and purchased power and transmission expenses. These increases were partially offset by decreased operations and maintenance expenses. Fuel consumed in electric generation increased, primarily due to increased coal prices and an increase in MWhs generated at Monongahela’s jointly-owned coal-fired plants. Purchased power and transmission expense increased, primarily due to congestion charges and increases in the prices for purchased power from PJM for Monongahela’s large commercial and industrial customers in Ohio. Operations and maintenance expense decreased, primarily due to decreased contract work resulting from insurance recoveries related to Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 and decreased outside services expense due to a reduction in the use of outside consultants, as well as reduced salaries and wages expense due to a decreased number of employees.

Operating income decreased $38.3 million for 2004 compared to 2003, primarily due to a $35.1 million decrease in operating revenues as discussed, above.

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Income Tax Expense

The effective tax rates for Monongahela’s continuing operations were 264.3%, (30.2)% and 35.3% for 2005, 2004 and 2003, respectively.

Income tax benefit for 2005 was higher than the income tax benefit calculated at the federal statutory tax rate, primarily due to:

• the allocation of consolidated tax savings to Monongahela and

• a $4.3 million tax benefit relating to the amendment of 2003 income tax returns as described in Note 1, “Basis of Presentation,” to the Monongahela’s Consolidated Financial Statements.

The negative effective tax rate for 2004 was primarily due to state tax benefits and investment tax credits applied to a low level of pre-tax income for the year.

The 2003 effective tax rate did not significantly differ from the federal statutory tax rate.

See Note 8, “Income Taxes,” to Monongahela’s Consolidated Financial Statements for additional information.

Continuing Operations

Income from continuing operations decreased $7.2 million for 2005 compared to 2004, primarily due to:

• a $21.9 million decrease in operating income, as discussed above,

• partially offset by a $3.8 million increase in other income and expenses, net due to increased equity earnings in AGC and interest income and

• an $11.0 million decrease in income tax expense, as discussed above.

Income from continuing operations decreased $55.6 million for 2004 compared to 2003, primarily due to decreases in operating revenues and other income and expenses, net, partially offset by increased income tax expense, as discussed above.

Discontinued Operations

Monongahela recorded income (losses) from discontinued operations of $1.0 million, $(13.9) million and $9.2 million for 2005, 2004 and 2003, respectively, relating to Monongahela’s natural gas operations.

The $14.9 million decrease in loss from discontinued operations for 2005 compared to 2004 was primarily a result of impairment charges on Monongahela’s West Virginia natural gas operations of $21.7 million, net of tax, recorded during the third and fourth quarters of 2004, compared to impairment charges of $7.0 million, net of tax, recorded during 2005.

The $23.1 million decrease in income from discontinued operations for 2004 compared to 2003 was primarily a result of impairment charges on Monongahela’s West Virginia natural gas operations of $21.7 million, net of tax, recorded during the third and fourth quarters of 2004.

See Note 3, “Discontinued Operations and Assets Held for Sale,” to Monongahela’s Consolidated Financial Statements for additional information.

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MONONGAHELA POWER COMPANY—DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

Monongahela’s Delivery and Services Segment

Net income decreased $7.1 million for 2005 compared to 2004, primarily due to:

• a $36.2 million decrease in operating income,

• partially offset by a $12.7 million increase in income tax benefit from continuing operations and

• a $14.9 million decrease in losses from discontinued operations.

Net income decreased $8.4 million for 2004 compared to 2003, primarily due to:

• a $23.1 million decrease in income from discontinued operations,

• partially offset by a $13.0 million increase in operating income.

Operating Revenues

The following table provides retail electricity sales information related to the Delivery and Services segment:

	2005	2004	2003	2005 Change		2004 Change
Electricity sales (million kWhs):
Residential	3,679	3,490	3,393	5.4	%	2.9	%
Commercial	2,749	2,609	2,556	5.4	%	2.1	%
Industrial	5,826	6,000	5,991	(2.9	)%	0.2	%
Other	26	26	26	—	%	—	%
Total electricity sales	12,280	12,125	11,966	1.3	%	1.3	%
HDD *	4,688	4,762	5,308	(1.6	)%	(10.3	)%
CDD *	1,238	786	614	57.5	%	28.0	%

* Normal (historical) HDD are 5,508 and normal (historical) CDD are 742, calculated on a weighted-average basis across the geographic areas served by the Monongahela.

Operating revenues were as follows:

(In millions)	2005		2004		2003
Retail electric:
Residential	$	264.2	$	250.6	$	243.8
Commercial		163.1		151.3		148.7
Industrial		227.7		225.2		222.4
Other		2.7		2.6		2.6
Total retail electric		657.7		629.7		617.5
Transmission services and bulk power		23.9		31.1		31.0
Other affiliated and non-affiliated energy services		9.8		8.2		6.9
Total Delivery and Services revenues	$	691.4	$	669.0	$	655.4

Operating revenues increased $22.4 million for 2005 compared to 2004 and increased $13.6 million for 2004 compared to 2003. These increases were primarily due to increased residential and commercial retail electric revenues.

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Retail electric revenues increased $28.0 million for 2005 compared to 2004, due to:

• a $13.6 million increase in residential revenues and

• an $11.8 million increase in commercial revenues.

Residential and commercial revenues increased due to a 5.4% increase in MWhs sold as a result of a 0.7% increase in customer growth and additional customer usage due to a 57.5% increase in CDD. In addition, the absence of a West Virginia customer choice credit for 2005 increased revenues.

Retail electric revenues increased $12.2 million for 2004 compared to 2003, due to:

• a $6.8 million increase in residential revenues,

• a $2.6 million increase in commercial revenues and

• a $2.8 million increase in industrial revenues.

Residential revenues increased due to a 2.9% increase in residential MWhs sold. Residential MWhs sold increased as a result of additional customer usage due to a 28.0% increase in CDD and a 0.4% increase in the average number of customers.

Commercial revenues increased due to a 2.1% increase in commercial MWhs sold as a result of a 28.0% increase in CDD and a 1.4% increase in the average number of customers.

Industrial revenues increased as a result of a 0.2% increase in industrial MWhs sold as a result of increased customer usage.

Transmission services and bulk power decreased $7.2 million for 2005 compared to 2004, primarily due to the expiration of certain transition credits that were associated with Allegheny’s entry into the PJM regional transmission system.

Operating Expenses

Purchased Power and Transmission:  Purchased power and transmission represents power purchases from, and exchanges with, other companies and purchases from qualified facilities under PURPA. Purchased power and transmission consists of the following items:

(In millions)	2005		2004		2003
Other purchased power and transmission	$	403.0	$	371.9	$	358.1
From PURPA generation *		57.9		56.6		48.9
Total purchased power and transmission	$	460.9	$	428.5	$	407.0
*PURPA cost (cents per kWh)		4.4		4.3		5.2

Purchased power and transmission expense increased $32.4 million for 2005 compared to 2004 and $21.5 million for 2004 compared to 2003, primarily due to increases in other purchased power and transmission.

Other purchased power and transmission primarily consists of purchases of energy by Monongahela’s Delivery and Services segment from Monongahela’s Generation and Marketing segment, as well as purchased power from PJM to meet Monongahela’s Ohio PLR obligations.

Other purchased power and transmission increased $31.1 million for 2005 compared to 2004, primarily due to a 7.4% increase in the price per MWh purchased and an increase in MWhs purchased. The increase in MWhs was the result of customer growth and increased usage, and the increase in price per MWh purchased was due to

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purchases of power from PJM at higher market prices to meet the needs of Monongahela’s large commercial and industrial customers in Ohio. Purchased power and transmission for 2005 included $66.2 million of costs associated with serving commercial and industrial customers in Ohio, from PJM.

Other purchased power and transmission increased $13.8 million for 2004 compared to 2003, primarily due to increases in both the rates for, and volume of, purchased power. Purchased power and transmission for 2004 included $30.9 million of costs associated with serving commercial and industrial customers in Ohio at rates higher than those charged to customers.

Purchased power and transmission from PURPA generation increased $7.7 million for 2004 compared to 2003, primarily as a result of the receipt during 2003 of a contractually required payment from one of the PURPA generation facilities that supplies power to Monongahela. This increase was partially offset by lower MWhs generated at lower average prices.

Loss on Sale of Ohio T&D Assets:  During 2005, the Delivery and Services segment recorded a loss of $29.3 million in connection with its sale of Monongahela’s electric T&D operations in Ohio. The loss was recorded based on the estimated value, at December 31, 2005, of Monongahela’s power sales agreement with Columbus Southern to provide power at below-market prices from December 31, 2005 through May 31, 2007, partially offset by approximately $8.0 million, representing the purchase price less the net book value of the assets at December 31, 2005 and approximately $2.0 million in expenses associated with the sale. The sale was completed as of December 31, 2005.

Operations and Maintenance:  Operations and maintenance expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:

(In millions)	2005		2004		2003
Operations and maintenance	$	115.5	$	117.9	$	145.4

Operations and maintenance expenses decreased $2.4 million for 2005 compared to 2004, primarily due to:

• a $1.4 million decrease in contract expenses related to vegetation control and

• a $2.4 million decrease in insurance expense,

• partially offset by a $1.5 million increase in other service expenses.

Vegetation control expenses decreased due to a decrease in contractor expenditures resulting from a decrease in the size of the area covered during 2005. Insurance expense decreased as a result of reduced claims and lower premiums. Other service expenses increased as a result of costs associated with transition services relating to the sale of Monongahela’s natural gas T&D operations in West Virginia in 2005.

Operations and maintenance expenses decreased $27.5 million for 2004 compared to 2003, primarily due to:

• a $6.4 million decrease in insurance expense,

• a $5.9 million decrease in costs related to uncollectible accounts,

• a $5.4 million decrease in employee benefits expense and

• a $4.6 million decrease in outside service and contract work expense.

The decrease in insurance expense was primarily due to lower workers’ compensation expense and lower costs for potential claims alleging exposure to asbestos. The decrease in uncollectible accounts expense was due to bankruptcy expenses recorded for certain customers in 2003. The decrease in employee benefits expense reflects a $3.0 million decrease in SERP and ELIP expenses due to costs recorded in 2003 for certain executives,

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a $2.8 million decrease in disability costs principally related to costs recorded in 2003 and a $1.5 million decrease in costs for other postretirement benefits. These amounts were partially offset by a $1.3 million increase in pension expense resulting from the reductions in the discount rate and expected long-term rate of return on pension plan assets. Contract work and outside services decreased as a result of decreased use of independent contractors and consultants.

Depreciation and Amortization:  Depreciation and amortization expenses were as follows:

(In millions)	2005		2004		2003
Depreciation and amortization	$	31.5	$	31.4	$	29.8

Depreciation and amortization expense increased $1.6 million for 2004 compared to 2003, primarily due to increased depreciation resulting from net property, plant and equipment additions.

Taxes Other Than Income Taxes:  Taxes other than income taxes primarily includes West Virginia business and occupation taxes, payroll taxes and property taxes. Taxes other than income taxes were as follows:

(In millions)	2005		2004		2003
Taxes other than income taxes	$	26.2	$	27.0	$	22.0

Taxes other than income taxes increased $5.0 million for 2004 compared to 2003, primarily due to an increase in business and occupation taxes due to increased taxable kWh sales and a favorable sales and use tax settlement in 2003 that did not recur in 2004.

Interest Expense:  Interest expense was as follows:

(In millions)	2005		2004		2003
Interest expense	$	25.1	$	24.8	$	22.2

Interest expense increased $2.6 million for 2004 compared to 2003, primarily due to the annual revision in segment allocation factors. Monongahela allocates interest expense between its segments based on a number of factors, including the relative amount of each segment’s identifiable assets. Interest expense increased for the Delivery and Services segment and decreased for the Generation and Marketing segment in 2004 due to a change in the relative amounts of identifiable assets held in each segment.

Generation and Marketing

Net income increased $14.8 million for 2005 compared to 2004, primarily due to a $14.3 million decrease in operating loss.

Net income decreased $69.8 million for 2004 compared to 2003, primarily due to:

• a $51.3 million decrease in operating income and

• a $60.3 million decrease in other income and expenses, net,

• partially offset by a $39.1 million decrease in income tax expenses from continuing operations.

Operating Revenues

Operating revenues were as follows:

(In millions)	2005		2004			2003
Revenue from affiliates	$	301.6	$	317.6		$	338.5
Wholesale and other, net		113.9		(4.8	)		12.4
Total Generation and Marketing revenues	$	415.5	$	312.8		$	350.9

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Operating revenues increased $102.7 million for 2005 compared to 2004 due to increased wholesale and other affiliated revenues, net. Operating revenues decreased $38.1 million for 2004 compared to 2003 due to decreased revenue from affiliates and wholesale and other revenues, net.

Revenues from affiliates represent sales to Monongahela’s Delivery and Services segment to meet its customer obligations and affiliated sales to AE Supply, as discussed below.

Monongahela’s Generation and Marketing segment purchases energy from, and sells capacity to, AE Supply at PJM market prices. Prior to January 2005, an affiliated power sales agreement with AE Supply covering these transactions contained a pricing mechanism that included financial transmission rights (“FTR”) and congestion values, and the transactions were recorded as affiliated revenues and affiliated purchased power and transmission expense. In January 2005, Monongahela signed a Revised Affiliated Power Sales Agreement with AE Supply. Under the Revised Affiliated Power Sales Agreement, Monongahela records energy purchases and capacity sales transactions with AE Supply as affiliated revenue or purchased power and transmission expense depending on hourly energy requirements. FTR and congestion values under the Revised Affiliated Power Sales Agreement are recorded as nonaffiliated revenue.

Revenues from affiliates decreased $16.0 million for 2005 compared to 2004, primarily due to the change in the allocation of revenues under Monongahela’s affiliated contract with AE Supply. This decrease was partially offset by increased revenue resulting from the Generation and Marketing segment’s portion of additional power to service load requirements of Monongahela’s Delivery and Services segment in West Virginia. These requirements were previously purchased by the Delivery and Services segment from a third party.

Revenues from affiliates decreased $20.9 million for 2004 compared to 2003, primarily due to decreases in the quantity of electricity produced, as a result of outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1.

Wholesale and other, net, revenues increased $118.7 million for 2005 compared to 2004, primarily due to the change in the allocation of revenues under Monongahela’s affiliated contract with AE Supply related to FTR and congestion, as discussed above.

Wholesale and other, net, revenues decreased $17.2 million for 2004 compared to 2003, primarily due to decreases in the quantity of electricity produced as a result of outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1.

Operating Expenses

Fuel Consumed in Electric Generation:  Fuel consumed in electric generation represents the cost of coal, lime and other materials consumed in the generation of power and emission allowances. Fuel consumed in electric generation was as follows:

(In millions)	2005		2004		2003
Fuel consumed in electric generation	$	148.4	$	119.1	$	135.1

Total fuel consumed in electric generation expenses increased $29.3 million for 2005 compared to 2004, primarily due to a $27.6 million increase in coal expense. The increase in coal expense was primarily due to increased coal prices and an increase in MWhs generated as a result of increased availability at Monongahela’s coal-fired generation facilities.

Total fuel consumed in electric generation expenses decreased $16.0 million for 2004 compared to 2003, primarily due to a decrease in kWhs generated as a result of the outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1, partially offset by an increase in average fuel prices.

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Purchased Power and Transmission:  Purchased power and transmission represents power purchases from AE Supply and exchanges with other companies. Purchased power and transmission was as follows:

(In millions)	2005		2004		2003
Purchased power and transmission	$	126.6	$	57.0	$	44.6

Purchased power and transmission increased $69.6 million for 2005 compared to 2004, primarily due to higher congestion charges and additional purchases to service load requirements of Monongahela’s Delivery and Services segment in West Virginia that were previously obtained from a third party.

Purchased power and transmission increased $12.4 million for 2004 compared to 2003. This increase was primarily due to increased market purchases resulting from decreases in MWhs generated. The decrease in MWhs generated was a consequence of reduced generation of certain plants due to market conditions and the outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1.

Operations and Maintenance:  Operations and maintenance expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:

(In millions)	2005		2004		2003
Operations and maintenance	$	85.3	$	96.6	$	83.6

Operations and maintenance expenses decreased $11.3 million for 2005 compared to 2004. This decrease was primarily due to a $9.2 million decrease in contract work expenses, primarily due to the receipt of insurance recoveries related to Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 and a reduction in planned outage weeks at Hatfield’s Ferry and Pleasants, as well as decreased outside services expense due to a reduction in the use of outside consultants.

Operations and maintenance expenses increased $13.0 million for 2004 compared to 2003. This increase was primarily due to an increase in planned outage weeks at Hatfield’s Ferry and Pleasants.

Taxes Other Than Income Taxes:  Taxes other than income taxes primarily includes West Virgina business and occupation taxes, payroll taxes and property taxes. Taxes other than income taxes were as follows:

(In millions)	2005		2004		2003
Taxes other than income taxes	$	23.5	$	23.1	$	19.8

Taxes other than income taxes increased $3.3 million for 2004 compared to 2003, primarily due to increases in business and occupation taxes resulting from a tax credit that expired in 2003 and property taxes as a result of a favorable court settlement in 2003 that did not recur in 2004.

Other Income and Expenses, Net:  Other income and expenses, net, represent non-operating income and expenses before income taxes. Other income and expenses, net were as follows:

(In millions)	2005		2004		2003
Other income and expenses, net	$	8.7	$	6.7	$	67.0

Other income and expenses, net, increased $2.0 million for 2005 compared to 2004, primarily due to increased equity earnings in AGC and increased interest income.

Other income and expenses, net, decreased $60.3 million for 2004 compared to 2003, primarily due to the recognition of a $61.7 million gain related to the reapplication of the provisions of SFAS No. 71 to generation assets in West Virginia that was recorded in the first quarter of 2003.

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See Note 10, “Accounting for the Effects of Price Regulation,” and Note 14, “Other Income and Expenses, Net,” to Monongahela’s Consolidated Financial Statements for additional details.

Interest Expense:  Interest expense was as follows:

(In millions)	2005		2004		2003
Interest expense	$	18.3	$	18.5	$	21.2

Interest expense decreased $2.7 million for 2004 compared to 2003, primarily due to the annual revision in segment allocation factors. Monongahela allocates interest expense between its segments based on a number of factors, including the relative amount of each segment’s identifiable assets. Interest expense decreased for the Generation and Marketing segment and increased for the Delivery and Services segment in 2004 due to a change in the relative amounts of identifiable assets held in each segment.

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THE POTOMAC EDISON COMPANY AND SUBSIDIARIES—RESULTS OF OPERATIONS

Income Summary

(In millions)	2005		2004		2003
Operating revenues	$	971.2	$	924.4	$	905.2
Operating income	$	120.1	$	98.4	$	71.3
Income before income taxes and cumulative effect of accounting change	$	99.8	$	72.8	$	61.2
Net income	$	66.4	$	38.0	$	40.5

Net income increased $28.4 million for 2005 compared to 2004. This increase was primarily due to a $21.7 million increase in operating income and a $4.7 million decrease in interest expense.

Net income decreased $2.5 million for 2004 compared to 2003, primarily due to:

• the recognition, during the first quarter of 2003, of a $14.1 million pre-tax gain for the reapplication of SFAS No. 71, which was recorded in other income,

• a $1.2 million increase in interest expense and

• a $14.2 million increase in income tax expense,

• partially offset by a $27.1 million increase in operating income, which was primarily the result of increased operating revenue and lower operations and maintenance expense.

Operating Revenues

The following table provides retail electricity sales information related to Potomac Edison:

	2005	2004	2003	2005 Change		2004 Change
Electricity sales (million kWhs):
Residential	6,154	5,820	5,593	5.7	%	4.1	%
Commercial	3,378	3,213	3,077	5.1	%	4.4	%
Industrial	6,366	6,499	6,362	(2.0	)%	2.2	%
Other	24	24	24	—	%	—	%
Total electricity sales	15,922	15,556	15,056	2.4	%	3.3	%
HDD *	5,148	5,109	5,497	0.8	%	(7.1	)%
CDD *	1,220	1,046	844	16.6	%	23.9	%

* Normal (historical) HDD are 5,249 and normal (historical) CDD are 902, calculated on a weighted-average basis across the geographic areas served by the Potomac Edison.

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Operating revenues were as follows:

(In millions)	2005		2004		2003
Retail electric:
Residential	$	417.5	$	396.9	$	380.1
Commercial		220.4		193.3		183.8
Industrial		234.6		243.9		241.3
Other		5.4		5.1		4.9
Total retail electric		877.9		839.2		810.1
Transmission services and bulk power		85.0		75.6		85.9
Other affiliated and non-affiliated energy services		8.3		9.6		9.2
Total operating revenues	$	971.2	$	924.4	$	905.2

Retail electric revenues increased $38.7 million for 2005 compared to 2004, primarily due to:

• a $20.6 million increase in residential revenues and

• a $17.8 million aggregate increase in commercial and industrial revenues.

Residential revenues increased due to a 5.7% increase in residential MWhs sold. Residential MWhs sold increased as a result of additional customer usage due to a 16.6% increase and a 0.8% increase in CDD and HDD, respectively, and a 2.9% increase in the average number of customers.

Commercial and industrial revenues increased in the aggregate as a result of higher market-based pricing for the generation component of rates in Maryland and a 5.1% increase in commercial MWhs sold. Commercial MWhs sold increased due to a 2.8% increase in the average number of customers and increased customer usage. These increases were partially offset by reduced SOS requirements from certain industrial customers who switched to alternative service providers for their electricity generation requirements and a significant reduction in usage by one large industrial customer that curtailed its operations in December 2005.

Retail electric revenues increased $29.1 million for 2004 compared to 2003, primarily due to increased residential and commercial regulated electric revenues. Residential and commercial revenues increased due to an increase in MWh sales resulting from an increase in the average number of customers served and an increase in customer usage.

Transmission services and bulk power revenues increased $9.4 million for 2005 compared to 2004, primarily due to increased MWh sales at higher prices related to the AES Warrior Run PURPA generation facility, partially offset by decreased transmission revenues as a result of the expiration of certain transition credits associated with Potomac Edison’s entry into the PJM regional transmission system.

Transmission and bulk power revenues decreased $10.3 million for 2004 compared to 2003, primarily as a result of the expiration of certain bulk power contracts in June 2003.

One industrial customer accounted for 12.9%, 12.9% and 10.5% of Potomac Edison’s 2005, 2004 and 2003 operating revenues, respectively. It is anticipated that this customer will have significantly reduced electric usage in 2006, due to the curtailment of its operations in December 2005.

To satisfy its obligations under PURPA, Potomac Edison entered into a long-term contract to purchase capacity and energy from the AES Warrior Run PURPA generation facility through the beginning of 2030. Potomac Edison is authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run cogeneration facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market by means of the “AES Warrior Run Surcharge.” Any under-recovery or over-recovery of net costs

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is being deferred on Potomac Edison’s Consolidated Balance Sheets as deferred energy costs, pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge. Because the AES Warrior Run Surcharge represents a dollar-for-dollar recovery of net contract costs, AES Warrior Run Surcharge revenues or revenues from sales of AES Warrior Run output do not impact Potomac Edison’s net income. Effective January 1, 2005, Potomac Edison sells all of the output it purchases from the AES Warrior Run facility to a non-affiliated third party, through a competitive bidding process approved by the Maryland PSC. During 2004 and 2003, all of the output purchased from the AES Warrior Run facility was sold to AE Supply. Revenues from the AES Warrior Run contract are reflected under “Transmission services and bulk power” in the table above.

Operating Expenses

Purchased Power and Transmission:  Purchased power and transmission represents power purchases, primarily from AE Supply and qualified facilities under PURPA. Purchased power and transmission consists of the following:

(In millions)	2005		2004		2003
Other purchased power and transmission	$	564.1	$	552.2	$	547.5
From PURPA generation *		105.3		93.6		95.2
Total purchased power and transmission	$	669.4	$	645.8	$	642.7
* PURPA cost (cents per kWh)		6.8		6.7		6.6

Purchased power and transmission expense increased $23.6 million for 2005 compared to 2004 due to:

• an $11.9 million increase in other purchased power and transmission and

• an $11.7 million increase in purchased power from PURPA generation.

Other purchased power and transmission increased primarily due to a 10.8% increase in the price per MWh purchased due to power purchases by Potomac Edison at market prices to serve commercial and industrial customers. This increase in price was partially offset by reduced PLR obligations as the result of customers who chose alternative electricity generation providers.

Purchased power from PURPA generation increased as a result of an 11.5% increase in MWhs purchased from the AES Warrior Run PURPA generation facility due to increased MWhs generated during 2005 compared to 2004.

Purchased power and transmission expense increased $3.1 million for 2004 compared to 2003 due to:

• a $4.7 million increase in other purchased power and transmission expense,

• partially offset by a $1.6 million decrease in PURPA expenses.

The increase in other purchased power and transmission expense is primarily due to an increase in transmission charges, an increase in PJM administration expenses, and an increase in purchased power from affiliates. These increases resulted from higher MWhs purchased from AE Supply to service the increased residential, commercial and industrial load. The decrease in PURPA expense was primarily due to decreased MWhs purchased from the AES Warrior Run PURPA generation facility due to decreased MWhs generated during 2004 compared to 2003.

Deferred Energy Costs, Net:  Deferred energy costs, net were as follows:

(In millions)	2005			2004		2003
Deferred energy costs (benefit), net	$	(1.5	)	$	0.2	$	(1.7	)

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Deferred energy costs, net, are primarily related to the recovery of net costs associated with purchases from the AES Warrior Run PURPA generation facility and the deferral of market-based generation costs.

Beginning on January 1, 2005, Maryland commercial and industrial generation rates transitioned to market-based rates. Potomac Edison is authorized by the Maryland PSC to recover the generation component of power sold to these customers. An asset or liability is recorded on Potomac Edison’s balance sheet relative to any under-recovery or over-recovery for the generation component of costs charged to Maryland commercial and industrial customers. Deferred energy costs relate to the recovery from or payment to customers related to these generation costs.

See “Operating Revenues” above, for additional details related to AES Warrior Run deferred costs.

Operations and Maintenance:  Operations and maintenance expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:

(In millions)	2005		2004		2003
Operations and maintenance	$	104.7	$	106.2	$	116.4

Operations and maintenance expenses decreased $1.5 million for 2005 compared to 2004, primarily due to:

• a $3.0 million decrease in outside services,

• partially offset by a $2.1 million increase in vegetation control expenses.

Outside services decreased as a result of a reduction in the use of outside consultants. Vegetation control expenses increased due to an increase in contractor expenditures resulting from an increase in the size of the area covered during 2005.

Operations and maintenance expenses decreased $10.2 million for 2004 compared to 2003 due to:

• a $3.6 million decrease in insurance expense,

• a $2.7 million decrease in outside services and contract work,

• a $2.3 million decrease in salaries and wages expense and

• a $2.1 million decrease in employee benefits expense.

The decrease in insurance expense was due to a reduction in costs for potential claims alleging exposure to asbestos and lower workers’ compensation insurance expense. The decrease in contract work and outside services was a result of a decrease in the use of independent contractors and consultants. The decrease in salaries and wages expense was the result of a decrease in the number of employees. The decrease in employee benefits expense reflects a $2.9 million decrease in SERP and ELIP expenses, primarily due to costs recorded in 2003 for certain executives, and a $1.2 million decrease in disability costs, which were principally related to costs recorded in 2003.

Depreciation and Amortization:  Depreciation and amortization expenses were as follows:

(In millions)	2005		2004		2003
Depreciation and amortization	$	43.2	$	39.6	$	38.3

Depreciation and amortization expenses increased $3.6 million for 2005 compared to 2004 and $1.3 million for 2004 compared to 2003, primarily due to increased depreciation resulting from net property, plant and equipment additions.

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Taxes Other Than Income Taxes:  Taxes other than income taxes primarily includes West Virginia business and occupation taxes, payroll taxes and property taxes. Taxes other than income taxes were as follows:

(In millions)	2005		2004		2003
Taxes other than income taxes	$	35.4	$	34.2	$	38.2

Taxes other than income taxes increased $1.2 million for 2005 compared to 2004, primarily as a result of a $1.0 million increase in a certain gross receipts tax due to a rate increase.

Taxes other than income taxes decreased by $4.0 million for 2004 compared to 2003, primarily due to a $4.9 million adjustment recorded in 2003 for Maryland gross receipts tax and a $1.8 million decrease in property tax, partially offset by a $1.9 million increase in a certain gross receipts tax.

Other Income and Expenses, Net:  Other income and expenses, net, represent non-operating income and expenses before income taxes. Other income and expenses, net were as follows:

(In millions)	2005		2004		2003
Other income and expenses, net	$	7.2	$	6.7	$	21.1

Other income and expenses, net, decreased $14.4 million for 2004 compared to 2003, primarily due to the recognition of a $14.1 million gain related to the reapplication of SFAS No. 71 in 2003.

See Note 7, “Accounting for the Effects of Price Regulation,” and Note 10, “Other Income and Expenses, Net,” to Potomac Edison’s Consolidated Financial Statements for additional information.

Interest Expense:  Interest expense was as follows:

(In millions)	2005		2004		2003
Interest expense	$	27.6	$	32.3	$	31.1

Interest expense decreased $4.7 million for 2005 compared to 2004, primarily due to the November 2004 refinancing at lower interest rates of $175 million of Potomac Edison’s outstanding First Mortgage Bonds.

Interest expense increased $1.2 million for 2004 compared to 2003, primarily due to interest expense during the one-month period between the November 2004 refinancing at lower interest rates of $175 million of Potomac Edison’s outstanding First Mortgage Bonds and the December 2004 redemption of an outstanding series of first mortgage bonds, during which time both series were outstanding.

Income Tax Expense

The effective tax rates for Potomac Edison’s continuing operations were 33.5%, 47.8% and 33.7% for 2005, 2004 and 2003, respectively.

Allegheny allocates income tax expense or benefit to its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause significant fluctuations in the effective income tax rates from the statutory rates for the subsidiaries depending on the level of pre-tax profitability.

Income tax expense for 2004 was higher than the income tax expense (benefit) calculated at federal statutory tax rate, due to state income tax and the effects of utility rate-making.

See Note 5, “Income Taxes,” to Potomac Edison’s Consolidated Financial Statements for additional information.

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ALLEGHENY GENERATING COMPANY—RESULTS OF OPERATIONS

Income Summary

(In millions)	2005		2004		2003
Operating revenues	$	66.6	$	69.2	$	70.5
Operating income	$	41.9	$	43.1	$	45.1
Income before income taxes	$	34.7	$	34.7	$	32.8
Net income	$	31.1	$	27.4	$	20.8

Net income increased $3.7 million for 2005 compared to 2004. This increase was primarily due to an increase in the allocated state and federal income tax benefit pursuant to Allegheny’s consolidated tax sharing agreement.

Net income increased $6.6 million for 2004 compared to 2003, primarily due to a $4.0 million decrease in interest expense and a $4.7 million decrease in income tax expense. These amounts were partially offset by a $2.0 million decrease in operating income as a result of decreased operating revenues and increased operations and maintenance expense.

Operating Revenues:

AGC’s only operating asset is an undivided 40% interest in the Bath County, Virginia pumped-storage hydroelectric station and its connecting transmission facilities.

Pursuant to an agreement, AE Supply and Monongahela purchase all of AGC’s capacity at prices based on a “cost-of-service formula” wholesale rate schedule (the “revenue requirements”) approved by FERC. AE Supply and Monongahela purchase power capacity from AGC on a proportional basis, based on their respective equity ownership of AGC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment.

Operating revenues were as follows:

(In millions)	2005		2004		2003
Operating revenues	$	66.6	$	69.2	$	70.5

Operating revenues decreased $2.6 million for 2005 compared to 2004, primarily as a result of decreased expenditure recoveries on operations and maintenance expenditures.

Operating revenues decreased $1.3 million for 2004 compared to 2003. This decrease was primarily due to a decrease in revenue received from AE Supply and Monongahela resulting from a reduction in the return on debt component. This reduction was attributable to a decrease in debt as a result of repayments of affiliated debt in 2004 and other long-term debt repayments in 2003.

Operating Expenses:

Operations and Maintenance:  Operations and maintenance expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:

(In millions)	2005		2004		2003
Operations and maintenance	$	4.6	$	6.2	$	5.2

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Operations and maintenance expenses decreased $1.6 million for 2005 compared to 2004, and increased $1.0 million for 2004 compared to 2003 due to a charge recorded during 2004 to write-down inventory.

Interest Expense:  Interest expense was as follows:

(In millions)	2005		2004		2003
Interest expense	$	7.4	$	8.5	$	12.5

Interest expense decreased $1.1 million for 2005 compared to 2004, primarily due to $15.0 million in affiliated long-term debt repayments during 2005.

Interest expense decreased $4.0 million for 2004 compared to 2003, primarily due to $15.0 million in affiliated long-term debt repayments during 2004 and repayments of other long-term debt in 2003.

Income Tax Expense

The effective tax rates for AGC’s continuing operations were 10.3%, 21.0% and 36.5% for 2005, 2004 and 2003, respectively.

Allegheny allocates income tax expense or benefit to its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause significant fluctuations in the effective income tax rates from the statutory rates for the subsidiaries depending on the level of pre-tax profitability.

The effective income tax rates differ from the statutory tax rates primarily due to the effect of state income taxes, benefits derived from the allocation of consolidated tax savings to AGC, the amortization of deferred investment tax credits and depreciation.

See Note 4, “Income Taxes,” to AGC’s Financial Statements for additional information.

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FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES

Liquidity and Capital Requirements

To meet cash needs for operating expenses, the payment of interest, retirement of debt, acquisitions and construction programs, Allegheny has historically used internally generated funds (net cash provided by operations less common and preferred dividends) and external financings, including the sale of common and preferred stock, debt instruments, installment loans and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions and Allegheny’s cash needs and capital structure objectives. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and upon market conditions.

At December 31, 2005 and 2004, AE had cash and cash equivalents of $262.2 million and $189.5 million, respectively.

Restricted cash balances were $21.6 million and $228.9 million at December 31, 2005 and 2004, respectively. These restricted cash balances include transition charges collected by West Penn and collateral deposits posted as security related to certain contractual obligations. The December 31, 2004 balance also includes $198.3 million of the proceeds from the sale of the Lincoln generating facility and the assignment of the new OVEC power agreement to become effective in March 2006.

AE had collateral deposits of $147.8 million and $88.7 million at December 31, 2005 and 2004, respectively. These deposits are posted as security with counterparties for various transactions. These amounts are included in “Current assets” on the Consolidated Balance Sheets. Additionally, $0.2 million of collateral deposits outstanding at December 31, 2004 are included in “Assets held for sale” on the Consolidated Balance Sheets.

AE also had posted cash collateral of $41.3 million and $39.1 million at December 31, 2005 and 2004, respectively, as security for surety bonds issued by a third party. These funds are invested in a temporary investment fund and are included in the caption “Other” within the “Investments and Other Assets” section of the Consolidated Balance Sheets.

At December 31, 2005, $263.5 million was available under AE’s revolving credit facility. In addition, subject to certain limitations, AE Supply may borrow, or request letters of credit for, up to $50 million directly under the revolving credit facility. AE is permitted to request letters of credit under its revolving credit facility in an amount not in excess of $125 million on behalf of AE Supply and its subsidiaries.

Allegheny’s consolidated capital structure, including short-term debt and liabilities associated with assets held for sale and excluding minority interest, as of December 31, 2005 and 2004, was as follows:

	2005			2004
(In millions)	Amount		%	Amount		%
Debt	$	4,101.7	70.5	$	5,012.6	77.8
Common equity		1,695.3	29.1		1,353.8	21.0
Preferred equity		24.0	0.4		74.0	1.2
Total	$	5,821.0	100.0	$	6,440.4	100.0

2005 Activity

In April 2005, the holders of $295.0 million of the outstanding $300.0 million in Trust Preferred Securities issued by Capital Trust accepted AE and Capital Trust’s tender offer and consent solicitation. Under the terms of the offer, for each $1,000 in liquidation amount of Trust Preferred Securities tendered, a holder received 83.33

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shares of AE common stock and $160 in cash. On April 22, 2005, AE issued an aggregate of 24.6 million shares of its common stock and $47.2 million in cash to the holders of the tendered Trust Preferred Securities. The $47.2 million cash payment was expensed during the second quarter of 2005. In addition, AE received the required consents from holders of the Trust Preferred Securities for amendments to the indenture governing AE’s 11 ⁷/8% Notes due 2008. The holder of the remaining $5.0 million in liquidation amount of Trust Preferred Securities converted its Trust Preferred Securities into 416,650 shares of AE common stock on May 3, 2005.

On June 16, 2005, AE and AE Supply (together, the “Borrowers”) entered into a new $700 million credit facility (the “New AE Credit Facility”) comprised of a $400 million senior unsecured revolving credit facility (the “Revolving Facility”) and a $300 million senior unsecured term loan (the “Term Facility”). The Revolving Facility (a) refinanced the aggregate principal amount of approximately $122 million outstanding under AE’s prior credit facility, (b) continued letters of credit issued under AE’s prior credit facility and (c) provided working capital and letters of credit for AE and, subject to certain limitations, its subsidiaries. The lenders under the Revolving Facility are required to make revolving credit loans to, and issue letters of credit at the request of, AE. In addition, subject to certain limitations, AE Supply may borrow, or request letters of credit for, up to $50 million directly under the Revolving Facility. AE is permitted to request letters of credit in an amount not in excess of $125 million on behalf of AE Supply and its subsidiaries. The Revolving Facility matures June 16, 2010.

On August 1, 2005, AE used the proceeds of the Term Facility to refinance the aggregate principal outstanding amount under AE’s 7.75% Notes due August 1, 2005. AE must repay the principal amount borrowed under the Term Facility in consecutive quarterly installments equal to 0.25% of the aggregate principal amount initially advanced to AE under the Term Facility, with the balance due in full at maturity on June 16, 2010. AE may not re-borrow any part of the Term Facility that it repays or prepays.

Loans under the New AE Credit Facility bear interest, depending on the type of loan requested by the Borrowers, at a rate equal to either (i) the higher of the rate announced publicly by Citibank in New York, from time to time, as Citibank’s base rate or 0.50% above the Federal Funds Rate (as defined in the Credit Agreement) (the “Base Rate”), plus the applicable margin, which is between 1.50% and 0.50% for Base Rate loans, or (ii) the Eurodollar Rate (as defined in the Credit Agreement), plus the applicable margin, which is between 2.50% and 1.50% for Eurodollar Rate-based loans. The applicable margin for LIBOR borrowings was 2.00% at December 31, 2005. On January 18, 2006, the margin for LIBOR borrowings was reduced to 1.50% as a result of increased S&P credit ratings on certain of AE’s debt. With respect to each letter of credit, the relevant Borrower is required to pay to the Administrative Agent a letter of credit fee equal to the applicable margin, which ranges from 2.50% to 1.50%, times the daily maximum amount available to be drawn under such letter of credit. In each case of a Base Rate loan, Eurodollar Rate loan or letter of credit, the applicable margin varies depending upon Standard & Poor’s (“S&P”) and Moody’s Investors Service, Inc.’s (“Moody’s”) ratings of certain of AE’s public debt. The Borrowers’ ability to request and maintain Eurodollar Rate loans is subject to certain limitations.

On July 21, 2005, AE Supply and certain of its subsidiaries entered into a secured term loan facility (the “New AE Supply Term Loan”) of $1.07 billion. The New AE Supply Term Loan matures in 2011 and has an initial interest rate equal to LIBOR plus 1.75%. On January 18, 2006, the margin for LIBOR borrowings was reduced to 1.50% as a result of increased S&P credit ratings on certain of AE Supply’s debt. Proceeds from the New AE Supply Term Loan were used, in part, to refinance approximately $738 million outstanding under the prior AE Supply loan.

Proceeds from the New AE Supply Term Loan were also used on August 22, 2005 to redeem AE Supply’s 10.25% Senior Notes due 2007, which had a principal amount outstanding of approximately $331 million. Also on August 22, 2005, AE Supply used cash on hand to redeem its 13.0% Senior Notes due 2007, which had a principal amount outstanding of approximately $35 million. AE Supply expensed premiums and costs associated with the redemption of its 10.25% Senior Notes and 13.0% Senior Notes in the amount of $32.6 million during the three months ended September 30, 2005.

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On August 15, 2005, Potomac Edison issued $145 million of 5.125% First Mortgage Bonds due 2015. Approximately $143 million of the proceeds, together with available cash, was used to redeem Potomac Edison’s $65 million of outstanding 7.75% First Mortgage Bonds due 2025 and its $80 million of outstanding 7.625% First Mortgage Bonds due 2025.

On September 27, 2005, WPP Funding, LLC, a subsidiary of West Penn issued $115.0 million of 4.46% Transition Bonds, Series 2005-A with an expected maturity of June 2010. These bonds securitize an intangible right to receive a revenue stream from rate payers. Interest on these bonds will accrue and be added to the principal amount of the bonds until the first scheduled interest payment date following final payment of the Transition Bonds, Series 1999-A issued by West Penn Funding LLC, which is expected to occur in June 2008. Thereafter, interest on these bonds will be paid quarterly.

On October 17, 2005, Monongahela issued $70.0 million of 5.375% First Mortgage Bonds due 2015. Monongahela utilized the proceeds and available cash to redeem $70.0 million of its 7 ⁵/8% First Mortgage Bonds due 2025 on November 16, 2005.

On October 31, 2005, Monongahela fully redeemed its $50.0 million of outstanding $7.73, Series L ($100 par value) Cumulative Preferred Stock. Monongahela paid accrued and unpaid dividends of approximately $1 million.

Allegheny made various other debt payments during 2005. See Note 2, “Capitalization,” to the Consolidated Financial Statements for additional information.

The aggregate amount of debt issued, by entity, during 2005 is shown below:

(In millions)	AE		AE Supply		Monongahela		Potomac Edison		West Penn		Total
Prior Credit Facility	$	47.0	$	—	$	—	$	—	$	—	$	47.0
New AE Credit Facility		422.0		—		—		—		—		422.0
New AE Supply Term Loan		—		1,069.0		—		—		—		1,069.0
First Mortgage Bonds		—		—		70.0		145.0		—		215.0
Transition Bonds		—		—		—		—		116.3		116.3
Total	$	469.0	$	1,069.0	$	70.0	$	145.0	$	116.3	$	1,869.3

Redemptions of debt, by entity, during 2005 are listed below:

(In millions)	AE		AE Supply		Monongahela		Potomac Edison		West Penn		Total
Convertible Preferred Securities	$	300.0	$	—	$	—	$	—	$	—	$	300.0
Prior Credit Facility		147.0		—		—		—		—		147.0
New AE Credit Facility		223.0		—		—		—		—		223.0
Medium-Term Notes		300.0		380.0		—		—		—		680.0
Prior AE Supply Loan		—		982.1		—		—		—		982.1
New AE Supply Term Loan		—		80.0		—		—		—		80.0
First Mortgage Bonds		—		—		70.0		145.0		—		215.0
Transition Bonds		—		—		—		—		73.0		73.0
Total	$	970.0	$	1,442.1	$	70.0	$	145.0	$	73.0	$	2,700.1
Debt associated with assets held for sale:
Other Notes	$	—	$	—	$	86.7	$	—	$	—	$	86.7

Allegheny may seek to engage in further financings to support capital expenditures and to maintain working capital. In addition, Allegheny’s asset optimization, fuel procurement and risk management activities require direct and indirect credit support.

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2004 Activity

On March 8, 2004, AE and AE Supply refinanced approximately $1.7 billion of long-term debt with new borrowings in an aggregate amount of $1.55 billion. These new borrowings consisted of a $750 million secured Term B Loan and a $500 million secured Term C Loan (collectively, the “AE Supply Loans”) at AE Supply and unsecured revolving and term loan facilities at AE in the aggregate amount of $300 million (the “AE Facility” and together with the AE Supply Loans, the “Loan Facilities”). See Note 2, “Capitalization,” for additional information concerning the March 8, 2004 refinancing and the debt covenants contained in the Loan Facilities. As discussed below, the AE Supply Loans were refinanced in October 2004.

On June 9, 2004, Monongahela issued $120 million of 6.70% First Mortgage Bonds, which mature on June 15, 2014. The net proceeds of the bond issuance were used to repay Monongahela’s $53.6 million short-term bridge loan in June 2004 and to fund the July 2004 redemption of $40 million of 8.375% First Mortgage Bonds due 2022 and $25 million of 7.25% First Mortgage Bonds due 2007. Interest on the 6.70% First Mortgage Bonds is payable semi-annually in arrears on each June 15 and December 15, commencing December 15, 2004. The bonds are redeemable at Monongahela’s option and rank equally in right of payment with its existing or future first mortgage bonds.

On October 5, 2004, Allegheny sold 10 million shares of its common stock at a price of $15.15 per share directly to institutional investors in a private placement. The proceeds of the sale, and cash on hand, were used to reduce $200 million of debt at AE Supply.

On October 28, 2004, AE Supply refinanced the remaining $1.04 billion outstanding under the AE Supply Loans. In connection with the refinancing of the AE Supply Loans, the Term B Loan and the Term C Loan were consolidated into one loan (the “Refinanced AE Supply Loan”). The Refinanced AE Supply Loan bore interest at a rate per annum equal to LIBOR plus 2.75%. Following the repayment of $200 million of the outstanding balance of the Refinanced AE Supply Loan on January 14, 2005, the per annum interest rate on the Refinanced AE Supply Loan was reduced to LIBOR plus 2.50%. See Note 2, “Capitalization,” to the Consolidated Financial Statements for additional information regarding the October 2004 refinancing and the debt covenants contained in the Refinanced AE Supply Loan.

On November 22, 2004, Potomac Edison issued $175 million of 5.35% First Mortgage Bonds, which mature on November 15, 2014. The net proceeds of the bond issuance were used to fund the December 2004 redemption of $55.0 million of 8.0% First Mortgage Bonds due 2022, $45.0 million of 7.75% First Mortgage Bonds due 2023 and $75.0 million of 8.0% First Mortgage Bonds due 2024. Interest on the 5.35% First Mortgage Bonds is payable semi-annually in arrears on each May 15 and November 15, commencing May 15, 2005. The bonds are redeemable at Potomac Edison’s option and rank equally in right of payment with its existing or future unsubordinated indebtedness.

The aggregate amount of debt issued, by entity, during 2004 is shown below:

(In millions)	AE		AE Supply		Monongahela		Potomac Edison		Total
AE Supply Loans	$	—	$	1,250.0	$	—	$	—	$	1,250.0
Refinanced AE Supply Loan		—		1,043.7		—		—		1,043.7
AE Facility		225.0		—		—		—		225.0
First Mortgage Bonds		—		—		120.0		175.0		295.0
Borrowing Facilities		—		28.3		—		—		28.3
Total	$	225.0	$	2,322.0	$	120.0	$	175.0	$	2,842.0

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Redemptions of debt, by entity, during 2004 are listed below:

(In millions)	AE		AE Supply		Monongahela		Potomac Edison		West Penn		Total
Borrowing Facilities	$	257.0	$	1,407.8	$	—	$	—	$	—	$	1,664.8
AE Supply Loans		—		1,250.0		—		—		—		1,250.0
Refinanced AE Supply Loan		—		61.6		—		—		—		61.6
First Mortgage Bonds		—		—		65.0		175.0		—		240.0
AE Facility		125.0		—		—		—		—		125.0
Medium-Term Notes		—		—		—		—		84.0		84.0
Transition Bonds		—		—		—		—		73.7		73.7
Short-term Debt		—		—		53.6		—		—		53.6
Total	$	382.0	$	2,719.4	$	118.6	$	175.0	$	157.7	$	3,552.7

Certain amounts have been excluded from the tables above, because they relate to liabilities associated with assets held for sale as of December 31, 2004. During 2004, there were no issuances and $3.3 million of redemptions of “other notes” related to liabilities associated with assets held for sale.

2005 Asset Sales

On December 31, 2005, Monongahela completed the sale of its Ohio electric T&D assets to Columbus Southern for net cash proceeds of $51.8 million. The purchase price for the assets was the net book value at the time of closing, plus $10.0 million, less certain property taxes. The sale included a power sales agreement under which Monongahela will provide power to Columbus Southern for the Ohio retail customer base from the time of closing through May 31, 2007 at $45 per megawatt-hour, which is projected to be less than the projected market price for power. During 2005, Monongahela recorded a loss on the sale of $29.3 million based on the estimated value, at December 31, 2005, of Monongahela’s power sales agreement with Columbus Southern to provide power at below-market prices from December 31, 2005 through May 31, 2007, partially offset by approximately $8.0 million, representing the purchase price less net book value of the assets at December 31, 2005 and approximately $2.0 million in expenses associated with the sale.

On September 30, 2005, Monongahela completed the sale of its natural gas operations in West Virginia to Mountaineer Gas Holdings Limited Partnership, a partnership composed of IGS Utilities LLC, IGS Holdings LLC and affiliates of ArcLight Capital Partners, LLC, for approximately $161.0 million in cash and the assumption of approximately $87.0 million of long-term debt. The assets sold included all of the issued and outstanding capital stock of Mountaineer Gas and certain other assets related to the West Virginia natural gas operations, subject to certain post closing adjustments.

On August 12, 2005, AE Supply and its subsidiaries, Allegheny Energy Supply Wheatland Generating Facility, LLC and Lake Acquisition Company, LLC completed the sale of certain assets relating to AE Supply’s Wheatland generating facility (the “Wheatland Assets”) to PSI Energy, Inc. and The Cincinnati Gas & Electric Company for approximately $100 million and the assumption of certain liabilities related to the Wheatland Assets.

During May 2005, Potomac Edison completed the sale of its Hagerstown, Maryland property for $10.6 million in net cash proceeds.

Land Sales:  During 2005, AE Supply and West Penn and its subsidiaries completed land sales for aggregate proceeds of $2.6 million.

See Note 3, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements for information relating to asset sales.

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2004 Asset Sales

During the third quarter of 2004, AE Supply recorded a charge against earnings to write-down its investment in the Lincoln generating facility to the expected net proceeds from the sale. The write-down resulted in a charge against earnings of $209.4 million, before income taxes ($129.2 million, net of income taxes). This write-down is included in “Loss from discontinued operations, net of tax” in the Consolidated Statements of Operations. The Lincoln generating facility is a component of Allegheny’s Generation and Marketing segment. On December 15, 2004, AE Supply sold the Lincoln generating facility, together with an associated tolling agreement, to an affiliate of ArcLight Capital Partners, LLC. The sale resulted in a reduction of the loss by $1.8 million, before income taxes ($1.1 million, net of income taxes), which is recorded in “Loss from discontinued operations, net of tax” on the Consolidated Statements of Operations. Cash proceeds from the sale were $175.0 million, which were used to reduce debt in December 2004 and January 2005.

On December 31, 2004, AE sold a 9% equity interest in OVEC to Buckeye. In addition, AE Supply assigned to Buckeye all of its rights and obligations under a new OVEC inter-company power agreement that is expected to become effective on March 13, 2006. However, AE Supply will retain its rights under the current agreement to 9% of the power from the OVEC electric generation facilities through March 12, 2006. The sale resulted in a gain of $94.8 million, before income taxes ($60.0 million, net of income taxes), which is recorded in “Gain on sale of OVEC power agreement and shares” on the Consolidated Statements of Operations. AE recorded a gain of $6.2 million, before income taxes ($4.0 million, net of income taxes) and AE Supply recorded a gain of $88.6 million, before income taxes ($56.0 million, net of income taxes). Cash proceeds from the sale were $102.0 million, of which $6.0 million is expected to be received in April 2006 upon the fulfillment of certain post-closing obligations. The remaining $96.0 million in proceeds was used to reduce debt in the first quarter of 2005.

Land Sales:  In 2004, West Penn and its subsidiaries completed land sales for aggregate proceeds of $11.1 million.

Anticipated Asset Sales

Allegheny decided to sell certain non-core assets and has classified these assets as held for sale. See Note 3, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements for additional information relating to these assets.

Dividends

AE did not pay dividends on its common stock in 2005 or 2004. Monongahela did not pay dividends during 2005 on its common stock and paid dividends on its common stock of approximately $33.2 million in 2004. Monongahela paid dividends on its preferred stock of approximately $4.1 million and approximately $5.0 million in 2005 and 2004, respectively. Potomac Edison paid dividends on its common stock of approximately $63.1 million in 2005 and approximately $43.0 million in 2004. AGC paid aggregate dividends on its common stock to AE Supply and Monongahela of approximately $21.8 million in 2005 and approximately $12.5 million in 2004.

Return of Capital

During October 2005, AE received $80.0 million representing a return of capital from Monongahela using a portion of the cash proceeds from the sale of its West Virginia natural gas operations.

Other Matters Concerning Liquidity and Capital Requirements

On September 19, 2005, AE entered into a Professional Services Agreement, under which, on November 1, 2005, the Service Provider assumed responsibility for many of Allegheny’s information technology functions and agreed to assist Allegheny with the installation of an enterprise resource planning system. Unless extended by

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AE, the Professional Services Agreement will expire on December 31, 2012. Expected cash payments relating to the Professional Services Agreement are included in the contractual obligations and commitments table, below.

Allegheny makes contributions to its pension plan in order to meet at least the minimum required funding amount under ERISA. The minimum required funding contribution for 2006 is approximately $16 million. Allegheny also currently anticipates contributing a total amount in 2006 ranging from $16 million to $18 million, to fund postretirement benefits other than pensions.

Allegheny estimates that its capital expenditures for 2006 and 2007 will be approximately $430.0 million and $644.0 million, respectively. These estimates include expenditures of approximately $156.0 million and $334.0 million, respectively, for environmental control technology.

See Note 23, “Commitments and Contingencies” to the Consolidated Financial Statements for additional information.

Allegheny has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel agreements and other contracts. The table below summarizes the payments due by period for these obligations and commitments as of December 31, 2005. The table below does not include expected pension contributions described above and in Note 10, “Pension Benefits and Postretirement Benefits other than Pensions,” contingent liabilities, liabilities associated with assets held for sale and contractual commitments that were accounted for under fair value accounting. For more information regarding fair value accounting, see “Allegheny Energy, Inc.—Discussion of Segment Results of Operations—AE’s Generation and Marketing Segment Results.”

Allegheny

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2006		Payments from January 1, 2007 to December 31, 2008		Payments from January 1, 2009 to December 31, 2010		Payments from January 1, 2011 and beyond		Total
Long-term debt (a)	$	476.0	$	280.4	$	406.3	$	2,939.0	$	4,101.7
Interest on long-term debt (c)		253.4		458.5		436.5		437.0		1,585.4
Interest rate swap obligations		6.1		12.2		12.2		2.2		32.7
Capital lease obligations (b)		10.3		13.0		7.1		1.5		31.9
Operating lease obligations (b)		5.0		6.9		6.6		19.5		38.0
PURPA purchased power		208.4		426.7		441.5		3,711.9		4,788.5
Fuel purchase and transportation commitments		652.3		933.0		574.9		2,200.0		4,360.2
Other purchase obligation (d)		34.7		53.3		50.4		44.9		183.3
Total	$	1,646.2	$	2,184.0	$	1,935.5	$	9,356.0	$	15,121.7

(a) Does not include debt associated with unamortized debt expense, discounts, premiums, payments made subsequent to December 31, 2005 and anticipated debt repayments.

(b) Does not include amounts associated with assets held for sale.

(c) Amounts are based on interest rates as of December 31, 2005 and do not reflect any payments made subsequent to December 31, 2005 and any anticipated future debt repayments or interest rate changes. Total interest on long-term debt includes $13.6 million in interest that will accrue and be added to the principal amount of West Penn’s $115.0 million of 4.46% Transaction Bonds, Series 2005-A.

(d) Amounts represent Allegheny’s expected cash payments for outsourcing of certain information technology functions and assistance with the installation of an enterprise resource planning system.

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Monongahela

Monongahela estimates that its capital expenditures for 2006 and 2007 will be approximately $101.0 million and $141.0 million, respectively. These estimates include expenditures of approximately $38.0 million and $81.0 million, respectively, for environmental control technology. See Note 16, “Commitments and Contingencies,” to Monongahela’s Consolidated Financial Statements for additional information.

Monongahela has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel agreements and other contracts. The table below summarizes the payments due by period for these obligations and commitments as of December 31, 2005. The table below does not include expected pension contributions and contingent liabilities.

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2006		Payments from January 1, 2007 to December 31, 2008		Payments from January 1, 2009 to December 31, 2010		Payments from January 1, 2011 and beyond		Total
Long-term debt (a)	$	300.0	$	15.5	$	110.0	$	260.2	$	685.7
Interest on long-term debt (b)		35.4		47.6		39.3		76.0		198.3
Capital lease obligations		4.2		5.1		2.7		0.5		12.5
Operating lease obligations		0.5		0.3		0.1		—		0.9
PURPA purchased power		58.1		117.0		120.2		1,162.7		1,458.0
Fuel purchase and transportation commitments		134.2		197.5		121.7		467.8		921.2
Total	$	532.4	$	383.0	$	394.0	$	1,967.2	$	3,276.6

(a) Does not include debt associated with unamortized debt expense, discounts, premiums, payments made subsequent to December 31, 2005 and anticipated debt repayments.

(b) Amounts are based on interest rates as of December 31, 2005 and do not reflect any payments made subsequent to December 31, 2005 and any anticipated future debt repayments or interest rate changes.

Potomac Edison

Potomac Edison estimates that its capital expenditures for 2006 and 2007 will be approximately $81.0 million and $98.0 million, respectively. See Note 14, “Commitments and Contingencies,” to Potomac Edison’s Consolidated Financial Statements for additional information.

Potomac Edison has various obligations and commitments to make future cash payments under debt instruments, lease arrangements and other contracts. The table below summarizes the payments due by period for these obligations and commitments as of December 31, 2005. The table below does not include expected pension contributions and contingent liabilities.

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2006		Payments from January 1, 2007 to December 31, 2008		Payments from January 1, 2009 to December 31, 2010		Payments from January 1, 2011 and beyond		Total
Long-term debt (a)	$	100.0	$	—	$	—	$	320.0	$	420.0
Interest on long-term debt (b)		21.0		33.6		33.6		70.6		158.8
Capital lease obligations		2.5		3.7		2.2		0.5		8.9
Operating lease obligations		0.3		0.1		—		—		0.4
PURPA purchased power		99.4		203.1		208.6		2,126.9		2,638.0
Total	$	223.2	$	240.5	$	244.4	$	2,518.0	$	3,226.1

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(a) Does not include debt associated with unamortized debt expense, discounts, premiums, payments made subsequent to December 31, 2005 and anticipated debt repayments.

(b) Amounts are based on interest rates as of December 31, 2005 and do not reflect any payments made subsequent to December 31, 2005 and any anticipated future debt repayments or interest rate changes.

AGC

AGC estimates that its capital expenditures for 2006 and 2007 will be approximately $10.0 million and $6.0 million, respectively. See Note 10, “Commitments and Contingencies,” to AGC’s Financial Statements for additional information.

AGC has various obligations and commitments to make future cash payments under debt instruments. The table below summarizes the payments due by period for these obligations and commitments as of December 31, 2005. The table below does not include expected pension contributions and contingent liabilities.

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2006		Payments from January 1, 2007 to December 31, 2008		Payments from January 1, 2009 to December 31, 2010		Payments from January 1, 2011 and beyond		Total
Long-term debt (a)	$	—	$	—	$	—	$	100.0	$	100.0
Interest on long-term debt (b)		6.9		13.8		13.8		87.0		121.5
Total	$	6.9	$	13.8	$	13.8	$	187.0	$	221.5

(a) Does not include debt associated with unamortized debt expense, discounts, premiums, payments made subsequent to December 31, 2005 and anticipated debt repayments.

(b) Amounts are based on interest rates as of December 31, 2005 and do not reflect any payments made subsequent to December 31, 2005 and any anticipated future debt repayments or interest rate changes.

AE Supply

AE Supply estimates that its capital expenditures for 2006 and 2007 will be approximately $165.0 million and $315.0 million, respectively. These estimates include expenditures of approximately $118.0 million and $253.0 million, respectively, for environmental control technology.

AE Supply has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel agreements and other contracts. The table below summarizes the payments due by period for these obligations and commitments as of December 31, 2005. The table below does not include expected pension contributions, contingent liabilities, liabilities associated with assets held for sale and contractual commitments that were accounted for under fair value accounting.

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2006		Payments from January 1, 2007 to December 31, 2008		Payments from January 1, 2009 to December 31, 2010		Payments from January 1, 2011 and beyond		Total
Long-term debt (a)	$	—	$	109.0	$	21.4	$	2,291.7	$	2,422.1
Interest on long-term debt (b)		167.0		327.6		322.0		282.2		1,098.8
Interest rate swap obligations		6.1		12.2		12.2		2.2		32.7
Capital lease obligations		0.2		—		—		—		0.2
Operating lease obligations		3.7		6.4		6.7		19.5		36.3
Fuel purchase and transportation commitments		518.1		735.5		453.2		1,732.2		3,439.0
Total	$	695.1	$	1,190.7	$	815.5	$	4,327.8	$	7,029.1

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(a) Does not include unamortized debt expense, discounts, premiums, payments made subsequent to December 31, 2005 and anticipated debt repayments.

(b) Amounts are based on interest rates as of December 31, 2005 and do not reflect any payments made subsequent to December 31, 2005 and any anticipated future debt repayments or interest rate changes.

West Penn

West Penn estimates that its capital expenditures for 2006 and 2007 will be approximately $72.0 million and $83.0 million, respectively.

West Penn has various obligations and commitments to make future cash payments under debt instruments, lease arrangements and other contracts. The table below summarizes the payments due by period for these obligations and commitments as of December 31, 2005. The table below does not include expected pension contributions and contingent liabilities.

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2006		Payments from January 1, 2007 to December 31, 2008		Payments from January 1, 2009 to December 31, 2010		Payments from January 1, 2011 and beyond		Total
Long-term debt (a)	$	75.8	$	154.7	$	85.8	$	80.0	$	396.3
Interest on long-term debt (b)		17.2		24.6		23.7		8.2		73.7
Capital lease obligations		3.4		4.2		2.3		0.4		10.3
Operating lease obligations		0.4		0.1		—		—		0.5
PURPA purchased power		50.9		106.5		112.7		422.4		692.5
Total	$	147.7	$	290.1	$	224.5	$	511.0	$	1,173.3

(a) Does not include debt associated with unamortized debt expense, discounts, premiums, payments made subsequent to December 31, 2005 and anticipated debt repayments.

(b) Amounts are based on interest rates as of December 31, 2005 and do not reflect any payments made subsequent to December 31, 2005 and any anticipated future debt repayments or interest rate changes. Total interest on long-term debt includes $13.6 million in interest that will accrue and be added to the principal amount of West Penn’s $115.0 million of 4.46% Transaction Bonds, Series 2005-A.

Letters of Credit and Credit Facility Availability

Allegheny had $136.5 million in letters of credit outstanding at December 31, 2005 under the Revolving Facility. Of this amount, a letter of credit for $125.0 million that expires in June 2006 was issued on September 23, 2005 on behalf of Allegheny as collateral to stay enforcement of the judgment in Allegheny’s litigation against Merrill Lynch while an appeal is pending, and letters of credit for $9.5 million and $2.0 million that expire in July 2006 and September 2006, respectively, were issued on behalf of Allegheny Energy Solutions, Inc. AE Supply also had a $1.6 million letter of credit outstanding that is collateralized by cash and was not issued under AE’s revolving facility. The $1.6 million letter of credit expired in February 2006 and was replaced with a $2.1 million letter of credit. The $2.1 million letter of credit is collateralized by cash, is not issued under AE’s revolving facility and expires in February 2007. These letters of credit are not recorded on Allegheny’s Consolidated Balance Sheets.

At December 31, 2005, $263.5 million was available to Allegheny under the Revolving Facility. In addition, subject to certain limitations, AE Supply may borrow, or request letters of credit for, up to $50 million directly under the Revolving Facility. AE is permitted to request letters of credit in an amount not in excess of $125 million on behalf of AE Supply and its subsidiaries.

Allegheny has agreed to maintain $35 million of availability under the Revolving Facility to stay enforcement of the judgment in its litigation against Merrill Lynch while an appeal is pending.

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Off-Balance Sheet Arrangements

None of the registrants has any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on their financial condition, revenues, expenses, results of operation, liquidity, capital expenditures or capital resources.

Cash Flows

Allegheny

Allegheny’s cash flows from operating activities primarily result from the sale of electricity. Future cash flows will be affected by, among other things, the impact that the economy, weather, customer choice and future regulatory proceedings have on revenues, future demand and market prices for energy, as well as Allegheny’s ability to produce and supply its customers with power at competitive prices.

Operating Activities:    Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation and amortization expense is a significant component of cash flows from operating activities.

Cash flows provided by operating activities for the year ended December 31, 2005 were $486.1 million, consisting of discontinued operations and non-cash charges of $307.8 million, changes in certain assets and liabilities of $115.2 million and net income of $63.1 million. Cash flows provided by operating activities for the year ended December 31, 2004 were $523.7 million, consisting of discontinued operations and non-cash charges of $797.5 million and changes in certain assets and liabilities of $36.8 million, partially offset by a net loss of $310.6 million.

Significant cash flows related to operating activities for the year ended December 31, 2005 included $89.1 million in payments to Allegheny’s pension and other postretirement benefit plans, primarily as a result of contributions made to satisfy the funding requirements of these benefit plans, $47.2 million in payments to the holders of the 11 ⁷/8% Trust Preferred Securities under the terms of the tender offer and consent solicitation, $29.5 million in payments to the remaining holders of AE Supply’s 10.25% and 13.0% Senior Notes and the cash receipt of $11.2 million from a former trading executive’s forfeited assets.

Significant cash flows related to operating activities for the year ended December 31, 2004 included $88.6 million in net proceeds related to the 2004 sale of the OVEC tolling agreement, $70.8 million in proceeds related to the 2003 sale of the CDWR contract and related hedges to J. Aron & Company as a result of the exit from Western U.S. energy markets, $55.8 million in payments to Allegheny’s pension and other postretirement benefit plans, primarily as a result of contributions made to satisfy the funding requirements of these benefits plans, and $28.0 million in final scheduled payments in connection with the termination of the tolling agreement with Williams Energy and Marketing Company.

The changes in certain assets and liabilities for the year ended December 31, 2005 resulted in an increase in operating cash flows of $115.2 million. Operating cash flows were provided primarily by a $112.8 million change in taxes receivable/accrued, net, primarily as a result of timing differences associated with the payment of certain tax obligations, a $75.1 million increase in accounts payable, primarily as a result of timing differences associated with the payment of certain obligations, and a $34.5 million increase in accrued interest, primarily as a result of interest expense accrued for the Merrill Lynch litigation summary judgment. These amounts were partially offset by cash flows used for operating activities primarily as a result of a $59.1 million increase in collateral deposits, primarily due to the requirements of various contracts, and a $48.3 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues.

The changes in certain assets and liabilities for the year ended December 31, 2004 resulted in an increase in operating cash flows of $36.8 million. Operating cash flows were provided primarily by a $97.6 million change in taxes receivable/accrued, net, primarily as a result of timing differences associated with the payment of certain

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tax obligations, a $26.9 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, and a $17.7 million change in other current liabilities. These amounts were partially offset by cash flows used for operating activities primarily as a result of a $37.5 million increase in collateral deposits, primarily due to the requirements of various contracts, $27.6 million decrease in accounts payable, primarily as a result of timing differences associated with the payment of certain obligations, a $26.6 million change in other liabilities and a $10.3 million increase in materials, supplies and fuel.

Investing Activities:    Cash flows provided by investing activities for the year ended December 31, 2005 were $191.5 million. Cash flows used in investing activities for the year ended December 31, 2004 were $261.9 million.

Significant cash flows provided by investing activities for the year ended December 31, 2005 included $226.8 million in net cash provided by investing activities of discontinued operations, primarily as a result of the sale of the West Virginia natural gas operations and the AE Supply Wheatland Generating Facility, a $207.3 million decrease in restricted funds, primarily due to the release of the proceeds related to the 2004 sales of OVEC and the Lincoln Generating Facility and $66.5 million in proceeds from the sale of assets, primarily as a result of the sale of the Ohio T&D assets. These amounts were partially offset by $306.5 million in capital expenditures.

Significant cash flows used in investing activities for the year ended December 31, 2004 included $265.6 million in capital expenditures and $183.8 million increase in restricted funds, primarily due to the requirement that the proceeds received from the 2004 sales of OVEC and the Lincoln Generating Facility be used to repay debt. These amounts were partially offset by $161.4 million in net cash provided by investing activities of discontinued operations, primarily as a result of the sale of the Lincoln Generating Facility and $24.0 million in proceeds from the sale of assets, primarily as a result of the sale of its 9% equity investment in OVEC and various parcels of land.

Financing Activities:    Cash flows used in financing activities for the year ended December 31, 2005 and 2004 were $604.9 million and $600.9 million, respectively.

Significant cash flows used in financing activities for the year ended December 31, 2005 included $2,406.9 million in payments for the retirement of long-term debt, primarily due to the June 16, 2005 refinancing of AE’s Prior Credit Facility and Medium-Term Notes, the July 21, 2005 refinancing of the Prior AE Supply loan and Medium-Term Notes, and the August 15, 2005 and October 17, 2005 refinancings of outstanding First Mortgage Bonds. This amount was partially offset by $1,849.1 million (net of $18.9 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, primarily related to the previously mentioned refinancings and the issuance of $115.0 million in Transition Bonds.

Significant cash flows used in financing activities for the year ended December 31, 2004 included $3,506.0 million in payments for the retirement of long-term debt, primarily due to the March 8, 2004 refinancing of the Borrowing Facilities, the June 9, 2004 refinancing of outstanding First Mortgage Bonds, the October 28, 2004 refinancing of the Prior AE Supply Loan, and the November 22, 2004 refinancing of outstanding First Mortgage Bonds. This amount was partially offset by $2,811.6 million (net of $30.5 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, primarily related to the previously mentioned refinancings, and $151.4 million in proceeds from the October 5, 2004 private placement of 10 million shares of common stock.

Monongahela

Monongahela’s cash flows from operating activities primarily result from the sale, transmission and distribution of electricity. Future cash flows will be affected by, among other things, the impact that the economy, weather and future regulatory proceedings have on revenues, future demand and market prices for energy.

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Internal generation of cash, consisting of cash flows provided by operating activities reduced by common and preferred dividends, was $202.9 million for the year ended December 31, 2005 compared with $11.4 million for the same period in 2004.

Operating Activities:    Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation and amortization expense is a significant component of cash flows from operating activities.

Cash flows provided by operating activities for the year ended December 31, 2005 were $208.0 million, consisting of changes in certain assets and liabilities of $113.3 million, discontinued operations and non-cash charges of $84.5 million and net income of $10.2 million. Cash flows provided by operating activities for the year ended December 31, 2004 were $49.6 million, consisting of discontinued operations and non-cash charges of $75.4 million and net income of $2.5 million, partially offset by changes in certain assets and liabilities of $28.3 million.

The changes in certain assets and liabilities for the year ended December 31, 2005 resulted in an increase in operating cash flows of $113.3 million. Operating cash flows were provided primarily by $63.9 million in net cash provided by operating activities of discontinued operations, a $60.3 million increase in accounts payable to affiliates, net, a $9.9 million increase in accounts payable and a $7.9 million change in taxes receivable/accrued, net, each primarily as a result of timing differences associated with the payment of certain obligations. These amounts were partially offset by cash flows used for operating activities primarily as a result of a $20.6 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, and a $9.5 million increase in collateral deposits, primarily due to the requirements of various contracts.

The changes in certain assets and liabilities for the year ended December 31, 2004 resulted in a decrease in operating cash flows of $28.3 million. Operating cash flows were used primarily for $49.4 million in net cash used in operating activities of discontinued operations. This amount was partially offset by cash flows provided by operating activities primarily as a result of a $17.2 million increase in accounts payable to affiliates, net, and a $7.4 million change in taxes receivable/accrued, net, each primarily as a result of timing differences associated with the payment of certain obligations.

Investing Activities:    Cash flows provided by investing activities for the year ended December 31, 2005 were $109.7 million. Cash flows used in investing activities for the year ended December 31, 2004 were $67.0 million.

Significant cash flows used in investing activities for both periods were for capital expenditures. The year ended December 31, 2005 amount also included $127.6 million in net cash provided by investing activities of discontinued operations, primarily as a result of the sale of the West Virginia natural gas operations, and $52.1 million in proceeds from the sale of assets, primarily as a result of the sale of the Ohio T&D assets.

Financing Activities:    Cash flows used in financing activities for the year ended December 31, 2005 were $226.2 million. Cash flows provided by financing activities for the year ended December 31, 2004 were $18.5 million.

Significant cash flows used in financing activities for the year ended December 31, 2005 were $80.0 million for a return of capital to AE with a portion of the proceeds from the sale of the West Virginia natural gas operations, $72.1 million for the retirement of outstanding First Mortgage Bonds related to the October 17, 2005 refinancing, $67.1 million in net cash used in financing activities of discontinued operations, $50.0 million for the redemption of preferred stock and $21.3 million for an increase in a note receivable from an affiliate. These amounts were partially offset by $69.2 million (net of $0.8 million related to an original issue discount and debt issuance costs) in proceeds from the issuance of new First Mortgage Bonds related to the October 17, 2005 refinancing.

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Significant cash flows provided by financing activities for the year ended December 31, 2004 were $117.2 million (net of $2.8 million related to an original issue discount and debt issuance costs) in proceeds from the issuance of new First Mortgage Bonds related to the June 9, 2004 refinancing and $63.7 million in net cash provided by financing activities of discontinued operations. These amounts were partially offset by $66.3 million for the retirement of outstanding First Mortgage Bonds and $53.6 million for the repayment of short-term debt, each related to the June 9, 2004 refinancing, and $38.3 million in cash dividends paid on preferred and common stock.

Potomac Edison

Potomac Edison’s cash flows from operating activities primarily result from the sale, transmission and distribution of electricity. Future cash flows will be affected by, among other things, the impact that the economy, weather, customer choice and future regulatory proceedings have on revenues, future demand and market prices for energy, as well as Potomac Edison’s ability to obtain and provide its customers with power at competitive prices.

Internal generation of cash, consisting of cash flows provided by operating activities reduced by common dividends, was $27.6 million for the year ended December 31, 2005 compared with $82.7 million for the same period in 2004.

Operating Activities:    Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation and amortization expense is a significant component of cash flows from operating activities.

Cash flows provided by operating activities for the year ended December 31, 2005 were $90.7 million, consisting of net income of $66.4 million and non-cash charges of $54.9 million, partially offset by changes in certain assets and liabilities of $30.6 million. Cash flows provided by operating activities for the year ended December 31, 2004 were $125.7 million, consisting of non-cash charges of $71.5 million, net income of $38.0 million and changes in certain assets and liabilities of $16.2 million.

The changes in certain assets and liabilities for the year ended December 31, 2005 resulted in a decrease in operating cash flows of $30.6 million. Operating cash flows were used primarily for a $21.1 million decrease in accounts payable to affiliates, net, primarily as a result of timing differences associated with the payment of certain obligations, and an $11.8 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues.

The changes in certain assets and liabilities for the year ended December 31, 2004 resulted in an increase in operating cash flows of $16.2 million. Operating cash flows were provided primarily by a $9.7 million increase in collateral deposits held, primarily as a result of increased collateral requirements under an affiliate power agreement, and a $7.0 million change in other assets.

Investing Activities:    Cash flows used in investing activities for the year ended December 31, 2005 and 2004 were $53.3 million and $76.0 million, respectively.

Significant cash flows used in investing activities for both periods were for capital expenditures. The year ended December 31, 2005 amount also included $10.6 million in proceeds from the sale of assets, primarily as a result of the sale of the Hagerstown, Maryland property, and a source of $9.7 million resulting from a decrease in restricted funds due to reduced collateral requirements related to an affiliate power agreement. The year ended December 31, 2004 amount also included a use of $9.7 million resulting from an increase in restricted funds due to collateral requirements related to an affiliate power agreement.

Financing Activities:    Cash flows used in financing activities for the year ended December 31, 2005 and 2004 were $53.6 million and $65.3 million, respectively.

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Significant cash flows used in financing activities for the year ended December 31, 2005 included $149.6 million for the retirement of outstanding First Mortgage Bonds related to the August 15, 2005 refinancing, and $63.1 million in cash dividends paid on common stock. These amounts were partially offset by $142.2 million (net of $2.8 million related to an original issue discount and debt issuance costs) in proceeds from the issuance of new First Mortgage Bonds related to the August 15, 2005 refinancing, and $14.4 million for a decrease in a note receivable from an affiliate.

Significant cash flows used in financing activities for the year ended December 31, 2004 included $180.6 million for the retirement of outstanding First Mortgage Bonds related to the November 22, 2004 refinancing, $43.0 million in cash dividends paid on common stock and $14.4 million for an increase in a note receivable from an affiliate. These amounts were partially offset by $172.7 million (net of $2.3 million related to an original issue discount and debt issuance costs) in proceeds from the issuance of new First Mortgage Bonds related to the November 22, 2004 refinancing.

AGC

AGC’s cash flows from operating activities primarily result from the sale of electricity. Future cash flows will be affected by, among other things, the impact that the economy and weather have on revenues, future demand and market prices for energy.

Internal generation of cash, consisting of cash flows provided by operating activities reduced by common dividends, was $22.4 million for the year ended December 31, 2005 compared with $29.3 million for the same period in 2004.

Operating Activities:    Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation expense is a significant component of cash flows from operating activities.

Cash flows provided by operating activities for the year ended December 31, 2005 were $44.2 million, consisting of net income of $31.1 million, non-cash charges of $12.5 million and changes in certain assets and liabilities of $0.6 million. Cash flows provided by operating activities for the year ended December 31, 2004 were $41.8 million, consisting of net income of $27.4 million, non-cash charges of $12.3 million and changes in certain assets and liabilities of $2.1 million.

The changes in certain assets and liabilities for the year ended December 31, 2005 resulted in an increase in operating cash flows of $0.6 million. Operating cash flows were provided primarily by a $4.2 million change in accounts receivable due from/payable to affiliates, net, and a $2.7 million increase in accounts payable, each primarily as a result of timing differences associated with the payment of certain obligations. These amounts were partially offset by cash flows used for operating activities primarily as a result of a $6.1 million change in taxes receivable/accrued, net, primarily as a result of timing differences associated with the payment of certain tax obligations.

The changes in certain assets and liabilities for the year ended December 31, 2004 resulted in an increase in operating cash flows of $2.1 million. Operating cash flows were provided primarily by a $1.5 million change in accounts receivable due from/payable to affiliates, net, and a $0.7 million change in taxes receivable/accrued, net, each primarily as a result of timing differences associated with the payment of certain obligations.

Investing Activities:    Cash flows used in investing activities for the year ended December 31, 2005 and 2004 were $13.0 million and $9.1 million, respectively, consisting of capital expenditures.

Financing Activities:    Cash flows used in financing activities for the year ended December 31, 2005 were $36.8 million consisting of a $15.0 million payment on a note payable to parent and $21.8 million of cash

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dividends paid on common stock. Cash flows used in financing activities for the year ended December 31, 2004 were $27.5 million consisting of a $15.0 million payment on a note payable to parent and $12.5 million of cash dividends paid on common stock.

Financing

AE Common Stock

During 2005 and 2004, AE issued approximately 0.6 million and 0.4 million shares, respectively, of common stock, primarily in connection with matching contributions to its Employee Stock Ownership and Savings Plan, stock option exercises and settlement of stock units.

During 2005, AE issued an aggregate of 25.0 million shares of its common stock in connection with a tender offer for $300.0 million of Trust Preferred Securities issued by Capital Trust.

On October 5, 2004, AE sold 10.0 million shares of its common stock at a price of $15.15 per share directly to institutional investors in a private placement.

There were no shares of common stock repurchased in 2005 and 2004.

Preferred Stock

On October 31, 2005, Monongahela fully redeemed its $50.0 million of outstanding $7.73, Series L ($100 par value) Cumulative Preferred Stock. Monongahela paid accrued and unpaid dividends of approximately $1 million.

Return of Capital

During October 2005, AE received $80.0 million representing a return of capital from Monongahela using a portion of the cash proceeds from the sale of its West Virginia natural gas operations.

Long-term Debt

See “Liquidity and capital requirements,” above, and Note 2, “Capitalization,” to the Consolidated Financial Statements for information regarding debt issued and redeemed during 2005 and 2004.

Short-term Debt

Both AE and AE Supply manage short-term obligations with cash on hand and amounts available under revolving credit facilities. AE, Monongahela, Potomac Edison, AGC, West Penn and AE Supply manage excess cash and short-term requirements through an internal money pool. The money pool provides funds to approved AE subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. AE and AE Supply can only lend money into the money pool. Monongahela, West Penn and Potomac Edison can either lend money into, or borrow money from, the money pool. AGC can only borrow money from the money pool.

At December 31, 2005, no registrant had access to any short-term revolving credit facilities or lines of credit with third-party financial institutions beyond those described above. AE had $263.5 million of revolving credit available under its $400 million Revolving Credit Facility. There were $136.5 million of outstanding letters of credit issued under the Revolving Credit Facility at December 31, 2005. AE Supply also had a $1.6 million letter of credit outstanding that is collateralized by cash and was not issued under the Revolving Credit Facility. The

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$1.6 million letter of credit expired in February 2006 and was replaced with a $2.1 million letter of credit. The $2.1 million letter of credit is collateralized by cash, is not issued under the Revolving Credit Facility and expires in February 2007.

Lease Transactions

In December 2005, Allegheny signed a coal lease and sales agreement with an affiliate of Alliance Resource Partners, L.P. to permit, develop and mine Allegheny’s coal reserve in Washington County, Pennsylvania. Alliance will evaluate the feasibility of mining the reserve and seek the necessary permits and other governmental approvals to mine the reserve. If the reserve is developed, it is expected to produce high BTU, “scrubber-quality” coal suitable for use in Allegheny’s power plants with SO₂ emission controls, and Allegheny has agreed to purchase up to two million tons annually of the mine’s output. Allegheny also will receive estimated royalty payments of $5 to $10 million per year on coal that is mined and sold from the reserve, depending upon production levels and coal prices, after the mine reaches full commercial operation.

Changes in Credit Ratings

On February 17, 2005, S&P upgraded its credit rating of AE Supply’s Senior Secured Debt (referred to as the Prior AE Supply Loan) and the secured portion of the Amended A-Notes to “BB-” from “B+.” S&P’s outlook for AE and its subsidiaries remains positive.

On February 24, 2005, Moody’s Investors Service (“Moody’s”) upgraded its credit rating for AE’s Senior Unsecured Debt to “B1” from “B2.” Moody’s also upgraded its credit rating for AE Supply’s Senior Secured Debt to “Ba3” from “B1” and upgraded its credit rating for AE Supply’s Senior Unsecured Debt to “B2” from “B3.” Moody’s also upgraded its credit rating for AGC’s Senior Unsecured Debt to “B2” from “B3.” Moody’s upgraded its outlook for Monongahela, Potomac Edison and West Penn to positive from stable, making the rating outlook for all of Allegheny’s rated entities positive.

On February 25, 2005, Fitch IBCA Ratings Services revised its outlook of AE, AE Supply and AGC to positive from stable.

On April 19, 2005 S&P issued a new short-term credit rating for AE of “B2.” S&P reiterated its positive outlook for AE.

On May 9, 2005, S&P raised all of its credit ratings for AE and its subsidiaries (except for AE’s short-term rating and West Penn’s Transition Bonds). AE’s corporate rating was raised from “B+” to “BB-.” The ratings for Senior Unsecured Debt of AE, AE Supply and AGC and for Monongahela’s preferred equity were raised from “B-” to “B.” The ratings for the Senior Unsecured Debt of Monongahela and Potomac Edison were raised from “B” to “B+.” The rating for the Senior Unsecured Debt of West Penn was raised from “B+” to “BB-.” The rating for the Senior Secured Debt of AE Supply was raised from “BB-” to “BB.” The ratings for First Mortgage Bonds issued by Monongahela and Potomac Edison were raised from “BB+” to “BBB-.” S&P’s outlook for AE and its subsidiaries remains positive.

On June 3, 2005, Moody’s upgraded all of its credit ratings for AE and its subsidiaries (except West Penn’s Transition Bonds). AE’s Senior Unsecured Debt rating was raised from “B1” to “Ba2.” AE Supply’s and AGC’s Senior Unsecured Debt rating was raised from “B2” to “Ba3.” AE Supply’s Senior Secured Debt rating and AE Supply Statutory Trust’s Senior Secured Debt rating were raised from “Ba3” to “Ba2.” The rating for Monongahela’s First Mortgage Bonds was raised from “Ba1” to “Baa3.” Monongahela’s Senior Unsecured Debt rating was raised from “Ba2” to “Ba1.” Monongahela’s Preferred Stock rating was raised from “B1” to “Ba3.” The rating for Potomac Edison’s First Mortgage Bonds was raised from “Ba1” to “Baa2.” Potomac Edison’s Senior Unsecured Debt rating was raised from “Ba2” to “Baa3.” West Penn’s Senior Unsecured Debt was raised from “Ba1” to “Baa3.” Moody’s outlook for AE and its subsidiaries is stable.

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On June 13, 2005, Moody’s assigned a new Corporate Family rating of “Ba1” for AE and a new Liquidity rating of “SGL-2” for AE. Moody’s reiterated its stable outlook for AE and its subsidiaries.

On July 8, 2005, Fitch upgraded the Senior Secured Debt rating of AE Supply from “BB-” to “BB.” AE Supply’s Senior Unsecured Debt rating and AGC’s Senior Unsecured Debt rating were raised from “B-” to “B+.” Fitch reiterated its positive outlook for AE, AE Supply and AGC.

On September 27, 2005, Fitch, S&P and Moody’s assigned ratings of “AAA,” “AAA” and “Aaa,” respectively, to the Series-A 4.46% Transition Bonds issued by WPP Funding, LLC.

On November 7, 2005, Fitch upgraded its credit rating for AE Supply’s Senior Unsecured Debt from “B+” to “BB-” and upgraded its credit rating for AE Supply’s Senior Secured Debt from “BB” to “BB+.” Fitch also upgraded its credit rating for AGC’s Senior Unsecured Debt from “B+” to “BB+.”

On December 6, 2005, Fitch upgraded the ratings for the First Mortgage Bonds issued by Monongahela and Potomac Edison from “BBB” to “BBB+.”

On January 18, 2006, S&P raised its corporate credit ratings on AE and its subsidiaries from “BB-” to “BB+.” The ratings for Senior Unsecured Debt of AE, AE Supply and AGC were raised from “B” to “BB-.” The rating for Senior Secured Debt of AE Supply was raised from “BB” to “BBB-.” The ratings for the Senior Unsecured Debt of Monongahela and Potomac Edison were raised from “B+” to “BB-.” The rating for the Preferred Stock of Monongahela was raised from “B” to “B+.” The rating for Senior Unsecured Debt of West Penn was raised from “BB-” to BB+.” S&P’s outlook for AE and its subsidiaries remains positive.

The following table lists Allegheny’s credit ratings, as of February 28, 2006:

	Moody’s	S & P	Fitch
Outlook	Stable	Positive	Positive/Stable (a)
AE:
Corporate Credit Rating	Ba1(b)	BB+	NR
Senior Unsecured Debt	Ba2	BB-	BB-
Short-term Rating	SGL-2(c)	B2	NR
AE Supply:
Senior Unsecured Debt	Ba3	BB-	BB-
Senior Secured Debt	Ba2	BBB-	BB+
Pollution Control Bonds	NR	NR	AAA
Monongahela:
First Mortgage Bonds	Baa3	BBB-	BBB+
Senior Unsecured Debt	Ba1	BB-	BBB-
Preferred Stock	Ba3	B+	BB+
Potomac Edison:
First Mortgage Bonds	Baa2	BBB-	BBB+
Senior Unsecured Debt	Baa3	BB-	BBB-
West Penn:
Transition Bonds	Aaa	AAA	AAA
Senior Unsecured Debt	Baa3	BB+	BBB-
AGC:
Senior Unsecured Debt	Ba3	BB-	BB+

(a) Rating outlook positive for AE, AE Supply and AGC. All other entities are stable.

(b) Corporate Family rating

(c) Liquidity rating

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Derivative Instruments and Hedging Activities

Allegheny follows SFAS No. 133 for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The standards require that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in earnings or other comprehensive income (loss) and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

AE Supply records any commodity contract related to energy trading that is a derivative instrument at its fair value as a component of operating revenues, unless the contract falls within the “normal purchases and normal sales” scope exception of SFAS No. 133 or is designated as a hedge for accounting purposes. The normal purchases and normal sales scope exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under accrual accounting and, therefore, are not recorded on the balance sheet at fair value. For certain transactions that are designed to hedge the cash flows of a forecasted transaction, the effective portion of the hedge is recorded as a separate component of stockholders’ equity under the caption “Accumulated other comprehensive income (loss)” and subsequently reclassified into earnings when the forecasted transaction is completed or settled. The ineffective portion of the hedge is immediately reflected in earnings.

AE Supply has designated certain contracts as cash flow hedges. The first contracts were designated effective July 1, 2004 and were related to legacy mark to market contracts that are going to be serviced by anticipated excess generation. These contracts expire at various dates through December 31, 2006. During the third quarter 2005, additional contracts were executed and designated as cash flow hedges to lock in prices for a portion of anticipated excess generation for the period October 2005 through April 2006.

The fair value of AE Supply’s trading portfolio is primarily comprised of interest rate swap agreements and commodity cash flow hedges, The contracts represent an aggregate liability of $106.6 million and $80.1 million as of December 31, 2005 and 2004, respectively. These are accounted for at fair value on the Consolidated Balance Sheets.

See Note 5, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements for additional information.

RECENT ACCOUNTING PRONOUNCEMENTS

The following recent accounting pronouncements were issued, but have not yet been adopted by Allegheny as of December 31, 2005:

SFAS No. 123 (Revised 2004), “Share-Based Payment” (“SFAS 123R”).    In December 2004, the FASB issued SFAS 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which revised SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion 25, “Accounting for Stock Issued to Employees,” and its related implementation guidance. SFAS 123R requires that compensation cost relating to all share-based payments to employees, including grants of employee stock options, be recognized in the financial statements based on the fair values of the equity instrument issued. The pro forma disclosures under SFAS 123 will no longer be permitted. SFAS 123R will be effective for Allegheny in the first quarter of 2006 and will apply to all prospective awards, as well as all outstanding unvested share-based payment awards as of January 1, 2006, using the modified prospective transition method without restatement of prior periods. Under the modified prospective transition method, compensation cost for the portion of awards for which the requisite service has not been rendered will be recognized as the requisite service is rendered after January 1, 2006. Allegheny expects to determine the fair value of stock option awards after January 1, 2006 in a manner consistent with the

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methodology used to illustrate the effect of applying the fair value recognition of SFAS 123 in the table above, and expects that the impact on 2006 will not be materially different from the pro forma effect disclosed above.

Staff Accounting Bulletin No. 107 (“SAB 107”).    In March 2005, the SEC issued SAB 107, which expressed the views of the SEC regarding the interaction between SFAS 123R and certain SEC rules and regulations and provided guidance regarding the valuation of share-based payment arrangements for public companies. Allegheny is currently in the process of implementing SFAS 123R, effective as of January 1, 2006, and will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS 123R.

SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“SFAS 154”).    In May 2005, the FASB issued SFAS 154, which replaced APB Opinion No. 20, “Accounting Changes,” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS 154 requires companies to recognize a change in accounting principle, including a change required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. Allegheny will assess the impact of a retrospective application of a change in accounting principle in accordance with SFAS 154 when such a change arises after the effective date of January 1, 2006.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

AE

During 2005, Allegheny continued its focus on reducing risk, optimizing the value of its generation facilities, reducing the volatility of mark-to-market earnings and prudently managing and protecting the value associated with the existing positions in its wholesale energy markets transactions portfolio.

Allegheny remains exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price and transportation costs of electricity, coal, natural gas and other energy-related commodities. The interest rate risk exposure results from changes in interest rates related to interest rate swaps, variable-rate debt and debt that is maturing and is refinanced. Allegheny has a program designed to systematically identify, measure, evaluate and actively manage and report market risks.

Allegheny’s Corporate Energy Risk Policy was adopted by its Board of Directors and is monitored by a Risk Management Committee, which is chaired by its Chief Executive Officer or his designee and is composed of senior management. An independent risk management group within Allegheny measures and monitors the risk exposures to ensure compliance with the policy and to ensure that the policy is periodically reviewed.

To manage the financial exposure to commodity price fluctuations in its wholesale transactions portfolio, fuel procurement, power marketing, natural gas supply and risk management activities, Allegheny, through AE Supply, enters into contracts, such as electricity and natural gas purchase and sale commitments, to hedge the risk exposure. However, Allegheny does not hedge the entire exposure of its operations from commodity price volatility for a variety of reasons. To the extent Allegheny does not hedge against commodity price volatility, its consolidated results of operations, cash flows and consolidated financial position may be affected either favorably or unfavorably by a shift in the forward price curves and spot commodity prices.

AE Supply’s wholesale energy business enters into certain contracts for the purchase and sale of electricity. Certain of these contracts are recorded at their fair value and are an economic hedge for the generation facilities. For accounting purposes, the generation facilities are recorded at historical cost less depreciation. As a result, Allegheny’s results of operations and financial position can be favorably or unfavorably affected by a change in forward market prices.

Of its commodity-driven risks, Allegheny is primarily exposed to risks associated with the wholesale electricity markets, including the generation, fuel procurement, power marketing and the purchase and sale of electricity. Allegheny’s wholesale activities principally consist of bilateral forward contracts for the purchase and sale of electricity and natural gas. The majority of these contracts represent commitments to purchase or sell electricity at fixed prices in the future. These forward contracts generally require physical delivery of electricity.

At December 31, 2005, AE’s outstanding debt subject to variable interest rates was $1.19 billion, compared to $1.08 billion of outstanding debt subject to variable interest rates at December 31, 2004. Accordingly, a one percent increase in the variable interest rate under the New AE Facility and the Refinanced AE Supply Loan would increase Allegheny’s projected interest expense in 2006 by approximately $11.9 million, on an annual basis, based on the amount of outstanding debt as of December 31, 2005. For additional information regarding these financing activities, see “Financial Condition, Requirements and Resources—Liquidity and Capital Requirements.”

Credit Risk

Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Allegheny evaluates the credit standing of a prospective counterparty based on the prospective counterparty’s financial condition. Where deemed necessary, Allegheny may impose specified collateral requirements and use standardized agreements that facilitate netting of cash flows. Allegheny monitors the financial conditions of existing counterparties on an ongoing basis. Allegheny’s independent risk management group oversees credit risk.

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Allegheny engages in various short-term energy trading activities. The counterparties to these transactions generally include electric and natural gas utilities, independent power producers, energy marketers and commercial and industrial customers. In the event the counterparties do not fulfill their obligations, Allegheny may incur a loss to close out a position.

Allegheny has a concentration of customers in the electric and natural gas utility industries, most of whom are viewed as above investment grade credit quality. This concentration of customers may affect Allegheny’s overall exposure to credit risk, either positively or negatively, because these customers may be similarly affected by changes in economic or other conditions.

As of December 31, 2005, the fair value of Allegheny’s trading portfolio is comprised primarily of interest rate swap agreements with a single counterparty and commodity cash flow hedges.

Additionally, AE Supply is a counterparty to certain long-term agreements for the transportation of natural gas. See “Business—Fuel, Power and Resource Supply.”

Market Risk

Market risk arises from the potential for changes in the value of energy related to price and volatility in the market. Allegheny reduces these risks by using its generation assets to back positions on physical transactions. Allegheny monitors market risk exposure and credit risk limits within the guidelines of its Corporate Energy Risk Policy. Allegheny evaluates commodity price risk, operational risk and credit risk in establishing the fair value of commodity contracts.

Allegheny and AE Supply use various methods to measure their exposure to market risk on a daily basis, including a value at risk model (“VaR”). VaR is a statistical model that attempts to predict risk of loss based on historical market price and volatility data over a given period of time. The quantification of market risk using VaR provides a consistent measure of risk across diverse energy markets and products with different risk factors to set the overall corporate risk tolerance, determine risk targets and monitor positions. Allegheny and AE Supply calculate VaR by using a variance/covariance approach, in which the option positions are evaluated by using their delta equivalences. Due to inherent limitations of VaR, including the use of approximations to value options, subjectivity in the choice of liquidation period and reliance on historical data to calibrate the model, the VaR calculation may not accurately reflect Allegheny’s and AE Supply’s market risk exposure. As a result, changes in Allegheny’s and AE Supply’s market risk sensitive instruments could differ from the calculated VaR, and these changes could have a material effect on Allegheny’s and AE Supply’s consolidated results of operations and financial position. In addition to VaR, Allegheny and AE Supply routinely perform stress and scenario analyses to measure extreme losses due to exceptional events. Allegheny and AE Supply review the VaR and stress test results to determine the maximum expected reduction in the fair value of the entire energy markets portfolio.

AE Supply calculated VaR using the full term of all remaining wholesale energy market positions that are accounted for as marked-to-market. This calculation is based upon management’s best estimates and modeling assumptions, which could materially differ from actual results. As of December 31, 2005 and 2004, this calculation yielded a VaR of $0.4 million and $0.3 million, respectively.

MONONGAHELA

Monongahela is exposed to market risks associated with commodity prices that result from market fluctuations in the price and transportation costs of electricity.

Monongahela is subject to capped rates in West Virginia. Monongahela agreed to terminate its fuel clause in West Virginia effective July 1, 2000. The purpose of the fuel clause, which allowed Monongahela to recoup

122

certain fuel costs through customer rates, had been to offset fluctuations in the market price of fuel. In order to manage its financial exposure to these price fluctuations in the absence of a fuel clause, Monongahela enters into contracts, such as fuel purchase commitments. To the extent that Monongahela purchases fuel at significantly higher prices, Monongahela’s results of operations and cash flows could be adversely affected.

See “Business—Regulatory Framework Affecting Allegheny.”

POTOMAC EDISON

Potomac Edison is exposed to market risks associated with commodity prices that result from market fluctuations in the price of electricity as discussed below.

In connection with its restructuring plans in Maryland and Virginia, Potomac Edison separated its rates into two separate charges—a generation (or supply) charge and T&D charges. Generation rates are capped through the applicable transition period. The transition period for Potomac Edison’s Maryland residential customers extends through December 31, 2008.

Pursuant to a settlement, Potomac Edison will provide SOS to residential customers through December 31, 2012, and will provide SOS to other commercial and industrial customers for various periods through as late as December 31, 2008. Potomac Edison will procure wholesale power necessary to serve these obligations (after the expiration of the transition period and before the expiration of the settlement period) through a competitive bidding process. In addition to the electric supply costs associated with the winning bids, Potomac Edison will also be allowed to recover its incremental costs for providing these services (including a return for its shareholder) through an administrative charge.

AE Supply provides Potomac Edison with a majority of the electricity needed to serve those customers who do not choose an alternative electricity generation supplier during the applicable transition period. Potomac Edison’s power supply agreements with AE Supply have both fixed-price and market-based pricing components. The amount of electricity purchased under these agreements that is subject to market prices escalates each year, through June 30, 2007 in Virginia and December 31, 2008 in Maryland. To the extent that Potomac Edison purchases electricity from AE Supply at market prices that exceed the established fixed prices, Potomac Edison’s results of operations and cash flows could be adversely affected. In 2005 and 2004, $3.3 million and $6.7 million, respectively, of additional purchased electricity costs were recorded due to this market-based pricing component. See “Business—Regulatory Framework Affecting Allegheny.”

AGC

Not Applicable.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements

	Page No.
Allegheny Energy, Inc. and Subsidiaries	125
Report of Independent Registered Public Accounting Firm	187
Monongahela Power Company and Subsidiaries	189
Report of Independent Registered Public Accounting Firm	221
The Potomac Edison Company and Subsidiaries	222
Report of Independent Registered Public Accounting Firm	245
Allegheny Generating Company	246
Report of Independent Registered Public Accounting Firm	262
Schedule I AE (Parent Company) Condensed Financial Statements	263
Schedule II Valuation and Qualifying Accounts	265

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Consolidated Statements of Operations

	Year ended December 31,
(In thousands, except share amounts)	2005			2004			2003
Operating revenues	$	3,037,887		$	2,756,121		$	2,182,294
Operating expenses:
Fuel consumed in electric generation		736,641			614,422			592,007
Purchased power and transmission		458,306			328,421			312,909
Loss on sale of Ohio T&D assets		29,256			—			—
Gain on sale of OVEC power agreement and shares		—			(94,826	)		—
Deferred energy costs, net		(1,528	)		204			(1,737	)
Operations and maintenance		757,746			818,434			985,385
Depreciation and amortization		308,141			299,425			286,200
Taxes other than income taxes		212,534			200,811			203,909
Total operating expenses		2,501,096			2,166,891			2,378,673
Operating income (loss)		536,791			589,230			(196,379	)
Other income and expenses, net (Note 19)		44,230			24,522			105,989
Interest expense and preferred dividends:
Interest expense		436,447			400,196			422,792
Preferred dividends of subsidiary		4,071			5,037			5,037
Total interest expense and preferred dividends		440,518			405,233			427,829
Income (loss) from continuing operations before income taxes and minority interest		140,503			208,519			(518,219	)
Income tax expense (benefit) from continuing operations		64,771			79,669			(202,170	)
Minority interest in net income (loss) of subsidiaries		587			(882	)		(7,174	)
Income (loss) from continuing operations		75,145			129,732			(308,875	)
Loss from discontinued operations, net of tax (Note 3)		(6,152	)		(440,330	)		(25,339	)
Income (loss) before cumulative effect of accounting changes		68,993			(310,598	)		(334,214	)
Cumulative effect of accounting changes, net of tax of $3,367, $0 and $12,974		(5,928	)		—			(20,765	)
Net income (loss)	$	63,065		$	(310,598	)	$	(354,979	)
Common Share Data:
Weighted average common shares outstanding
Basic		155,016			129,486			126,848
Diluted		158,634			156,492			126,848
Basic income (loss) per common share:
Income (loss) from continuing operations	$	0.48		$	1.00		$	(2.44	)
Loss from discontinued operations, net of tax		(0.04	)		(3.40	)		(0.20	)
Cumulative effect of accounting changes, net of tax		(0.04	)		—			(0.16	)
Net income (loss) per common share	$	0.40		$	(2.40	)	$	(2.80	)
Diluted income (loss) per common share:
Income (loss) from continuing operations	$	0.47		$	0.99		$	(2.44	)
Loss from discontinued operations, net of tax		(0.04	)		(2.82	)		(0.20	)
Cumulative effect of accounting changes, net of tax		(0.03	)		—			(0.16	)
Net income (loss) per common share	$	0.40		$	(1.83	)	$	(2.80	)

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Cash Flows

	Year ended December 31,
(In thousands)	2005			2004			2003
				(Revised-Note 1)
Cash Flows From Operating Activities:
Net income (loss)	$	63,065		$	(310,598	)	$	(354,979	)
Loss from discontinued operations, net of tax		6,152			440,330			—
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of accounting changes, net		5,928			—			20,765
Reapplication of SFAS No. 71		—			—			(75,824	)
Depreciation and amortization		308,141			299,425			326,935
Amortization of debt issuance costs		24,861			44,401			33,681
Loss (gain) on asset sales and disposals		26,520			(20,937	)		22,054
Minority interest in net income (loss) of subsidiaries		587			(882	)		(7,174	)
Deferred income taxes and investment tax, net		(47,334	)		(18,907	)		(158,432	)
Stock-based compensation expense		10,632			21,884			10,647
Unrealized losses (gains) on commodity contracts, net		(20,639	)		5,720			468,375
Other, net		(7,053	)		26,509			(48,546	)
Changes in certain assets and liabilities:
Accounts receivable, net		(48,261	)		26,871			116,749
Materials, supplies and fuel		(3,744	)		(10,271	)		(23,707	)
Taxes receivable/accrued, net		112,833			97,568			186,869
Collateral deposits		(59,067	)		(37,533	)		(36,709	)
Other current assets		6,690			4,197			24,798
Accounts payable		75,128			(27,617	)		(92,333	)
Accrued interest		34,536			2,380			(1,781	)
Other current liabilities		(14,185	)		17,694			(20,564	)
Benefit plans’ investments		—			—			47,309
Other assets		2,956			(1,712	)		(55,043	)
Commodity contract termination costs liability		—			(259	)		(47,706	)
Other liabilities		(46,376	)		(26,587	)		34,682
Net cash provided by (used in) operating activities of discontinued operations		54,750			(7,981	)		—
Net cash provided by operating activities		486,120			523,695			370,066
Cash Flows From Investing Activities:
Capital expenditures		(306,461	)		(265,618	)		(254,460	)
Acquisition of generation assets		—			—			(318,435	)
Proceeds from sale of businesses and assets		66,497			24,039			57,645
Decrease (increase) in restricted funds		207,268			(183,830	)		(42,676	)
Other investments		(2,644	)		2,130			11,707
Net cash provided by investing activities of discontinued operations		226,829			161,378			—
Net cash provided by (used in) investing activities		191,489			(261,901	)		(546,219	)
Cash Flows From Financing Activities:
Net repayments of short-term debt		—			(53,610	)		(1,079,210	)
Issuance of long-term debt		1,849,061			2,811,547			2,274,098
Retirement of long-term debt		(2,406,870	)		(3,506,000	)		(694,354	)
Redemption of preferred stock of subsidiary		(50,000	)		—			—
Proceeds from issuance of common stock		—			151,360			—
Exercise of stock options		2,941			227			—
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(1,100	)		—
Net cash used in financing activities of discontinued operations		(11	)		(3,348	)		—
Net cash provided by (used in) financing activities		(604,879	)		(600,924	)		500,534
Net increase (decrease) in cash and cash equivalents		72,730			(339,130	)		324,381
Cash and cash equivalents at beginning of period		189,482			528,612			204,231
Cash and cash equivalents at end of period	$	262,212		$	189,482		$	528,612
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest (net of amount capitalized)	$	399,797		$	392,526		$	431,666
Income taxes, net	$	3,215		$	(2,748	)	$	(267,024	)

See accompanying Notes to Consolidated Financial Statements

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Consolidated Balance Sheets

	As of December 31,
(In thousands)	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	262,212		$	189,482
Accounts receivable:
Customer		179,634			165,000
Unbilled utility revenue		129,111			126,612
Wholesale and other		82,261			51,518
Allowance for uncollectible accounts		(16,778	)		(19,854	)
Materials and supplies		98,069			100,054
Fuel		67,273			61,812
Deferred income taxes		93,404			44,590
Prepaid taxes		45,758			46,900
Assets held for sale (Note 3)		1,521			150,031
Collateral deposits		147,775			88,708
Commodity contracts		9,325			13,523
Restricted funds		21,589			228,857
Regulatory assets		38,418			37,626
Other		14,246			20,273
Total current assets		1,173,818			1,305,132
Property, Plant and Equipment, Net:
Generation		5,751,077			5,695,851
Transmission		1,028,323			1,015,751
Distribution		3,448,350			3,366,217
Other		429,108			463,515
Accumulated depreciation		(4,508,707	)		(4,341,282	)
Subtotal		6,148,151			6,200,052
Construction work in progress		129,277			102,966
Total property, plant and equipment, net		6,277,428			6,303,018
Investments and Other Assets:
Non-current assets held for sale (Note 3)		48,559			340,457
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		28,555			29,991
Intangible assets		27,396			33,215
Other		49,413			46,628
Total investments and other assets		521,210			817,578
Deferred Charges:
Commodity contracts		—			3,667
Regulatory assets		544,810			562,843
Other		41,546			52,902
Total deferred charges		586,356			619,412
Total Assets	$	8,558,812		$	9,045,140

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Balance Sheets (continued)

	As of December 31,
(In thousands, except share amounts)	2005			2004
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Long-term debt due within one year (Note 2)	$	477,217		$	385,142
Accounts payable		316,713			223,584
Accrued taxes		154,587			112,866
Commodity contracts		92,934			40,835
Accrued interest		91,433			61,726
Liabilities associated with assets held for sale (Note 3)		—			37,471
Other		153,570			144,082
Total current liabilities		1,286,454			1,005,706
Long-term Debt (Note 2)		3,624,483			4,540,764
Deferred Credits and Other Liabilities:
Commodity contracts		22,994			56,501
Investment tax credit		76,965			83,307
Deferred income taxes		692,241			635,374
Obligations under capital leases		16,427			23,788
Regulatory liabilities		454,275			453,913
Adverse power purchase commitment		184,224			201,377
Liabilities associated with assets held for sale (Note 3)		—			89,356
Other		459,465			505,620
Total deferred credits and other liabilities		1,906,591			2,049,236
Commitments and Contingencies (Note 23)
Minority Interest		21,989			21,618
Preferred Stock of Subsidiary		24,000			74,000
Common Stockholders’ Equity:
Common stock, $1.25 par value, 260 million shares authorized and 163,002,295 and 137,430,137 shares issued at December 31, 2005 and 2004, respectively		203,753			171,788
Other paid-in capital		1,880,644			1,600,215
Accumulated deficit		(244,625	)		(307,690	)
Treasury stock at cost; 49,493 shares at December 31, 2005 and 2004		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(142,721	)		(108,741	)
Total common stockholders’ equity		1,695,295			1,353,816
Total Liabilities and Stockholders’ Equity	$	8,558,812		$	9,045,140

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Capitalization

			As of December 31,
(In thousands, except share amounts)			2005			2004
Common Stockholders’ Equity (See Consolidated Balance Sheets)			$	1,695,295		$	1,353,816
Preferred Stock of Subsidiary, $100 par value:
Series	December 31, 2005 Regular Call Price Per Share
4.40% - 4.80%—190,000 shares outstanding at December 31, 2005 and 2004	$	103.50 to $106.50	$	19,000		$	19,000
$6.28 - $7.73—50,000 and 550,000 shares outstanding at December 31, 2005 and 2004, respectively		$102.86		5,000			55,000
Total Preferred Stock of Subsidiary			$	24,000		$	74,000
Long-term Debt:
	December 31, 2005 Interest Rate %
First mortgage bonds, maturity:
2006		5.000	$	300,000		$	300,000
2014 - 2015		5.125 - 6.700		510,000			295,000
2022 - 2025		—		—			215,000
Transition bonds due 2008 - 2010		4.460 - 6.980		316,284			272,977
Debentures due 2023		6.875		100,000			100,000
Pollution control bonds and other secured and unsecured notes due 2007 - 2029		4.700 - 6.875		356,065			356,065
Medium-term debt due 2006 - 2012		5.000 - 8.250		1,340,000			2,020,000
2004 Refinancing credit facility, due 2007 - 2011		—		—			1,082,148
2005 Refinancing credit facility, due 2010 - 2011		5.974 - 6.450		1,187,979			—
Convertible Trust Preferred Securities due 2008		—		—			300,000
Unamortized debt discounts, premiums and terminated interest rate swaps, net				(8,628	)		(15,284	)
Total long-term debt (including current maturities of $477,217 and $385,142)				4,101,700			4,925,906
Total long-term debt associated with assets held for sale				—			86,732
Total Capitalization			$	5,820,995		$	6,440,454

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Stockholders’ Equity

(In thousands, except shares)	Shares outstanding		Common stock			Other paid-in capital			Retained earnings (deficit)			Treasury stock			Accumulated other comprehensive loss			Total stockholders’ equity
Balance at January 1, 2003	126,597,273		$	158,261		$	1,446,180		$	357,889		$	(411	)	$	(30,412	)	$	1,931,507
Net loss	—			—			—			(354,979	)		—			—			(354,979	)
Forfeiture of stock awards	(28,949	)		—			(473	)		—			(1,027	)		—			(1,500	)
Issuance of common stock for Employee Stock Ownership and Savings Plan	399,914			500			2,123			—			—			—			2,623
Other comprehensive loss	—			—			—			—			—			(61,792	)		(61,792	)
Balance at December 31, 2003	126,968,238			158,761			1,447,830			2,910			(1,438	)		(92,204	)		1,515,859
Net loss	—			—			—			(310,598	)		—			—			(310,598	)
Issuance of common stock for Employee Stock Ownership and Savings Plan	363,361			454			5,591			—			—			—			6,045
Issuance of common stock, net	10,000,000			12,500			138,860			—			—			—			151,360
Stock-based compensation expense-stock units	—			—			6,729			—			—			—			6,729
Stock-based compensation expense-non employee stock awards	16,000			20			484			—			—			—			504
Exercise of stock options	17,000			21			206			—			—			—			227
Settlement of stock units	30,000			38			422			—			—			—			460
Other	(13,955	)		(6	)		93			(2	)		(318	)		—			(233	)
Other comprehensive loss	—			—			—			—			—			(16,537	)		(16,537	)
Balance at December 31, 2004	137,380,644			171,788			1,600,215			(307,690	)		(1,756	)		(108,741	)		1,353,816
Net income	—			—			—			63,065			—			—			63,065
Issuance of common stock for Employee Stock Ownership and Savings Plan	294,904			369			7,388			—			—			—			7,757
Conversion of trust preferred securities	24,998,997			31,249			258,385			—			—			—			289,634
Stock-based compensation expense-stock units	—			—			9,939			—			—			—			9,939
Stock-based compensation expense-non-employee stock awards	3,600			4			689			—			—			—			693
Exercise of stock options	199,969			250			2,691			—			—			—			2,941
Settlement of stock units	74,688			93			393			—			—			—			486
Tax benefit on exercised stock options and stock unit settlement	—			—			1,063			—			—			—			1,063
Other	—			—			(119	)		—			—			—			(119	)
Other comprehensive loss	—			—			—			—			—			(33,980	)		(33,980	)
Balance at December 31, 2005	162,952,802		$	203,753		$	1,880,644		$	(244,625	)	$	(1,756	)	$	(142,721	)	$	1,695,295

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Comprehensive Income (Loss)

	Year ended December 31,
(In thousands)	2005			2004			2003
Net income (loss)	$	63,065		$	(310,598	)	$	(354,979	)
Other comprehensive income (loss), net of tax:
Minimum pension liability adjustment, net of tax of $69, $10,477 and $45,276		(5,011	)		(14,677	)		(62,063	)
Unrealized gain (loss) on available-for-sale securities, net of tax of $282, $167 and $117		(252	)		87			168
Unrealized gains (losses) on cash flow hedges for the period, net of tax of $18,211, $1,210 and $64		(28,717	)		(1,947	)		103
Total other comprehensive loss		(33,980	)		(16,537	)		(61,792	)
Comprehensive income (loss)	$	29,085		$	(327,135	)	$	(416,771	)

See accompanying Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note No.		Page No.
1	Basis of Presentation	133
2	Capitalization	142
3	Discontinued Operations and Assets Held for Sale	150
4	Asset Sales	152
5	Derivative Instruments and Hedging Activities	153
6	Asset Retirement Obligations (“ARO”)	155
7	Business Segments	156
8	Goodwill and Other Intangible Assets	158
9	Income Taxes	158
10	Pension Benefits and Postretirement Benefits Other Than Pensions	161
11	Stock-Based Compensation	167
12	Reconciliation of Basic and Diluted Income (Loss) per Share	169
13	Accounting for the Effects of Price Regulation	170
14	Regulatory Assets and Liabilities	171
15	Dividend Restriction	172
16	Restructuring Charges and Workforce Reduction Expenses	172
17	Fair Value of Financial Instruments	173
18	Jointly Owned Electric Utility Plants	173
19	Other Income and Expenses, Net	173
20	Quarterly Financial Information (Unaudited)	174
21	Guarantees and Letters of Credit	174
22	Variable Interest Entities	175
23	Commitments and Contingencies	176
24	Subsequent Event	186

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1:  BASIS OF PRESENTATION

Allegheny Energy, Inc. (“AE”) operates primarily through directly and indirectly owned subsidiaries (together with AE, “Allegheny”). Allegheny’s two business segments are the Delivery and Services segment and the Generation and Marketing segment.

The Delivery and Services segment primarily consists of Allegheny’s regulated utility subsidiaries. These subsidiaries include Monongahela Power Company (“Monongahela”), excluding its generation operations, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”) (collectively, the “Distribution Companies”). The Distribution Companies operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia, Maryland and Virginia. The Distribution Companies are subject to federal and state regulation. The Delivery and Services segment also includes Allegheny Ventures, Inc. (“Allegheny Ventures”).

The Generation and Marketing segment primarily consists of Allegheny’s electric generation subsidiaries. These subsidiaries include Allegheny Energy Supply Company, LLC (“AE Supply”), Allegheny Generating Company (“AGC”) and Monongahela’s generation operations. AE Supply owns, operates and controls electric generation capacity and supplies and trades energy and energy-related commodities. AGC owns and sells generation capacity to AE Supply and Monongahela, which own approximately 77% and 23% of AGC, respectively. The Generation and Marketing segment is subject to federal regulation, but is not subject to state regulation of rates, except that Monongahela’s generation is subject to state regulation in West Virginia.

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny. As of December 31, 2005, AESC employed approximately 4,460 employees, of which approximately 1,290 are subject to collective bargaining arrangements.

During the third quarter of 2004, AE and certain of its subsidiaries decided to sell certain non-core assets. The results of operations relating to these assets have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. The assets and liabilities associated with these discontinued operations have been classified as held for sale in the Consolidated Balance Sheets from September 30, 2004 to the date of sale.

On September 30, 2005, Monongahela sold its West Virginia natural gas operations. The results of operations relating to these assets have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. The assets and liabilities associated with these discontinued operations were classified as held for sale in the consolidated balance sheets from September 30, 2004 to the date of sale.

Monongahela completed the sale of its Ohio electric T&D assets to Columbus Southern Power Company (“Columbus Southern”), a subsidiary of American Electric Power, Inc., on December 31, 2005. The results of operations related to the Ohio T&D assets were not reclassified to discontinued operations because the terms of the sale include a power sales agreement under which Monongahela will sell power to Columbus Southern to serve Monongahela’s former Ohio retail customer base through May 31, 2007.

Certain prior period amounts have been reclassified to conform to the financial statement preparation for the current period.

In addition, the accompanying Consolidated Statements of Cash Flows present the cash flows from discontinued operations in each of the three major categories (operating, investing and financing activities). The

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

consolidated statement of cash flows for the year ended December 31, 2004 was revised during 2005 to conform to this presentation. Accordingly, for the year ended December 31, 2004, approximately $13.6 million in cash outflows for capital expenditures of discontinued operations and approximately $3.3 million in cash outflows for debt repayment of discontinued operations were moved from cash flows from operating activities to cash flows of investing and financing activities of discontinued operations, respectively. In addition, approximately $175 million in proceeds from the sales of discontinued operations was moved from the line “proceeds from sale of businesses and assets” to the line “net cash provided by investing activities of discontinued operations” within the same cash flows from investing activities category.

Significant accounting policies of Allegheny are summarized below.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires Allegheny to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a continuous basis, Allegheny evaluates its estimates, including those related to the calculation of the fair value of commodity contracts and derivative instruments, unbilled revenues, goodwill, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Allegheny bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Consolidation

The Consolidated Financial Statements include the accounts of AE and its wholly owned and controlled subsidiaries. All significant intercompany balances and transactions have been eliminated. The Consolidated Financial Statements have been prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of FERC and applicable state regulatory commissions.

Revenues

Revenues from the sale of electricity to customers of the regulated utility subsidiaries are recognized in the period that the electricity is delivered and consumed by customers, including an estimate for unbilled revenues.

Revenues from the sale of generation are recorded in the period in which the electricity is delivered and consumed by customers.

PJM Interconnection, LLC (“PJM”) is a regional transmission organization. Most of the power that Allegheny generates is sold into the PJM market, and most of the power needed to meet the needs of customers of the Distribution Companies is purchased from the PJM market. The majority of PJM purchases and sales are reported on a net basis in “Operating revenues.”

Allegheny records any commodity contract related to energy trading that is a derivative instrument at its fair value as a component of operating revenues, unless the contract falls within the “normal purchases and normal sales” scope exception of SFAS No. 133 or is designated as a hedge for accounting purposes. The normal purchases and normal sales scope exception requires, among other things, physical delivery in quantities

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expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under accrual accounting and, therefore, are not recorded on the balance sheet at fair value. For certain transactions that are designed to hedge the cash flows of a forecasted transaction, the effective portion of the hedge is recorded as a separate component of stockholders’ equity under the caption “Accumulated other comprehensive income (loss)” and subsequently reclassified into earnings when the forecasted transaction is completed or settled. Any ineffective portion of the hedge is immediately reflected in earnings.

Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. Fair values are subject to change in the near term and reflect management’s best estimate based on various factors. In establishing the fair value of commodity contracts that do not have quoted prices, such as physical contracts, over-the-counter options and swaps, management uses available market data and pricing models to estimate fair values. Estimating fair values of instruments which do not have quoted market prices requires management’s judgment in determining amounts which could reasonably be expected to be received from, or paid to, a third party in settlement of the instruments. These amounts could be materially different from amounts that might be realized in an actual sale transaction.

Allegheny has netting agreements with various counterparties, which provide the right to set off amounts due from or to the counterparty. In cases in which these netting agreements are in place, Allegheny records the fair value of commodity contract assets and liabilities and accounts receivable and accounts payable with counterparties on a net basis.

See Note 5, “Derivative Instruments and Hedging Activities,” for additional details regarding energy trading activities.

Unbilled revenues are associated with the Distribution Companies. Energy sales to individual customers are based on their meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of energy delivered to each customer after the last meter reading is estimated, and the Distribution Companies recognize unbilled revenues related to these amounts. The unbilled revenue estimates are based on daily generation, purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses and the most recent consumer rates.

In December 2001, Allegheny entered into an agreement to provide design, construction and installation services for seven natural gas-fired turbine generators for Southern Mississippi Electric Power Association (“SMEPA”). The seven units, with a combined output of approximately 450 MW, will be located at three sites in southern Mississippi. The units will be owned by SMEPA. Construction started in May 2002, and installation of all the units is expected to be completed by May 2006. Revenues from the SMEPA project are recognized under the percentage of completion method. Provisions for estimated losses are made in the period in which such losses are determined.

Revenues from all other activities are recorded in the period during which products or services are delivered and accepted by customers.

Deferred Energy Costs, Net

Historically, the difference between the costs of fuel, purchased energy and certain other costs billed to regulated electric utility customers has been deferred until it is either recovered from or credited to customers under state fuel and energy cost-recovery procedures. With the exception of one power purchase agreement under PURPA that remains subject to a deferred energy cost mechanism in Maryland, however, fuel and

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purchased energy costs for the regulated electric utilities have been expensed as incurred, because the applicable state regulatory bodies eliminated their deferred energy cost mechanisms.

Beginning on January 1, 2005, Maryland commercial and industrial generation rates transitioned to market-based rates. Potomac Edison is authorized by the Maryland PSC to recover the generation component of power sold to customers. An asset or liability is recorded on Potomac Edison’s balance sheet relative to any under-recovery or over-recovery for the generation component of costs charged to Maryland commercial and industrial customers. Deferred energy costs relate to the recovery from or payment to customers related to these generation costs.

Debt Issuance Costs

Costs incurred to issue debt are recorded as deferred charges on the Consolidated Balance Sheets. These costs are amortized over the term of the related debt instrument using the effective interest method.

Property, Plant and Equipment

Regulated Subsidiaries.    Regulated property, plant and equipment are stated at original cost. Cost includes direct labor and materials, allowance for funds used during construction on regulated property for which construction work in progress is not included in rate base and indirect costs, such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes and other benefits related to employees engaged in construction. Upon retirement, the costs of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation with no gain or loss recorded.

Unregulated Subsidiaries.    Unregulated property, plant and equipment are stated at original cost. Gains and losses are recorded on asset dispositions and retirements when such dispositions or retirements occur prior to the estimated useful life of the asset.

Allegheny capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over the expected useful life of the software, beginning upon a project’s completion.

Intercompany Transactions

Common Services.    Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for Allegheny. Each entity is responsible for its proportionate share of the cost of services provided by AESC.

Income Taxes.    AE and its subsidiaries file a consolidated federal income tax return. Federal income tax expense (benefit) and tax assets and liabilities are allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability.

Money Pool.    Allegheny manages excess cash and short-term requirements through an internal money pool. The money pool provides funds to approved AE subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. AE and AE Supply can only lend money into the money pool. Monongahela, West Penn and Potomac Edison can lend money into, or borrow money from, the money pool. AGC can only borrow money from the money pool.

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Power Sales and Purchases.    AE Supply supplies electricity to the Distribution Companies in accordance with agreements approved by FERC to meet the majority of the Distribution Companies’ retail provider-of-last-resort (“PLR”) and other obligations. AE Supply also records ancillary service revenue from the Distribution Companies in accordance with these agreements.

AE Supply and Monongahela purchase all of AGC’s capacity in the Bath County generation facility under a “cost-of-service formula” wholesale rate schedule approved by FERC. AE Supply and Monongahela purchase capacity from AGC on a proportional basis, based on their respective equity ownership of AGC.

Leases.    West Penn and Monongahela own property, including buildings and software, which they lease primarily to AESC for its use in providing services to AE and its affiliates.

Long-Lived Assets

Allegheny’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows. See Note 3, “Discontinued Operations and Assets Held for Sale,” for information related to asset impairment charges recorded during 2005 and 2004.

Allowance for Funds Used During Construction (“AFUDC”) and Capitalized Interest

AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is recognized by Allegheny’s utility subsidiaries as a cost of utility property, plant and equipment. Rates used by the regulated subsidiaries for computing AFUDC in 2005, 2004 and 2003 averaged 6.79%, 7.27% and 8.08%, respectively. Allegheny recorded AFUDC of $2.7 million, $1.9 million and $3.7 million for 2005, 2004 and 2003, respectively.

For non-utility construction, Allegheny capitalizes interest costs. The average interest capitalization rates in 2005, 2004 and 2003 were 7.12%, 7.33% and 7.90%, respectively. Allegheny capitalized $3.1 million, $3.4 million and $15.4 million of interest during 2005, 2004 and 2003, respectively.

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Depreciation and Maintenance

Depreciation expense is determined generally on a straight-line group method over the estimated service lives of depreciable assets for unregulated operations. For regulated utility operations, depreciation expense is determined using a straight-line group method in accordance with currently enacted regulatory rates. Under the straight-line group method, plant components are categorized as “retirement units” or “minor items of property.” As retirement units are replaced, the cost of the replacement is capitalized and the original component is retired. Replacements of minor units of property are expensed as maintenance. Depreciation expense was approximately 2.8% of average depreciable property in 2005, 2004 and 2003. Estimated service lives for generation, T&D and other property are as follows:

	Years
Generation property:
Steam scrubbers and equipment	20-50
Steam generator units	40-75
Internal combustion units	35-40
Hydroelectric dams and facilities	50-121
Transmission and distribution property:
Gas equipment	21-63
Electric equipment	10-65
Easements	75-100
Other property:
Office buildings and improvements	40-60
General office/other equipment	12-25
Vehicles and transportation	7-25
Computers, software and information systems	2-20

The Delivery and Service segment’s depreciation expense was $124.6 million, $120.1 million and $117.7 million for 2005, 2004 and 2003, respectively. The Generation and Marketing segment’s depreciation expense was $152.0 million, $148.0 million and $132.3 million for 2005, 2004 and 2003, respectively.

Maintenance expenses reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily relating to plant outages and storm damage and the replacement of minor items of property. Maintenance costs are expensed as incurred.

Goodwill and Other Intangible Assets

Allegheny records the acquisition cost in excess of fair value of tangible and intangible assets acquired, less liabilities assumed, as goodwill. Allegheny tests goodwill and other intangible assets with indefinite lives for impairment at least annually. Other intangible assets with finite lives are amortized over their useful lives and tested for impairment when events or circumstances warrant.

See Note 8, “Goodwill and Other Intangible Assets” for additional information.

Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates are generally accounted for under the equity method of accounting. The income or loss on such investments is recorded in “other income and expenses, net” in the Consolidated Statements of Operations.

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Cash Equivalents

For purposes of the Consolidated Statements of Cash Flows and Consolidated Balance Sheets, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, repurchase agreements and money market funds, are considered to be the equivalent of cash.

Restricted Funds

Allegheny had restricted funds at December 31, 2005 and 2004 of $21.6 million and $228.9 million, respectively. The restricted funds held at December 31, 2005 were primarily comprised of $16.8 million of Competitive Transition Charges (“CTC”) collected from customers. The restricted funds held at December 31, 2004 were primarily comprised of $198.3 million of cash, which was received at the closing of certain asset sales during December 2004 and used to repay outstanding debt during the first quarter of 2005 and $14.4 million of CTC collected from customers.

Collateral Deposits

Allegheny had collateral deposits at December 31, 2005 and 2004 of $147.8 million and $88.7 million, respectively. These deposits are posted as security with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. These amounts are included in “Current assets” on the Consolidated Balance Sheets.

Allegheny also has funds on deposit with a third party that were posted as collateral for the issuance of surety bonds. These amounts were $41.3 million and $39.1 million at December 31, 2005 and 2004, respectively, and are included in the caption “Other” within “Investments and other assets” on the Consolidated Balance Sheets.

Regulatory Assets and Liabilities

Under cost-based regulation, regulated utility enterprises generally are permitted to recover their operating expenses and earn a reasonable return on their utility investment.

Allegheny accounts for its regulated utility operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs or revenues would be recognized by an unregulated enterprise. Accordingly, Allegheny records assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” Allegheny periodically evaluates the applicability of SFAS No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities.

See Note 14, “Regulatory Assets and Liabilities,” for additional information.

Inventory

Allegheny values materials, supplies and fuel inventory, including emission allowances, using an average cost method.

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Income Taxes

The Company computes income taxes under the liability method. Under the liability method, deferred income taxes are generally determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Net deferred tax assets are recorded when it is more likely than not that such tax benefits will be realized.

Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. Allegheny does not expect that any settlement related to such examination will have a material impact on its consolidated statement of operations, financial position or cash flow.

See Note 9, “Income Taxes,” for additional information.

Pension and Other Postretirement Benefits

Allegheny has noncontributory, defined benefit pension plans covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. Allegheny’s funding policy is to contribute annually to these plans at least the minimum amount required under the Employee Retirement Income Security Act of 1974 (“ERISA”) and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments.

Allegheny’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured. Allegheny does not provide subsidized medical coverage in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees.

Stock-Based Compensation

Allegheny maintains certain stock-based employee compensation arrangements. These arrangements include Allegheny’s Long-Term Incentive Plan (“LTIP”), under which stock option awards, restricted share awards and performance awards may be granted.

Through July 2, 2004, Allegheny recorded compensation expense related to stock units issued to certain of its executive officers using the variable method of accounting. On that date, Allegheny received authorization from the SEC to settle stock units in shares of Allegheny’s common stock as the units vest. Since July 3, 2004, Allegheny has recorded compensation expense relating to stock unit awards using the fixed method of accounting. The amount of this expense was approximately $9.9 million in 2005, $18.7 million in 2004 and $10.6 million in 2003.

Allegheny currently accounts for stock options under the recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. No stock option based compensation expense was recognized in consolidated net income (loss) during 2005, 2004 and 2003, because all options granted had exercise prices equal to the market price of the underlying stock on the date of grant.

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In addition, Allegheny currently follows the disclosure provisions of SFAS No. 148, “Accounting for Stock-Based Compensation Transition and Disclosure, an Amendment of SFAS No. 123.” The following table illustrates the effect on consolidated net income (loss) and income (loss) per share as if Allegheny had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to all stock-based employee compensation:

	Year Ended December 31,
(In millions, except per share data)	2005		2004			2003
Consolidated net income (loss), as reported	$	63.1	$	(310.6	)	$	(355.0	)
Add:
Stock-based employee compensation expense included in consolidated net income (loss), net of related tax effects		6.0		11.3			6.4
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		11.0		16.1			7.8
Consolidated net income (loss), pro forma	$	58.1	$	(315.4	)	$	(356.4	)
Basic income (loss) per share:
As reported	$	0.40	$	(2.40	)	$	(2.80	)
Pro-forma	$	0.37	$	(2.44	)	$	(2.81	)
Diluted income (loss) per share:
As reported	$	0.40	$	(1.83	)	$	(2.80	)
Pro-forma	$	0.36	$	(1.86	)	$	(2.81	)

In December 2004, the FASB issued SFAS 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which revised SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion 25, “Accounting for Stock Issued to Employees,” and its related implementation guidance. SFAS 123R requires that compensation cost relating to all share-based payments to employees, including grants of employee stock options, be recognized in the financial statements based on the fair values of the equity instrument issued. The pro forma disclosures under SFAS 123 will no longer be permitted. SFAS 123R will be effective for Allegheny in the first quarter of 2006 and will apply to all prospective awards, as well as all outstanding unvested share-based payment awards as of January 1, 2006, using the modified prospective transition method without restatement of prior periods. Under the modified prospective transition method, compensation cost for the portion of awards for which the requisite service has not been rendered will be recognized as the requisite service is rendered after January 1, 2006. Allegheny expects to determine the fair value of stock option awards after January 1, 2006 in a manner consistent with the methodology used to illustrate the effect of applying the fair value recognition of SFAS 123 in the table above, and expects that the impact on 2006 will not be materially different from the pro forma effect disclosed above.

See Note 11, “Stock-Based Compensation” for additional information.

Other Comprehensive Income (Loss)

Other comprehensive income (loss) consists of unrealized gains and losses, net of income taxes, from the temporary decline in the fair value of available-for-sale securities, cash flow hedges and the adjustment for the minimum pension liability.

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Recent Accounting Pronouncements

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (“SFAS 153”).    In December of 2004, the FASB issued SFAS 153, which was effective in the third quarter of 2005. Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The amendments made by SFAS 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance, in essence increasing the number of exchanges that will be fair valued in the future. The provisions of SFAS 153 are applied prospectively, and its adoption did not have a material impact on Allegheny’s consolidated results of operations or financial position in 2005.

EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations” (“EITF 03-13”).    In November of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified as held for sale in fiscal periods beginning after December 15, 2004. The adoption of EITF 03-13 did not have a material impact on Allegheny’s consolidated results of operations, cash flows or financial position.

NOTE 2:  CAPITALIZATION

Allegheny’s consolidated capital structure, including short-term debt and debt associated with assets held for sale and excluding minority interest, as of December 31, 2005 and 2004, was as follows:

	2005			2004
(In millions, except percent)	Amount		%	Amount		%
Debt	$	4,101.7	70.5	$	5,012.6	77.8
Common equity		1,695.3	29.1		1,353.8	21.0
Preferred stock of subsidiary		24.0	0.4		74.0	1.2
Total	$	5,821.0	100.0	$	6,440.4	100.0

Common Stock

During 2005 and 2004, AE issued 0.6 million and 0.4 million shares, respectively, of common stock, primarily in connection with matching contributions to its Employee Stock Ownership and Savings Plan (“ESOSP”), stock option exercises and the settlement of stock units.

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During 2005, AE issued 25.0 million shares of its common stock in connection with a tender offer for its $300.0 million in Trust Preferred Securities. See “2005 Debt Activity,” below.

On October 5, 2004, AE sold 10 million shares of its common stock at a price of $15.15 per share directly to institutional investors in a private placement. The proceeds of the sale, and cash on hand, were used to reduce $200 million of debt at AE Supply.

Preferred Stock of Subsidiary

Each share of Monongahela’s preferred stock is entitled, upon voluntary liquidation, to its then current call price and, on involuntary liquidation, to $100 per share.

On October 31, 2005, Monongahela fully redeemed its $50.0 million of outstanding $7.73, Series L ($100 par value) Cumulative Preferred Stock. In connection with the redemption, Monongahela paid accrued and unpaid dividends of approximately $1 million.

Return of Capital

During October 2005, AE received $80.0 million, representing a return of capital from Monongahela, for which Monongahela used a portion of the cash proceeds from the sale of its West Virginia natural gas operations.

Short-term Debt

No short-term debt was outstanding at December 31, 2005 and 2004.

Average short-term debt outstanding during 2005 and 2004 consisted of:

	2005				2004
(In millions)	Amount		Rate		Amount		Rate
Average amount outstanding and interest rate during the year:
Bridge loan at Monongahela	$	—	—	%	$	23.5	4.59	%

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Long-Term Debt

At December 31, 2005, contractual maturities of long-term debt are as follows:

(In millions)	2006			2007			2008			2009			2010			Thereafter			Total
AE:
New AE Credit Facility	$	1.5		$	3.0		$	3.0		$	3.0		$	188.5		$	—		$	199.0
Total AE	$	1.5		$	3.0		$	3.0		$	3.0		$	188.5		$	—		$	199.0
AE Supply:
Pollution Control Bonds	$	—		$	91.7		$	—		$	—		$	—		$	191.4		$	283.1
Medium-Term Notes		—			—			—			—			—			1,050.0			1,050.0
Debentures-AGC		—			—			—			—			—			100.0			100.0
New AE Supply Term Loan		—			6.6			10.7			10.7			10.7			950.3			989.0
Total AE Supply	$	—		$	98.3		$	10.7		$	10.7		$	10.7		$	2,291.7		$	2,422.1
Monongahela:
First Mortgage Bonds	$	300.0		$	—		$	—		$	—		$	—		$	190.0		$	490.0
Pollution Control Bonds		—			15.5			—			—			—			70.2			85.7
Medium-Term Notes		—			—			—			—			110.0			—			110.0
Total Monongahela	$	300.0		$	15.5		$	—		$	—		$	110.0		$	260.2		$	685.7
Potomac Edison:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	320.0		$	320.0
Medium-Term Notes		100.0			—			—			—			—			—			100.0
Total Potomac Edison	$	100.0		$	—		$	—		$	—		$	—		$	320.0		$	420.0
West Penn:
Transition Bonds	$	75.8		$	79.9		$	74.8		$	71.4		$	14.4		$	—		$	316.3
Medium-Term Notes		—			—			—			—			—			80.0			80.0
Total West Penn	$	75.8		$	79.9		$	74.8		$	71.4		$	14.4		$	80.0		$	396.3
AGC:
Debentures	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0
Sub-total	$	477.3		$	196.7		$	88.5		$	85.1		$	323.6		$	3,051.9		$	4,223.1
Unamortized debt discounts, premiums and terminated interest rate swaps		(1.3	)		(1.3	)		(1.2	)		(1.2	)		(1.2	)		(2.4	)		(8.6	)
Eliminations		—			(2.3	)		—			—			—			(110.5	)		(112.8	)
Total consolidated debt	$	476.0		$	193.1		$	87.3		$	83.9		$	322.4		$	2,939.0		$	4,101.7

Certain of Allegheny’s properties are subject to liens of various relative priorities securing debt.

2005 Debt Activity

In April 2005, the holders of $295.0 million of the outstanding $300.0 million in Trust Preferred Securities issued by Allegheny Capital Trust I (“Capital Trust”) accepted AE and Capital Trust’s tender offer and consent solicitation. Under the terms of the offer, for each $1,000 in liquidation amount of Trust Preferred Securities tendered, a holder received 83.33 shares of AE common stock and $160 in cash. On April 22, 2005, AE issued an

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aggregate of 24.6 million shares of its common stock and $47.2 million in cash to the holders of the tendered Trust Preferred Securities. The $47.2 million cash payment was expensed during the second quarter of 2005. In addition, AE received the required consents from holders of the Trust Preferred Securities for amendments to the indenture governing AE’s 11 ⁷/8% Notes due 2008. The holder of the remaining $5.0 million in liquidation amount of Trust Preferred Securities converted its Trust Preferred Securities into 416,650 shares of AE common stock on May 3, 2005.

On June 16, 2005, AE and AE Supply (together, the “Borrowers”) entered into a new $700 million credit facility (the “New AE Credit Facility”) comprised of a $400 million senior unsecured revolving credit facility (the “Revolving Facility”) and a $300 million senior unsecured term loan (the “Term Facility”). The Revolving Facility (a) refinanced the aggregate principal amount of approximately $122 million outstanding under AE’s prior credit facility, (b) continued letters of credit issued under AE’s prior credit facility and (c) provided working capital and letters of credit for AE and, subject to certain limitations, its subsidiaries. The lenders under the Revolving Facility are required to make revolving credit loans to, and issue letters of credit at the request of, AE. In addition, subject to certain limitations, AE Supply may borrow, or request letters of credit for, up to $50 million directly under the Revolving Facility. AE is permitted to request letters of credit in an amount not in excess of $125 million on behalf of AE Supply and its subsidiaries. The Revolving Facility matures June 16, 2010.

On August 1, 2005, AE used the proceeds of the Term Facility to refinance the aggregate principal outstanding amount under AE’s 7.75% Notes due August 1, 2005. AE must repay the principal amount borrowed under the Term Facility in consecutive quarterly installments equal to 0.25% of the aggregate principal amount initially advanced to AE under the Term Facility, with the balance due in full at maturity on June 16, 2010. AE may not re-borrow any part of the Term Facility that it repays or prepays.

Loans under the New AE Credit Facility bear interest, depending on the type of loan requested by the Borrowers, at a rate equal to either (i) the higher of the rate announced publicly by Citibank in New York, from time to time, as Citibank’s base rate or 0.50% above the Federal Funds Rate (as defined in the Credit Agreement) (the “Base Rate”), plus the applicable margin, which is between 1.50% and 0.50% for Base Rate loans, or (ii) the Eurodollar Rate (as defined in the Credit Agreement), plus the applicable margin, which is between 2.50% and 1.50% for Eurodollar Rate-based loans. The applicable margin for LIBOR borrowings was 2.00% at December 31, 2005. On January 18, 2006, the margin for LIBOR borrowings was reduced to 1.50% as a result of increased S&P credit ratings on certain of AE’s debt. With respect to each letter of credit, the relevant Borrower is required to pay to the Administrative Agent a letter of credit fee equal to the applicable margin, which ranges from 2.50% to 1.50%, times the daily maximum amount available to be drawn under such letter of credit. In each case of a Base Rate loan, Eurodollar Rate loan or letter of credit, the applicable margin varies depending upon Standard & Poor’s (“S&P”) and Moody’s Investors Service, Inc.’s (“Moody’s”) ratings of certain of AE’s public debt. The Borrowers’ ability to request and maintain Eurodollar Rate loans is subject to certain limitations.

On July 21, 2005, AE Supply and certain of its subsidiaries entered into a secured term loan facility (the “New AE Supply Term Loan”) of $1.07 billion. The New AE Supply Term Loan matures in 2011 and has an initial interest rate equal to LIBOR plus 1.75%. On January 18, 2006, the margin for LIBOR borrowings was reduced to 1.50% as a result of increased S&P credit ratings on certain of AE Supply’s debt. Proceeds from the New AE Supply Term Loan were used, in part, to refinance approximately $738 million outstanding under the prior AE Supply loan.

Proceeds from the New AE Supply Term Loan were also used on August 22, 2005 to redeem AE Supply’s 10.25% Senior Notes due 2007, which had a principal amount outstanding of approximately $331 million. Also on August 22, 2005, AE Supply used cash on hand to redeem its 13.0% Senior Notes due 2007, which had a

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principal amount outstanding of approximately $35 million. AE Supply expensed premiums and costs associated with the redemption of its 10.25% Senior Notes and 13.0% Senior Notes in the amount of $32.6 million during the three months ended September 30, 2005.

On August 15, 2005, Potomac Edison issued $145 million of 5.125% First Mortgage Bonds due 2015. Approximately $143 million of the proceeds, together with available cash, was used to redeem Potomac Edison’s $65 million of outstanding 7.75% First Mortgage Bonds due 2025 and its $80 million of outstanding 7.625% First Mortgage Bonds due 2025.

On September 27, 2005, WPP Renaissance Funding, LLC, a subsidiary of West Penn issued $115.0 million of 4.46% Transition Bonds, Series 2005-A with an expected maturity of June 2010. These bonds securitize an intangible right to receive a revenue stream from rate payers. Interest on these bonds will accrue and be added to the principal amount of the bonds until the first scheduled interest payment date following final payment of the Transition Bonds, Series 1999-A issued by West Penn Funding LLC, which is expected to occur in June 2008. Thereafter, interest on these bonds will be paid quarterly.

On October 17, 2005, Monongahela issued $70.0 million of 5.375% First Mortgage Bonds due 2015. Monongahela utilized the proceeds and available cash to redeem $70.0 million of its 7 ⁵/8% First Mortgage Bonds due 2025 on November 16, 2005.

On October 31, 2005, Monongahela fully redeemed its $50.0 million of outstanding $7.73, Series L ($100 par value) Cumulative Preferred Stock. Monongahela paid accrued and unpaid dividends of approximately $1 million.

Allegheny made various other debt payments during 2005.

2005 Issuances and Redemptions

The aggregate amount of debt issued, by entity, during 2005 is shown below:

(In millions)	AE		AE Supply		Monongahela		Potomac Edison		West Penn		Total
Prior Credit Facility (a)	$	47.0	$	—	$	—	$	—	$	—	$	47.0
New AE Credit Facility (b)		422.0		—		—		—		—		422.0
New AE Supply Term Loan (c)		—		1,069.0		—		—		—		1,069.0
First Mortgage Bonds		—		—		70.0		145.0		—		215.0
Transition Bonds (d)		—		—		—		—		116.3		116.3
Total	$	469.0	$	1,069.0	$	70.0	$	145.0	$	116.3	$	1,869.3

(a) Reflects issuances under AE’s prior credit facility, which, as discussed above, was refinanced on June 16, 2005.

(b) Reflects issuances under AE’s new revolving credit facility, which, as discussed above, was entered into on June 16, 2005.

(c) Reflects issuances under AE Supply’s new term loan, which, as discussed above, was entered into on July 21, 2005.

(d) Amount includes $1.3 million, representing accrued interest, as discussed above.

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Redemptions of debt, by entity, during 2005 are listed below:

(In millions)	AE		AE Supply		Monongahela		Potomac Edison		West Penn		Total
Convertible Preferred Securities	$	300.0	$	—	$	—	$	—	$	—	$	300.0
Prior Credit Facility (a)		147.0		—		—		—		—		147.0
New AE Credit Facility (b)		223.0		—		—		—		—		223.0
Medium-Term Notes		300.0		380.0		—		—		—		680.0
Prior AE Supply Loan (c)		—		982.1		—		—		—		982.1
New AE Supply Term Loan (d)		—		80.0		—		—		—		80.0
First Mortgage Bonds		—		—		70.0		145.0		—		215.0
Transition Bonds		—		—		—		—		73.0		73.0
Total	$	970.0	$	1,442.1	$	70.0	$	145.0	$	73.0	$	2,700.1
Debt associated with assets held for sale:
Other Notes (e)	$	—	$	—	$	86.7	$	—	$	—	$	86.7

(a) Reflects redemptions under AE’s prior credit facility, which, as discussed above, was refinanced on June 16, 2005.

(b) Reflects redemptions under AE’s new revolving credit facility, which, as discussed above, was entered into on June 16, 2005.

(c) Reflects redemptions under AE Supply’s prior term loan, which, as discussed above, was refinanced on July 21, 2005.

(d) Reflects redemptions under AE Supply’s new term loan, which, as discussed above, was entered into on July 21, 2005.

(e) Represents debt related to Monongahela’s natural gas operations in West Virginia. In connection with the sale of these operations on September 30, 2005, the purchaser assumed this debt.

2004 Debt Activity

On March 8, 2004, AE and AE Supply refinanced approximately $1.7 billion of long-term debt with new loans in an aggregate amount of $1.55 billion. These new loans consisted of secured Term B Loans and a secured Term C Loan (collectively, the “AE Supply Loans”) at AE Supply of $750 million and $500 million, respectively, and unsecured revolving and term loan facilities at AE of $300 million (the “AE Facility” and collectively with the AE Supply Loans, the “Loan Facilities”). On October 28, 2004, AE Supply refinanced the remaining $1.04 billion outstanding under the AE Supply Loan (as refinanced, the “Refinanced AE Supply Loan”). The terms of the Loan Facilities and the Refinanced AE Supply Loan are described below:

AE Supply

• A borrowing facility of $750 million consisting of secured Term B Loans in (a) an aggregate principal amount of $650 million (the “Term B Secured Loan”) and (b) an aggregate principal amount of $100 million (the “Term B Springdale Loan”). The Term B Secured Loan and the Term B Springdale Loan are collectively referred to as the (“Term B Loans”).

Provided that AE Supply meets certain requirements listed in the loan documents, including, but not limited to, ensuring that all covenants are maintained on a pro-forma basis and sufficient liens on collateral can be granted, AE Supply may request an increase in the principal amount under the Term B Secured Loan up to $200 million. Any increased amounts would amortize over the remaining term of the Term B Loans.

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The Term B Loans bore interest at AE Supply’s option at either the London Interbank Offering Rate (“LIBOR”) plus a margin of 3.0% per annum or at a base lending rate plus a margin of 2.0% per annum, depending on AE Supply’s then current credit rating as provided by Standard and Poor’s (“S&P”) and Moody’s Investor Services (“Moody’s”).

The Term B Loans required repayments under a schedule providing for quarterly installments in an annual amount equal to one percent of the Term B Loans outstanding, with the balance payable on March 8, 2011.

• A borrowing facility with an aggregate principal amount of $500 million (the “Term C Loan”).

The Term C Loan bore interest at AE Supply’s option at either LIBOR plus a margin of 4.25% per annum or at a base lending rate plus a margin of 3.25% per annum, depending on AE Supply’s then current credit rating as provided by S&P and Moody’s.

On October 28, 2004, AE Supply refinanced the remaining $1.04 billion outstanding under the AE Supply Loans. In connection with the refinancing of the AE Supply Loans, the Term B Loans and the Term C Loan were consolidated into the Refinanced AE Supply Loan. The Refinanced AE Supply Loan bore interest at a rate per annum equal to LIBOR plus 2.75%. Following the repayment of $200 million on January 14, 2005, the per annum interest rate on the Refinanced AE Supply Loan was reduced to LIBOR plus 2.50%. The Refinanced AE Supply Loan will mature on March 8, 2011.

The AE Supply Loans contained financial covenants, including a minimum interest coverage ratio and a maximum debt to EBITDA ratio (as defined). Other covenants included: limitations on the incurrence of debt, guarantees or other contingent obligations; creation of liens; entering into leases; mergers and consolidations; sales, transfers or other dispositions of assets; making of loans or investments; capital expenditures; making restricted payments or distributions; speculative transactions; transactions with affiliates and prepayments or redemptions of other debt. The AE Supply Loans also contained provisions requiring mandatory prepayments with specified percentages of excess cash flow (as defined) and the net proceeds of certain asset sales, 50% of the net cash proceeds from the issuance of equity securities and 100% of the net cash proceeds from the issuance of debt securities, with certain exceptions. The Refinanced AE Supply Loan contains similar covenants.

The Refinanced AE Supply Loan is secured pari passu with the Amended A-Notes (as defined below) by a first priority perfected pledge of substantially all of the assets of AE Supply.

AE

• The AE Facility is an unsecured borrowing facility of up to an aggregate amount of $300 million. The AE Facility is comprised of a $200 million revolving credit sub-facility, $100 million of which is available for the issuance of letters of credit, and a $100 million term loan.

The full amount of all borrowings is required to be repaid by March 8, 2007.

Interest on borrowings under the AE Facility are at AE’s option at either LIBOR plus a margin of 2.5% to 3.0% per annum, depending on AE’s then current credit rating as provided by S&P and Moody’s, or an applicable bank lending base rate plus a margin of 1.5% to 2.0% per annum, depending on AE’s then current credit rating as provided by S&P and Moody’s.

The AE Facility carries an unused commitment fee of 0.5% per annum and letter of credit fees comprised of a fronting fee of 0.35% and an additional annual fee of 2.5% to 3.0% on the face amount of outstanding letters of credit, depending on AE’s then current credit rating as provided by S&P and Moody’s.

The AE Facility contains financial covenants, including a minimum interest coverage ratio and a maximum debt to EBITDA ratio (as defined). Other covenants include limitations on: incurrence of debt, guarantees or

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other contingent obligations; creation of liens, entering into leases; mergers and consolidations; sales, transfers or other dispositions of assets; making loans or investments; capital expenditures; making restricted payments or distributions; creating dividend restrictions on subsidiaries; speculative transactions; transactions with affiliates and prepayments or redemptions of other debt of AE or its subsidiaries.

The AE Facility also contains provisions requiring mandatory prepayments with all of the net cash proceeds of asset sales after the first $100 million, subject to certain exceptions. Mandatory prepayments of the AE Facility generally will be applied first to repay the term loan, then to repay borrowings for letters of credit and then to repay amounts outstanding under the revolving credit sub-facility.

In June 2004, Monongahela issued $120 million of 6.70% First Mortgage Bonds, which mature on June 15, 2014. The net proceeds of the bond issuance were used to repay Monongahela’s $53.6 million short-term bridge loan in June 2004 and to fund the July 2004 redemption of $40 million of 8.375% First Mortgage Bonds due 2022 and $25 million of 7.25% First Mortgage Bonds due 2007. Interest on the 6.70% First Mortgage Bonds is payable semi-annually in arrears on each June 15 and December 15, commencing December 15, 2004. The bonds are redeemable at Monongahela’s option and rank equally in right of payment with its existing or future first mortgage bonds.

In November 2004, Potomac Edison issued $175 million of 5.35% First Mortgage Bonds, which mature on November 15, 2014. The net proceeds of the bond issuance were used to fund the December 2004 redemption of $55.0 million of 8.0% First Mortgage Bonds due 2022, $45.0 million of 7.75% First Mortgage Bonds due 2023 and $75.0 million of 8.0% First Mortgage Bonds due 2024. Interest on the 5.35% First Mortgage Bonds is payable semi-annually in arrears on each May 15 and November 15, commencing May 15, 2005. The bonds are redeemable at Potomac Edison’s option and rank equally in right of payment with its existing or future unsubordinated debt.

2004 Issuances and Redemptions

The aggregate amount of debt issued, by entity, during 2004 is shown below:

(In millions)	AE		AE Supply		Monongahela		Potomac Edison		Total
AE Supply Loans	$	—	$	1,250.0	$	—	$	—	$	1,250.0
Refinanced AE Supply Loan		—		1,043.7		—		—		1,043.7
AE Facility		225.0		—		—		—		225.0
First Mortgage Bonds		—		—		120.0		175.0		295.0
Borrowing Facilities		—		28.3		—		—		28.3
Total	$	225.0	$	2,322.0	$	120.0	$	175.0	$	2,842.0

Redemptions of indebtedness, by entity, during 2004 are listed below:

(In millions)	AE		AE Supply		Monongahela		Potomac Edison		West Penn		Total
Borrowing Facilities	$	257.0	$	1,407.8	$	—	$	—	$	—	$	1,664.8
AE Supply Loans		—		1,250.0		—		—		—		1,250.0
Refinanced AE Supply Loan		—		61.6		—		—		—		61.6
First Mortgage Bonds		—		—		65.0		175.0		—		240.0
AE Facility		125.0		—		—		—		—		125.0
Medium-Term Notes		—		—		—		—		84.0		84.0
Transition Bonds		—		—		—		—		73.7		73.7
Short-term Debt		—		—		53.6		—		—		53.6
Total	$	382.0	$	2,719.4	$	118.6	$	175.0	$	157.7	$	3,552.7

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NOTE 3:  DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

During the third quarter of 2004, Allegheny and certain of its subsidiaries decided to sell certain non-core assets. The results of operations relating to these assets have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. In addition, the assets and liabilities associated with these discontinued operations have been classified as held for sale in the consolidated balance sheets through the dates on which the sales concluded.

The components of income (loss) from discontinued operations are as follows:

(In millions)	2005			2004			2003
AE Supply:
Operating revenues	$	0.4		$	29.3		$	21.3
Operating expenses		7.2			(28.1	)		(46.1	)
Interest expense		(10.2	)		(27.3	)		(29.8	)
Loss before income taxes		(2.6	)		(26.1	)		(54.6	)
Income tax benefit		2.6			2.5			20.1
Gain from disposal of discontinued operations, net of tax		—			1.1			—
Impairment charge, net of tax		(7.2	)		(403.9	)		—
Loss from discontinued operations, net of tax	$	(7.2	)	$	(426.4	)	$	(34.5	)
Monongahela:
Operating revenues	$	218.1		$	306.4		$	268.8
Operating expenses		(201.6	)		(285.2	)		(246.2	)
Other income		1.0			0.2			0.5
Interest expense		(6.1	)		(8.3	)		(8.7	)
Income before income taxes		11.4			13.1			14.4
Income tax expense		(3.4	)		(5.3	)		(5.2	)
Impairment charge, net of tax		(7.0	)		(21.7	)		—
Income (loss) from discontinued operations, net of tax	$	1.0		$	(13.9	)	$	9.2
Consolidated:
Operating revenues	$	218.5		$	335.7		$	290.1
Operating expenses		(194.3	)		(313.3	)		(292.3	)
Other income		1.0			0.2			0.5
Interest expense		(16.3	)		(35.6	)		(38.5	)
Income (loss) before income taxes		8.9			(13.0	)		(40.2	)
Income tax benefit (expense)		(0.8	)		(2.8	)		14.9
Gain from disposal of discontinued operations, net of tax		—			1.1			—
Impairment charge, net of tax		(14.2	)		(425.6	)		—
Loss from discontinued operations, net of tax	$	(6.1	)	$	(440.3	)	$	(25.3	)

Impairment charges, reflected in the table above, represent adjustments of the carrying values of assets held for sale to current estimates of sales proceeds, less costs to sell.

During 2005, AE Supply recorded net impairment charges related to its Wheatland and Gleason generating facilities of $9.1 million ($7.2 million, net of income taxes), representing adjustments of the carrying values of assets held for sale to estimated sales proceeds, less costs to sell.

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During 2005, Monongahela recorded impairment charges related to its natural gas operations in West Virginia of $11.9 million ($7.0 million, net of income taxes), representing adjustments of the carrying values of assets held for sale to estimated sales proceeds, less costs to sell.

During 2004, Monongahela recorded a charge against earnings to write-down its investment in its West Virginia natural gas operations to the expected net proceeds from the sale of these assets. The write-down resulted in a charge against earnings of $36.7 million ($21.7 million, net of income taxes).

During the third quarter of 2004, AE Supply recorded a charge against earnings to write-down its investment in its Lincoln generating facility to the expected net proceeds from the sale. The write-down resulted in a charge against earnings of $209.4 million ($129.2 million, net of income taxes). Also during the third quarter of 2004, AE Supply recorded write-downs to fair value of its Wheatland generating facility and the Gleason generating facilities, as a result of its decision to sell these facilities. These write-downs resulted in an aggregate charge against earnings of $445.4 million, ($274.7 million, net of income taxes).

Assets held for sale and liabilities associated with assets held for sale, all of which relate to AE Supply, at December 31, 2005 were as follows:

(In millions)	Consolidated
Assets:
Current assets	$	1.5
Property, plant and equipment		23.1
Deposit		25.5
Total assets	$	50.1

Assets held for sale and liabilities associated with assets held for sale at December 31, 2004 were as follows:

(In millions)	Monongahela		Potomac Edison		AE Supply		Eliminations			Consolidated
Assets:
Current assets	$	147.8	$	—	$	2.2	$	—		$	150.0
Property, plant and equipment		163.7		10.8		128.3		—			302.8
Investments and other assets		6.8		—		—		—			6.8
Deferred charges		6.3		—		—		(0.5	)		5.8
Deposit		—		—		25.0		—			25.0
Total assets	$	324.6	$	10.8	$	155.5	$	(0.5	)	$	490.4
Liabilities:
Current liabilities	$	95.5	$	—	$	—	$	(58.0	)	$	37.5
Long-term debt		83.4		—		—		—			83.4
Deferred credits and other liabilities		17.6		—		—		(11.6	)		6.0
Total liabilities	$	196.5	$	—	$	—	$	(69.6	)	$	126.9

See Note 4, “Asset Sales,” for additional information.

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NOTE 4:  ASSET SALES

On December 31, 2005, Monongahela completed the sale of its Ohio electric T&D assets to Columbus Southern for net cash proceeds of $51.8 million. The purchase price for the assets was the net book value at the time of closing, plus $10.0 million, less certain property taxes. The sale included a power sales agreement under which Monongahela will provide power to Columbus Southern to serve Monongahela’s former Ohio retail customer base through May 31, 2007 at $45 per megawatt-hour, which is less than the projected market price for power. Monongahela recorded a loss on the sale in the amount of $29.3 million based, in part, on the estimated fair value at December 31, 2005 of its agreement to provide power at below-market prices through May 31, 2007.

The results of operations relating to the Ohio electric T&D assets were not included in discontinued operations because the terms of the sale include a power sales agreement under which Monongahela will sell power to the purchaser for Monongahela’s Ohio retail customer base from the time of closing through May 31, 2007.

On September 30, 2005, Monongahela completed the sale of its natural gas operations in West Virginia to Mountaineer Gas Holdings Limited Partnership, a partnership composed of IGS Utilities LLC, IGS Holdings LLC and affiliates of ArcLight Capital Partners, LLC, for approximately $161.0 million in cash and the assumption of approximately $87.0 million of long-term debt. The assets sold included all of the issued and outstanding capital stock of Mountaineer Gas and certain other assets related to the West Virginia natural gas operations.

On August 12, 2005, AE Supply and its subsidiaries, Allegheny Energy Supply Wheatland Generating Facility, LLC and Lake Acquisition Company, LLC completed the sale of certain assets relating to AE Supply’s Wheatland generating facility (the “Wheatland Assets”) to PSI Energy, Inc. and The Cincinnati Gas & Electric Company for approximately $100 million and the assumption of certain liabilities related to the Wheatland Assets.

During May 2005, Potomac Edison completed the sale of its Hagerstown, Maryland property for $10.6 million in net cash proceeds.

On December 31, 2004, AE completed the sale of a 9% equity interest in the Ohio Valley Electric Corporation (“OVEC”) to Buckeye Power Generating, LLC (“Buckeye”). In addition, AE Supply assigned to Buckeye all of its rights and obligations under the Amended and Restated OVEC Inter-Company Power Agreement (the “New ICPA”) effective March 13, 2006. The aggregate purchase price for the equity sale by AE and the assignment of AE Supply’s rights in the New ICPA was $102 million. AE Supply will retain its rights to 9% of the power from the OVEC electric generation facility through March 12, 2006. The sale resulted in a gain of $94.8 million, before income taxes ($60.0 million, net of income taxes), which is recorded in “Gain on sale of OVEC power agreement and shares” on the Consolidated Statements of Operations. AE recorded a gain of $6.2 million, before income taxes ($4.0 million, net of income taxes), and AE Supply recorded a gain of $88.6 million, before income taxes ($56.0 million, net of income taxes). Cash proceeds from the sale were $102.0 million, of which $6.0 million is expected to be received in April 2006 upon the fulfillment of certain post-closing obligations. The remaining $96.0 million in proceeds was used to reduce debt in the first quarter of 2005.

In December 2004, AE Supply sold its 672 MW Lincoln generating facility, in Manhattan, Illinois, together with an associated tolling agreement, to an affiliate of ArcLight Capital Partners, LLC. Cash proceeds from the sale were $175.0 million, which were used to reduce debt.

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NOTE 5:  DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Allegheny records any commodity contract related to energy trading that is a derivative instrument at its fair value as a component of operating revenues, unless the contract falls within the “normal purchases and normal sales” scope exception of SFAS No. 133 or is designated as a hedge for accounting purposes. The normal purchases and normal sales scope exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under accrual accounting and, therefore, are not recorded on the balance sheet at fair value. For certain transactions that are designed to hedge the cash flows of a forecasted transaction, the effective portion of the hedge is recorded as a separate component of stockholders’ equity under the caption “Accumulated other comprehensive income (loss)” and subsequently reclassified into earnings when the forecasted transaction is completed or settled. Any ineffective portion of the hedge is immediately reflected in earnings.

Fair values for exchange-traded instruments, principally futures and certain options, are based on quoted market prices. In establishing the fair value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options and swaps, management makes estimates using available market data and pricing models. Factors such as commodity price risk, operational risk and credit risk of counterparties are evaluated in establishing the fair value of commodity contracts. The commodity contracts include certain financial instruments, such as interest rate swaps, which are used to mitigate the effect of interest rate changes.

Allegheny had unique contracts due to their long-term nature and terms that were valued using proprietary pricing models prior to 2004. Exposure to these types of contracts has declined significantly as a result of AE Supply’s exit from the Western U.S. energy markets. Inputs to the models included estimated forward natural gas and power prices, interest rates, estimates of market volatility for natural gas and power prices and the correlation of natural gas and power prices. These inputs depended heavily on judgments and assumptions by management. Approximately $0.7 million and $1.4 million of Allegheny’s contracts were valued using “prices based on models” at December 31, 2005 and 2004, respectively.

AE Supply has designated certain contracts as cash flow hedges. The first contracts were designated effective July 1, 2004 and were related to legacy “mark to market” contracts that are anticipated to be serviced by excess generation. These contracts expire at various dates through December 31, 2006. During the third quarter 2005, additional contracts were executed and designated as cash flow hedges to lock in prices for a portion of anticipated excess generation for the period October 2005 through April 2006.

Changes in the fair value of these contracts are reflected in “accumulated other comprehensive income (loss)” in the Consolidated Balance Sheets. For the contracts designated as cash flow hedges on July 1, 2004, the existing derivative liabilities associated with each contract as of that designation date will be recognized in earnings over the remaining term of the contract, in accordance with the estimated cash flow of the contract at the time of the designation. The contracts designated as cash flow hedges represent an aggregate liability at December 31, 2005 and 2004 of $69.7 million and $31.1 million, respectively. The $38.6 million increase in this liability since December 31, 2004 is a result of the change in the fair value of contracts, which is due to changes in market prices and contract settlements during 2005. The accumulated other comprehensive loss balance at December 31, 2005 and 2004 was $50.4 million and $3.3 million, respectively. The $47.1 million increase in accumulated other comprehensive loss since December 31, 2004 is a result of the change in the fair value of contracts, which is primarily due to changes in market prices. Based on the fair value of AE Supply’s financial instruments as of December 31, 2005, accumulated other comprehensive loss of $50.4 million is expected to be reclassified as a reduction in earnings over the next twelve months. The ineffective portion of the cash flow hedges, $1.1 million, is reflected in earnings for 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Net unrealized gains (losses) of $20.6 million, $(5.7) million and $(468.4) million, before income taxes, for 2005, 2004 and 2003, respectively, were recorded in “Operating revenues.” These net unrealized gains (losses) were recorded to reflect the change in fair value of the trading contracts.

In June 2002, EITF 02-3 was issued. EITF 02-3 requires that mark-to-market gains and losses on energy trading contracts (whether realized or unrealized) be shown net in the Consolidated Statements of Operations. During 2002, Allegheny modified its reporting as a result of EITF 02-3 to reflect the revenues from energy trading activities, net of the cost of purchased power and transmission, related to contracts that require physical delivery. In connection with its implementation of EITF 02-3, AE Supply recorded a loss as a cumulative effect of an accounting change of approximately $19.7 million, before income taxes ($12.2 million, net of income taxes), in the first quarter of 2003. This charge represented the fair value of those contracts previously accounted for under EITF Issue No. 98-10 that no longer qualify for mark-to-market accounting.

Strategy Change in 2003

Allegheny worked throughout 2003 to accomplish AE Supply’s exit from the Western U.S. energy markets, as well as other speculative trading positions. AE Supply’s positions based in the Western U.S. had been a substantial source of earnings and cash flow volatility and risk, and trading in these markets did not fit with Allegheny’s intentions to focus on its core business.

Renegotiation and Sale of the CDWR Contract

In June 2003, AE Supply entered into a settlement agreement with the State of California to resolve the state’s litigation regarding its power supply contract with the California Department of Water Resources (“CDWR”). The terms of the settlement reduced the volume of power to be delivered from 2005 through 2011 and reduced the sale price of off-peak power to be delivered from 2004 through 2011, which in turn substantially reduced the value of the contract. On September 15, 2003, AE Supply and its subsidiary, Allegheny Trade Finance (“ATF”), sold the CDWR contract and associated hedge transactions, to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc., for approximately $354 million. Allegheny applied $214 million of the sale proceeds to required payments under agreements entered into to terminate tolling agreements with Williams Energy Marketing & Trading Company (“Williams”) and Las Vegas Cogeneration II, LLC (“LV Cogen”), a unit of Black Hills Corporation, as described below. Allegheny applied an additional $28 million of the proceeds to make required payments in March and September of 2004 under the agreement with Williams. Approximately $71 million of the sale proceeds were placed in escrow for the benefit of J. Aron & Company, pending Allegheny’s fulfillment of certain post-closing requirements. On March 3, 2004, the funds were released from escrow, which resulted in the recognition of a gain of approximately $68 million in the first quarter of 2004, and approximately $3 million in the third quarter of 2005 as a result of a resolution of a guarantee.

During 2003, AE Supply exited the Western U.S. energy trading markets, including all related contracts and hedge agreements. As a result, Allegheny recorded a net loss of approximately $535.2 million. This loss was recorded as a component of “Operating revenues” in the Consolidated Statements of Operations. This loss did not include the approximately $71 million of proceeds from the sale of the CDWR contract that were placed in escrow, as described above.

Refocusing Trading Activities

Following its exit from the Western U.S. energy markets during 2003, AE Supply has concentrated its efforts in the PJM and Mid-Atlantic markets and has reoriented its trading operations from high-volume financial trading in national markets to asset optimization and hedging within its region.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 6:  ASSET RETIREMENT OBLIGATIONS (“ARO”)

Effective January 1, 2003, Allegheny adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS No. 143 requires that the fair value of asset retirement costs for which Allegheny has a legal obligation be recorded as liabilities, with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an unregulated company settles the obligation for its recorded amount or records a gain or loss if it is settled at a different amount. Allegheny recorded AROs primarily related to ash landfills and above and below ground storage tanks.

The effect of adopting SFAS No. 143 on Allegheny’s Consolidated Financial Statements in 2003 was as follows:

	Effect of Adopting SFAS No. 143 Increase (Decrease)
(In millions)	Property, Plant and Equipment, Net		Non-Current Regulatory Asset		Non-Current Liabilities (AROs)		Decrease in Pre-Tax Income			Decrease in Net Income
AE Supply	$	0.3	$	—	$	12.2	$	(11.9	)	$	(7.4	)
Monongahela		3.0		2.3		6.1		(0.8	)		(0.4	)
Potomac Edison		0.1		—		0.2		(0.1	)		(0.1	)
West Penn		—		—		1.2		(1.2	)		(0.7	)
Total Allegheny	$	3.4	$	2.3	$	19.7	$	(14.0	)	$	(8.6	)

Effective December 31, 2005, Allegheny adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations (“Conditional AROs”)” which requires an entity to recognize a liability for the fair value of a Conditional ARO if the fair value of the liability can be reasonably estimated. The obligation to perform the asset retirement activity for a Conditional ARO is unconditional, even though uncertainty exists about the timing and (or) method of settlement.

Allegheny recorded Conditional AROs related to asbestos contained in its generating facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”). The effect of adopting FIN 47 on Allegheny’s Consolidated Financial Statements in 2005 was as follows:

	Effect of Adopting FIN No. 47 Increase (Decrease)
(In millions)	Property, Plant and Equipment, Net		Non-Current Regulatory Asset		Non-Current Liabilities (Conditional AROs)		Decrease in Pre-Tax Income			Decrease in Net Income
AE Supply	$	0.5	$	—	$	9.8	$	(9.3	)	$	(5.9	)
Monongahela		0.3		5.3		5.6		—			—
Potomac Edison		—		0.3		0.4		—			—
West Penn		—		0.4		0.4		—			—
Total Allegheny	$	0.8	$	6.0	$	16.2	$	(9.3	)	$	(5.9	)

Under the rate-making process, regulators generally permit recovery of costs associated with removing property, plant and equipment. Allegheny believes it is probable that any difference between expenses recorded under SFAS No. 143 and FIN 47 and expenses recovered currently in rates with respect to these assets will be recoverable in future rates. Therefore, Allegheny is deferring these differences in expenses as a regulatory asset.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For 2005, Allegheny’s total ARO balance, which includes both AROs and Conditional AROs, increased $20.0 million, from $28.8 million at December 31, 2004 to $48.8 million at December 31, 2005. This increase was primarily due to $16.2 million of certain Conditional ARO liabilities associated with the adoption of FIN 47 and $3.8 million of accretion expense, which Allegheny recorded in 2005.

As of December 31, 2003, Allegheny’s regulated utility subsidiaries reclassified the removal costs collected from customers related to assets that do not have associated retirement obligations under SFAS No. 143 in “Regulatory assets,” “Regulatory liabilities” and/or “Other current liabilities” on its Consolidated Balance Sheets. These estimated removal costs, which represent a regulatory liability (asset), are as follows:

(In millions)	December 31, 2005			December 31, 2004
Monongahela	$	242.1		$	241.8
Potomac Edison		170.8			162.3
West Penn		(17.4	)		(17.2	)
Total	$	395.5		$	386.9

Had the provisions of FIN 47 been adopted on January 1, 2003, Allegheny’s loss before cumulative effect of accounting changes and net loss would have changed as follows (per share amounts would not have changed):

	Year Ended December 31,
(In millions)	2004			2003
Loss before cumulative effect of accounting changes:
As reported	$	(310.6	)	$	(334.2	)
As adjusted		(311.0	)		(334.6	)
Net loss:
As reported		(310.6	)		(355.0	)
As adjusted		(311.0	)		(355.4	)

Had the provisions of FIN No. 47 been adopted on January 1, 2003, Allegheny’s ARO liability would have been $14.3 million at January 1, 2004 and $15.2 million at December 31, 2004.

NOTE 7:  BUSINESS SEGMENTS

Allegheny manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. Monongahela operates in both segments. All other Allegheny subsidiaries operate in only one segment. The Delivery and Services segment includes the operations of Potomac Edison, West Penn, Allegheny Ventures and Monongahela’s electric T&D business. The Generation and Marketing segment includes the operations of AE Supply, AGC and Monongahela’s West Virginia generating assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Business segment information for Allegheny is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts.

(In millions)	2005			2004			2003
Operating revenues:
Delivery and Services	$	2,845.5		$	2,764.1		$	2,705.8
Generation and Marketing		1,703.3			1,538.7			956.2
Eliminations		(1,510.9	)		(1,546.7	)		(1,479.7	)
Total	$	3,037.9		$	2,756.1		$	2,182.3
Depreciation and amortization:
Delivery and Services	$	153.6		$	148.8		$	152.2
Generation and Marketing		154.6			150.6			134.0
Total	$	308.2		$	299.4		$	286.2
Operating income (loss):
Delivery and Services	$	266.5		$	303.3		$	263.4
Generation and Marketing		270.3			285.9			(459.9	)
Total	$	536.8		$	589.2		$	(196.5	)
Interest expense:
Delivery and Services	$	120.6		$	125.9		$	123.8
Generation and Marketing		316.8			274.5			299.0
Eliminations		(1.0	)		(0.2	)		—
Total	$	436.4		$	400.2		$	422.8
Income (loss) from continuing operations, net:
Delivery and Services	$	112.2		$	117.3		$	102.6
Generation and Marketing		(37.0	)		12.5			(411.5	)
Eliminations		(0.1	)		(0.1	)		—
Total	$	75.1		$	129.7		$	(308.9	)
Income (loss) from discontinued operations, net:
Delivery and Services	$	1.0		$	(14.0	)	$	9.2
Generation and Marketing		(7.2	)		(426.4	)		(34.5	)
Eliminations		0.1			0.1			—
Total	$	(6.1	)	$	(440.3	)	$	(25.3	)
Cumulative effect of accounting changes, net:
Delivery and Services	$	—		$	—		$	(1.2	)
Generation and Marketing		(5.9	)		—			(19.6	)
Total	$	(5.9	)	$	—		$	(20.8	)
Net income (loss):
Delivery and Services	$	113.2		$	103.3		$	110.6
Generation and Marketing		(50.1	)		(413.9	)		(465.6	)
Total	$	63.1		$	(310.6	)	$	(355.0	)
Capital expenditures:
Delivery and Services	$	184.8		$	160.5		$	149.2
Generation and Marketing		121.7			107.0			107.7
Total	$	306.5		$	267.5		$	256.9
Acquisition of businesses:
Delivery and Services	$	—		$	—		$	—
Generation and Marketing		—			—			318.4
Total	$	—		$	—		$	318.4
Identifiable assets:
Delivery and Services	$	4,057.6		$	4,443.8
Generation and Marketing		4,031.8			4,349.1
Other		916.2			782.1
Eliminations		(446.8	)		(529.9	)
Total	$	8,558.8		$	9,045.1

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 8:  GOODWILL AND OTHER INTANGIBLE ASSETS

The recorded goodwill of $367.3 million at December 31, 2005 and 2004 was attributable to the Generation and Marketing segment. There were no additions to, or disposals of, goodwill during 2005 and 2004. Goodwill and other intangible assets with indefinite lives are not amortized. Instead, they are tested annually for impairment, with impairment losses recognized in operating income. Absent any impairment indicators, Allegheny performs its annual impairment tests during its third quarter in connection with its annual budgeting process. The annual impairment test used a discounted cash flow methodology to determine the fair value of the Generation and Marketing segment and indicated no impairment of goodwill.

Intangible assets of $27.4 million and $33.2 million as of December 31, 2005 and 2004, respectively, related to an additional minimum pension liability, as discussed in Note 10, “Pension Benefits and Postretirement Benefits Other Than Pensions.”

Additional intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:

	December 31, 2005				December 31, 2004
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Land easements, amortized	$	97.7	$	27.1	$	96.5	$	25.8
Land easements, unamortized		30.6		—		31.8		—
Software		72.3		50.9		82.7		55.8
Total	$	200.6	$	78.0	$	211.0	$	81.6

In addition, “Assets held for sale” included intangible assets related to natural gas rights, amortized, with a gross carrying amount and accumulated amortization of $8.4 million and $4.9 million, respectively, at December 31, 2004.

Amortization expense for intangible assets was $15.3 million, $19.1 million and $23.0 million for 2005, 2004 and 2003, respectively.

Amortization expense for intangible assets is estimated to be as follows:

(In millions)	2006		2007		2008		2009		2010
Annual amortization expense	$	13.0	$	12.5	$	10.3	$	9.9	$	8.6

NOTE 9:  INCOME TAXES

Details of federal and state income tax expense (benefit) from continuing operations are as follows:

(In millions)	2005			2004			2003
Income tax expense (benefit)—current:
Federal	$	55.2		$	88.7		$	(76.4	)
State		(6.5	)		10.0			(2.9	)
Total		48.7			98.7			(79.3	)
Income tax expense (benefit)-deferred, net		22.4			(12.5	)		(116.6	)
Amortization of deferred investment tax credit		(6.3	)		(6.5	)		(6.3	)
Total income tax expense (benefit)	$	64.8		$	79.7		$	(202.2	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Taxable income differs from pre-tax accounting income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using enacted tax rates in effect in the years in which the differences are expected to reverse.

During the second quarter of 2005, Allegheny determined that it had not claimed certain income tax deductions in its 2003 income tax returns relating to commodity trading contracts. Allegheny filed a claim for these additional deductions, which increased Allegheny’s recorded tax net operating loss carryforwards in the amount of approximately $210 million and decreased other recorded deferred tax assets in a similar amount, except for certain state income tax effects. Allegheny recorded a charge of $3.8 million during the second quarter of 2005 to write-off state deferred tax assets that will not be realized due to state limitations on the use of net operating loss carryforwards resulting from the filing of this claim. The effect of this adjustment was not material to Allegheny’s results of operations for the years ended December 31, 2005 and 2003.

On June 30, 2005, the state of Ohio enacted broad changes to its business tax system including a phase-out of the state’s income-based franchise tax over a five-year period beginning in 2006. The phase-out of the franchise tax will reduce the benefit of recorded tax assets by $1.9 million, and deferred tax assets were written down by this amount in the second quarter of 2005. The franchise tax has been replaced by a gross receipts tax that will be phased-in over a five year period beginning July 1, 2005.

Allegheny also recorded a $6.9 million charge during the fourth quarter of 2005 to decrease recorded deferred tax assets on deferred compensation due to changes in the timing of payments permitted under the American Jobs Creation Act of 2004.

Investment tax credits have been deferred and are being amortized over the estimated service lives of the related property, plant and equipment.

The total income tax expense (benefit) from continuing operations differs from the amount produced by applying the federal statutory income tax rate of 35% to income (loss) from continuing operations before income taxes and minority interest, as set forth below:

	2005					2004					2003
(In millions, except percent)	Amount			%		Amount			%		Amount			%
Income (loss) from continuing operations before income taxes and minority interest	$	140.5				$	208.5				$	(518.2	)
Preferred dividend of subsidiary		4.1					5.0					5.0
Subtotal		144.6					213.5					(513.2	)
Income tax expense (benefit) calculated using the federal statutory rate of 35%		50.6		35.0			74.7		35.0			(179.6	)	35.0
Increases (reductions) resulting from:
Tax deductions for which deferred tax was not provided:
Depreciation		7.5		5.2			0.5		0.2			11.7		(2.3	)
Plant removal costs		(1.9	)	(1.3	)		(2.2	)	(1.0	)		(3.9	)	0.8
State income tax, net of federal income tax benefit		7.2		5.0			7.6		3.5			(17.6	)	3.4
Amortization of deferred investment tax credit		(6.3	)	(4.3	)		(6.5	)	(3.0	)		(6.3	)	1.2
Reduction in tax benefits for deferred compensation		6.0		4.1			—		—			—		—
Reapplication of SFAS No. 71		—		—			—		—			(9.7	)	1.9
Other, net		1.7		1.1			5.6		2.6			3.2		(0.6	)
Total income tax expense (benefit)	$	64.8		44.8		$	79.7		37.3		$	(202.2	)	39.4

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The income tax benefit for loss from discontinued operations differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount as set forth below:

(In millions)	2005			2004			2003
Loss from discontinued operations, before income taxes	$	(12.1	)	$	(702.6	)	$	(40.2	)
Income tax benefit calculated using the federal statutory rate of 35%	$	4.2		$	245.9		$	14.0
Increased for state income tax benefit, net of federal income tax expense		1.7			16.4			0.8
Total income tax benefit	$	5.9		$	262.3		$	14.8

The income tax benefit for the cumulative effect of accounting changes differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount, as set forth below:

(In millions)	2005			2004		2003
Cumulative effect of accounting changes, before income taxes	$	(9.3	)	$	—	$	(33.7	)
Income tax benefit (expense) calculated using the federal statutory rate of 35%	$	3.3			—	$	(11.8	)
Increased for state income tax benefit, net of federal income tax expense		0.1			—		(1.2	)
Total income tax benefit (expense)	$	3.4		$	—	$	(13.0	)

At December 31, the deferred income tax assets and liabilities consisted of the following:

(In millions)	2005			2004
Deferred income tax assets:
Adverse power purchase commitment	$	36.4		$	41.2
Recovery of transition costs		11.1			12.0
Unamortized investment tax credit		45.1			50.0
Postretirement benefits other than pensions		111.1			132.6
Tax effect of net operating loss carryforwards		488.2			408.7
Fair value of commodity contracts		41.7			91.8
Valuation allowance on state net operating loss		(9.4	)		(4.3	)
Other		80.0			129.8
Total deferred income tax assets		804.2			861.8
Deferred income tax liabilities:
Plant asset basis differences, net		1,325.9			1,353.1
Other		77.1			99.5
Total deferred income tax liabilities		1,403.0			1,452.6
Total net deferred income tax liability		598.8			590.8
Deferred income taxes included in current assets		93.4			44.6
Total long-term net deferred income tax liability	$	692.2		$	635.4

Allegheny recorded as deferred income tax assets the effect of net operating losses, which will more likely than not be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 10:  PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by noncontributory, defined benefit pension plans. Benefits are based on each employee’s years of service and compensation. Allegheny’s funding policy is to contribute annually to these plans at least the minimum amount required under ERISA and not more than can be deducted for federal income tax purposes. For reporting purposes, the measurement date is September 30th.

Allegheny also provides partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees. The postretirement health care plans include a limit on Allegheny’s share of costs for eligible retirees and dependents.

The components of the net periodic cost for pension benefits and for postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents and the allocation by Allegheny, through AESC, of costs for pension benefits and postretirement benefits other than pensions were as follows:

	Pension Benefits									Postretirement Benefits Other Than Pensions
(In millions)	2005			2004			2003			2005			2004			2003
Components of net periodic cost:
Service cost	$	23.6		$	23.5		$	21.8		$	4.0		$	4.3		$	3.8
Interest cost		63.4			62.7			62.0			16.8			15.3			16.9
Expected return on plan assets		(69.2	)		(68.7	)		(74.9	)		(6.2	)		(6.1	)		(6.1	)
Amortization of unrecognized transition obligation		0.5			0.5			0.6			5.9			5.9			5.9
Amortization of prior service cost		3.6			4.1			4.8			—			0.2			0.4
Recognized actuarial loss		9.2			5.8			0.2			2.1			0.1			—
Subtotal		31.1			27.9			14.5			22.6			19.7			20.9
Curtailments, settlements and special termination benefits		1.3			6.0			14.4			3.4			3.4			5.8
Net periodic cost	$	32.4		$	33.9		$	28.9		$	26.0		$	23.1		$	26.7
Allocation of net periodic cost:
Monongahela	$	10.0		$	11.6		$	8.1		$	9.0		$	9.3		$	8.4
AE Supply		9.0			10.7			10.4			5.2			4.5			6.7
West Penn		7.4			6.3			5.8			6.5			4.9			6.2
Potomac Edison		5.5			4.7			4.2			5.0			4.2			5.1
AE		0.5			0.6			0.4			0.3			0.2			0.3
Net periodic cost	$	32.4		$	33.9		$	28.9		$	26.0		$	23.1		$	26.7
Portion of net periodic cost above included in discontinued operations	$	1.7		$	4.4		$	0.7		$	2.6		$	4.6		$	1.2

Approximately 21%, 20% and 13% of the above net periodic cost amounts were allocated to “Construction work in progress,” a component of “Property, plant and equipment, net” in 2005, 2004 and 2003, respectively.

The net periodic cost for 2005 for pension includes $1.0 million of curtailment charges due to the outsourcing of Allegheny’s information technology function and for postretirement benefits other than pensions

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includes $2.0 million of settlement charges due to the sale of natural gas operations in West Virginia and $1.1 million of curtailment charges due to the outsourcing of the information technology function. The net periodic cost for 2004 includes $2.7 million of curtailment charges for pension and $3.4 million of curtailment charges for postretirement benefits other than pensions related to the sale of natural gas operations in West Virginia. See Note 3, “Discontinued Operations and Assets Held for Sale,” to the Consolidated Financial Statements for additional information.

The amounts accrued at December 31, using a measurement date of September 30, included the following components:

	Pension Benefits						Postretirement Benefits Other Than Pensions
(In millions)	2005			2004			2005			2004
Change in benefit obligation:
Benefit obligations at beginning of year	$	1,108.8		$	1,078.8		$	296.1		$	275.8
Service cost		23.6			23.5			4.0			4.3
Interest cost		63.4			62.7			16.8			15.3
Plan participants’ contributions		—			—			2.1			2.3
Curtailments gain		(6.2	)		(14.5	)		—			(4.1	)
Settlements gain		(2.3	)		(5.1	)		—			—
Special termination benefits		—			3.3			—			—
Actuarial loss		8.8			28.3			18.6			31.2
Benefits paid		(66.2	)		(68.2	)		(26.3	)		(28.7	)
Benefit obligation at end of year	$	1,129.9		$	1,108.8		$	311.3		$	296.1
Change in plan assets:
Fair value of plan assets at beginning of year	$	765.4		$	739.2		$	73.4		$	73.7
Actual return on plan assets		79.6			66.7			4.0			3.0
Plan participants’ contributions		—			—			2.1			1.7
Employer contribution		63.0			34.4			15.3			8.2
Settlements		(2.3	)		(6.7	)		—			—
Benefits paid		(66.2	)		(68.2	)		(13.3	)		(13.2	)
Fair value of plan assets at end of year	$	839.5		$	765.4		$	81.5		$	73.4
Plan assets less than benefit obligation	$	290.4		$	343.4		$	229.8		$	222.7
Unrecognized transition obligation		(3.2	)		(3.7	)		(39.8	)		(47.0	)
Unrecognized net actuarial loss		(276.2	)		(293.4	)		(83.3	)		(59.3	)
Unrecognized prior service cost due to plan amendments		(25.0	)		(29.7	)		—			—
Fourth quarter contributions and benefit payments		(0.1	)		(0.1	)		(8.7	)		(10.9	)
(Prepaid) Accrued at December 31	$	(14.1	)	$	16.5		$	98.0		$	105.5

The postretirement benefits other than pensions unrecognized transition obligation is being amortized over 20 years, beginning January 1, 1993.

As the Supplemental Executive Retirement Plan (“SERP”) is a non-qualified pension plan, Allegheny is not obligated to fund the SERP obligation. The SERP obligation, which is included as a component of the pension benefit obligation, was $5.3 million and $7.0 million at December 31, 2005 and 2004, respectively. The amount of SERP included in the (prepaid) accrued pension benefits at December 31, 2005 and 2004 was an accrued benefit of $2.0 million and $2.5 million, respectively.

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Amounts recognized in the Consolidated Balance Sheets at December 31 were as follows:

	Pension Benefits						Postretirement Benefits Other Than Pensions
(In millions)	2005			2004			2005		2004
Accrued benefit liability	$	200.2		$	231.7		$	98.0	$	105.5
Intangible asset		(27.4	)		(33.2	)		—		—
Accumulated other comprehensive loss		(186.9	)		(182.0	)		—		—
Net amount recognized at December 31	$	(14.1	)	$	16.5		$	98.0	$	105.5

The accumulated benefit obligation for all defined benefit pension plans was $1,039.9 million and $997.2 million at December 31, 2005 and 2004, respectively. The portion of the total accumulated benefit obligation related to the SERP was $4.8 million and $6.6 million at December 31, 2005 and 2004, respectively.

Information for pension plans with a projected benefit obligation and an accumulated benefit obligation in excess of plan assets is as follows:

	Pension Benefits
(In millions)	2005		2004
Projected benefit obligation	$	1,129.9	$	1,108.8
Accumulated benefit obligation	$	1,039.9	$	997.2
Fair value of plan assets	$	839.5	$	765.4

Information related to the increase in the minimum pension liability included in accumulated other comprehensive loss is as follows:

	Pension Benefits
(In millions)	2005		2004		2003
Increase in minimum pension liability included in accumulated other comprehensive loss, before income taxes	$	4.9	$	25.2	$	107.3
Balance of minimum pension liability included in accumulated other comprehensive loss, before income taxes	$	186.9	$	182.0	$	156.8
Taxes related to minimum pension liability included in accumulated other comprehensive loss		75.7		75.8		65.3
Balance, net of taxes, of minimum pension liability included in accumulated other comprehensive loss	$	111.2	$	106.2	$	91.5

The assumptions used to determine net periodic benefit costs for years ended December 31, 2005, 2004 and 2003 are shown in the table below.

	Pension Benefits						Postretirement Benefits Other Than Pensions
	2005		2004		2003		2005		2004		2003
Discount rate	5.90	%	6.00	%	6.50	%	5.90	%	6.00	%	6.50	%
Expected long-term rate of return on plan assets *	8.50	%	8.50	%	9.00	%	8.50	%	8.50	%	9.00	%
Rate of compensation increase	3.25	%	3.75	%	4.00	%	3.25	%	3.75	%	4.00	%

* Excluding administrative expenses.

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The assumptions used to determine benefit obligations at year-end 2005 and 2004 are shown in the table below:

	Pension Benefits				Postretirement Benefits Other Than Pensions
	2005		2004		2005		2004
Discount rate	5.60	%	5.90	%	5.60	%	5.90	%
Rate of compensation increase	3.25	%	3.25	%	3.25	%	3.25	%

In selecting an assumed discount rate, Allegheny uses a modeling process that involves selecting a portfolio of high-quality bonds (AA- or better) whose cash flows (via coupons and maturities) match the timing and amount of Allegheny’s expected future benefit payments. Allegheny considers the results of this modeling process, as well as overall rates of return on high quality corporate bonds and changes in such rates over time, in the determination of its assumed discount rate.

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs for 2006 is 8.25%, which is net of administrative expenses.

Assumed health care cost trend rates at December 31 are as follows:

	2005	2004
Health care cost trend rate assumed for next year	9.5%	9.5%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0%	5.0%
Year that the rate reaches the ultimate trend rate	2015	2014

For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.5% beginning with 2006 and grading down by 0.5% each year to an ultimate rate of 5.0%, and plan provisions that limit future medical and life insurance benefits. Because of the plan provisions that limit future benefits, changes in the assumed health care cost trend rate would have a limited effect on the amounts displayed in the tables above. A one-percentage-point change in the assumed health care cost trend rate would have the following effects:

(In millions)	1-Percentage-Point Increase		1-Percentage-Point Decrease
Effect on total of service and interest cost components	$	0.6	$	(0.5	)
Effect on postretirement benefit obligation	$	5.6	$	(5.0	)

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) became law. Beginning in 2006, the federal government will provide subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. The subsidy would be 28% of eligible drug costs for retirees who are over age 65 and covered under Allegheny’s postretirement benefits other than pensions plan.

Allegheny elected to follow the deferral provisions of FASB Staff Position (“FSP”) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-1”). FSP 106-1 permits employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until guidance on the accounting for the

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federal subsidy is issued. On May 19, 2004, FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”), which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.

Allegheny has determined that the prescription drug benefit offered under its postretirement benefits other than pensions plan is at least actuarially equivalent to Medicare Part D and therefore, expects to receive the federal subsidy offered under the Medicare Act. Allegheny expects to receive subsidies of approximately $2.0 million to $3.0 million annually during the period 2006 through 2010, and expects to receive an aggregate of approximately $3.0 million during the period 2011 through 2015. Also, beginning in 2006, the annual net periodic postretirement benefit cost was reduced by approximately $1.8 million as a result of the expected sharing of the cost of the program by Medicare.

Plan Assets

Allegheny’s pension plans’ asset allocations as of the measurement dates of September 30, 2005 and 2004, by asset category are as follows:

	Plan Assets at September 30,
	2005		2004
Asset Category:
Fixed income securities	51	%	52	%
Equity securities	49	%	48	%
Total	100	%	100	%

Allegheny’s postretirement benefits other than pensions asset allocations as of the measurement dates of September 30, 2005 and 2004, by asset category are as follows:

	Plan Assets at September 30,
	2005		2004
Asset Category:
Fixed income securities	35	%	45	%
Equity securities	56	%	44	%
Short-term investments	9	%	11	%
Total	100	%	100	%

As of September 30, 2005, the investment policy of the defined benefit pension plan specified a long-term target asset allocation objective of 40% equity securities and 60% fixed income securities. The investment policies for the assets associated with the postretirement benefits other than pension plans vary based on the particular structure of each plan. As of September 30, 2005, the investment policies of these plans specified a long-term target asset allocation ranging from 55%-75% equity securities and 25%-40% fixed income securities. The asset allocations represent a long-term perspective. Under the plans’ investment policies, the allocations may vary from the stated objective within specified ranges. Market shifts, changes in the plan dynamics, or changes in economic conditions may cause the asset mix to fall outside of the long-term policy range in a given period.

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Contributions

Allegheny makes contributions to its pension plans in order to meet at least the minimum required funding amount under ERISA. These anticipated contributions may change in the future if Allegheny’s assumptions regarding prevailing interest rates change, if actual investments under-perform or out-perform expectations, if actuarial assumptions or asset valuation methods change or if pending pension reform legislation is passed. Allegheny currently anticipates that during 2006 it will contribute approximately the same amount as it contributed in 2005. Allegheny also currently anticipates contributing a total amount in 2006 ranging from $16.0 million to $18.0 million to fund postretirement benefits other than pensions.

401(k) Savings Plan

The ESOSP was established as a non-contributory stock ownership plan for all eligible employees, effective January 1, 1976, and was amended in 1984 to include a savings program. All of Allegheny’s employees, subject to meeting eligibility requirements, may elect to participate in the ESOSP. Under the ESOSP, each eligible employee can elect to have from 2% to 15% of his or her compensation contributed to the ESOSP on a pre-tax basis, and an additional 1% to 6% on a post-tax basis. Participants direct the investment of contributions to specified mutual funds or AE common stock. Allegheny matches 50% of the first 6% of pre-tax compensation deferred into the ESOSP by an employee.

AE made these matching contributions by issuing shares of its common stock for the period January 1, 2003 through June 30, 2003 and the period April 1, 2004 through December 31, 2005. For the period July 1, 2003 through March 31, 2004, AE purchased shares in the open market to make these matching contributions. AE issued 294,904 shares, 363,361 shares and 399,914 shares of its common stock as matching contributions in 2005, 2004 and 2003, respectively, and recorded expense for the fair market value of these shares in the amount of $7.8 million, $6.0 million and $2.5 million in 2005, 2004 and 2003, respectively. AE purchased 129,308 shares and 544,490 shares in the open market in 2004 and 2003, respectively, to make the matching contributions, and recorded expense for the cost of the shares purchased in the amount of $1.7 million and $5.3 million in 2004 and 2003, respectively.

Estimated Future Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are estimated to be paid and the following federal subsidy payments are expected to be received by Allegheny as follows:

	Pension Benefits		Postretirement Benefits Other Than Pensions
(In millions)			Benefit Payments		Expected Federal Subsidy
2006	$	65.7	$	23.4	$	2.1
2007		65.7		23.9		2.3
2008		65.9		24.0		2.5
2009		66.3		24.0		2.7
2010		66.9		24.0		2.9
2011 – 2015		355.3		120.6		3.1

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NOTE 11:  STOCK-BASED COMPENSATION

Under Allegheny’s LTIP, stock options, restricted shares and performance awards may be granted to officers and key employees. Ten million shares of Allegheny’s common stock have been authorized for issuance under the LTIP, subject to adjustments for changes in Allegheny’s common shares.

Under the LTIP, options are granted at or above the quoted market price of Allegheny’s common shares on the date of grant. Vesting periods are determined by Allegheny, with options typically vesting over a period of one to five years. Options terminate 10 years after the date of grant. There were 2,567,875 exercisable options at December 31, 2005.

Under the LTIP, Allegheny may grant awards of restricted shares of common stock on terms, conditions and restrictions as it may determine, based on performance standards, periods of service, share ownership or other criteria.

Allegheny may also grant performance awards under the LTIP, which consist of a right to receive a payment in cash and/or shares of Allegheny’s common stock that is based on the fair market value of a certain number of shares of AE common stock, increases in the fair market value of AE common stock during an award period and/or a fixed cash amount.

In 2005 and 2004, Allegheny granted approximately 0.1 million and 3.4 million stock units, respectively, pursuant to agreements with certain executives. Stock units vest annually over a period of three to five years. Each unit entitles the holder to one share of AE common stock on the vesting date, subject to an election to defer receipt. The weighted average fair values of the 2005 and 2004 stock units on the grant dates were $21.08 per share and $13.37 per share, respectively. Approximately 390,000 stock units were cancelled during 2004 as a result of the resignation of an executive. For the years ended December 31, 2005, 2004, and 2003, compensation expense of $9.9 million, $18.7 million and $10.6 million, respectively, was recorded for stock units.

The weighted average fair values of the 2005 and 2004 options on the date of grant were $9.40 and $7.18 per share, respectively. There were no stock options granted during 2003. The fair values were estimated at the date of grant using the Black-Scholes option-pricing model, with the following weighted average assumptions:

	2005		2004
Risk-free interest rate	4.19	%	3.50	%
Expected life in years	6.5		6
Expected stock volatility	35.00	%	52.42	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Stock option activities for the past three years are as follows:

	Stock Options		Weighted Average Price
Outstanding at December 31, 2002	2,043,227		$	36.021
Forfeited	(538,126	)	$	38.818
Outstanding at December 31, 2003	1,505,101		$	35.022
Granted	5,789,421		$	13.482
Exercised	(17,000	)	$	13.350
Forfeited	(1,117,748	)	$	24.980
Outstanding at December 31, 2004	6,159,774		$	16.659
Granted	440,000		$	21.584
Exercised	(200,569	)	$	14.704
Forfeited	(249,848	)	$	17.770
Outstanding at December 31, 2005	6,149,357		$	17.030

The following table summarizes the stock options outstanding at December 31, 2005:

	Options Outstanding				Options Exercisable
		Weighted Average
Range of Exercise Prices	Number Outstanding at 12/31/05	Remaining Contractual Term (in Years)	Exercise Price		Shares Exercisable at 12/31/05	Weighted Average Exercise Price at 12/31/05
$10.00 - $14.99	4,853,463	8.17	$	13.481	1,713,981	$	13.411
$15.00 - $19.99	176,000	9.06	$	18.935	4,000	$	17.245
$20.00 - $24.99	215,000	9.02	$	21.025	20,000	$	20.650
$25.00 - $29.99	75,000	9.92	$	28.490	—	$	—
$30.00 - $34.99	535,617	3.90	$	31.506	535,617	$	31.506
$35.00 - $39.99	22,800	5.68	$	39.005	22,800	$	39.005
$40.00 - $44.99	256,477	4.93	$	42.293	256,477	$	42.293
$45.00 - $49.99	15,000	5.24	$	46.260	15,000	$	46.260
Total	6,149,357	7.73	$	17.030	2,567,875	$	20.551

During 2004, Allegheny adopted a Non-Employee Director Stock Plan, under which each non-employee director receives, subject to the director’s election to defer his or her receipt, up to 1,000 shares of AE’s common stock for services performed during a calendar quarter. AE’s Board of Directors set the 2005 and 2004 quarterly compensation of each non-employee director at 800 shares of AE common stock. A maximum of 300,000 shares of AE’s common stock, subject to adjustments for stock splits, combinations, recapitalizations, stock dividends or similar changes in stock, may be issued under this plan. During 2005, AE issued 3,200 shares under this plan, and the directors deferred an additional 22,400 shares pursuant to the terms of the plan. During 2005, Allegheny recognized $0.7 million of expense for this plan. On December 1, 2005, AE’s Board of Directors increased the amount of compensation that non-employee directors will receive under the Non-Employee Director Stock Plan from 800 shares of AE common stock per quarter to 1,000 shares of AE common stock per quarter effective January 1, 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 12:  RECONCILIATION OF BASIC AND DILUTED INCOME (LOSS) PER SHARE

The following table provides a reconciliation of the numerators and the denominators for the basic and diluted earnings per share computations:

(In millions, except per share data)	2005			2004			2003
Basic Income (Loss) per Share:
Numerator:
Income (loss) from continuing operations, net of tax	$	75.1		$	129.7		$	(308.9	)
Redemption of preferred stock		(0.4	)		—			—
Income (loss) from continuing operations, net of tax after redemption of preferred stock		74.7			129.7			(308.9	)
Loss from discontinued operations, net of tax		(6.1	)		(440.3	)		(25.3	)
Cumulative effect of accounting changes, net of tax		(5.9	)		—			(20.8	)
Net income (loss)	$	62.7		$	(310.6	)	$	(355.0	)
Denominator:
Weighted average common shares outstanding		155,016,346			129,485,679			126,848,253
Basic Income (Loss) per Share:
Income (loss) from continuing operations, net of tax	$	0.48		$	1.00		$	(2.44	)
Loss from discontinued operations, net of tax		(0.04	)		(3.40	)		(0.20	)
Cumulative effect of accounting changes, net of tax		(0.04	)		—			(0.16	)
Net income (loss)	$	0.40		$	(2.40	)	$	(2.80	)
Diluted Income (Loss) per Share:
Numerator:
Income (loss) from continuing operations, net of tax	$	75.1		$	129.7		$	(308.9	)
Redemption of preferred stock		(0.4	)		—			—
Interest expense on convertible securities, net of tax		—			24.7			—
Income (loss) from continuing operations, net of tax after redemption of preferred stock and interest		74.7			154.4			(308.9	)
Loss from discontinued operations, net of tax		(6.1	)		(440.3	)		(25.3	)
Cumulative effect of accounting changes, net of tax		(5.9	)		—			(20.8	)
Net income (loss)	$	62.7		$	(285.9	)	$	(355.0	)
Denominator:
Weighted average common shares outstanding		155,016,346			129,485,679			126,848,253
Effect of dilutive securities:
Stock options		1,366,238			355,983			—
Performance shares		53,557			85,235			—	*
Non-employee stock awards		25,200			2,800			—
Stock units		2,172,410			1,561,993			—
Convertible securities		—	*		25,000,000			—	*
Total shares		158,633,751			156,491,690			126,848,253
Diluted Income (Loss) per Share:
Income (loss) from continuing operations, net of tax	$	0.47		$	0.99		$	(2.44	)
Loss from discontinued operations, net of tax		(0.04	)		(2.82	)		(0.20	)
Cumulative effect of accounting changes, net of tax		(0.03	)		—			(0.16	)
Net income (loss)	$	0.40		$	(1.83	)	$	(2.80	)

* The table below shows the following anti-dilutive shares not included above:

	2005	2004	2003
Performance shares	—	—	145,768
Convertible securities	7,614,991	—	25,000,000
Total	7,614,991	—	25,145,768

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 13:  ACCOUNTING FOR THE EFFECTS OF PRICE REGULATION

Deregulation

On May 29, 1998, the Pennsylvania Public Utility Commission (the “Pennsylvania PUC”) issued an order approving a transition plan for West Penn. This order was amended by a settlement agreement approved by the Pennsylvania PUC on November 19, 1998. West Penn recorded an extraordinary charge under the provisions of SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71,” in 1998 to reflect the disallowances of certain costs in the order. This charge included an estimated amount for an adverse power purchase commitment, which reflects a commitment to purchase power at above-market prices. The adverse power purchase commitment is amortized over the life of the commitment based on a schedule of estimated electricity purchases established in connection with the settlement agreement.

As of December 31, 2005, Allegheny’s reserve for adverse power purchase commitments, which is recorded entirely on West Penn’s Consolidated Balance Sheets, was $201.4 million and decreased as follows:

(In millions)	2005		2004		2003
Decrease in reserve for adverse power purchase commitments	$	16.7	$	18.0	$	19.1

These decreases in the reserve for adverse power purchase commitments are recorded as expense reductions in “Purchased power and transmission” on the Consolidated Statements of Operations.

Reregulation

In 1998, the West Virginia legislature passed legislation directing the Public Service Commission of West Virginia (the “West Virginia PSC”) to determine whether retail electric competition was in the best interests of West Virginia and its citizens. In response, the West Virginia PSC submitted a plan to introduce full retail competition on January 1, 2001. This plan was approved, but never implemented, by the legislature. In 2002, the West Virginia PSC issued orders dismissing deregulation proceedings. Based on these actions, Monongahela concluded that retail competition and the deregulation of generation assets is no longer probable and that the generation operations in West Virginia meet the requirements of SFAS No. 71.

Monongahela reapplied the provisions of SFAS No. 71 to its West Virginia generation assets in the first quarter of 2003 and recorded a gain of $61.7 million as part of “Other income and expenses, net” in the Consolidated Statements of Operations. This gain was primarily the result of the elimination of its transition obligation and the reestablishment of regulatory assets related to deferred income taxes.

Potomac Edison also recorded a transition obligation on its books associated with West Virginia deregulation. Potomac Edison reapplied the provisions of SFAS No. 71 in the first quarter of 2003 and recognized a gain of approximately $14.1 million as a result of the elimination of its transition obligation. This gain is also a component of “Other income and expenses, net” in the Consolidated Statements of Operations.

As a result of the reapplication of SFAS No. 71 to the West Virginia generation assets in January 2003, the Consolidated Balance Sheets include the amounts listed below for generation assets not subject to SFAS No. 71 as of December 31, 2005 and 2004:

(In millions)	December 31, 2005			December 31, 2004
Property, plant and equipment	$	4,160.4		$	4,121.2
Amounts under construction included above	$	62.7		$	36.1
Accumulated depreciation	$	(1,992.4	)	$	(1,925.6	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 14:  REGULATORY ASSETS AND LIABILITIES

Certain of Allegheny’s regulated utility operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:

(In millions)	2005		2004
Regulatory assets, including current portion:
Income taxes	$	312.2	$	325.5
Pennsylvania stranded cost recovery		88.1		122.0
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		97.7		84.2
Unamortized loss on reacquired debt		44.8		39.3
Other		40.4		29.5
Subtotal		583.2		600.5
Regulatory liabilities:
Non-legal asset removal costs		413.0		404.1
Income taxes		41.3		49.8
Subtotal		454.3		453.9
Net regulatory assets	$	128.9	$	146.6

Income Taxes, Net

In certain jurisdictions, deferred income tax expense is not permitted as a cost in the determination of rates charged to customers. In these jurisdictions a deferred income tax liability is recorded with an offsetting regulatory asset. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. These deferred income taxes primarily relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. No return is allowed on the regulatory asset for income taxes.

Pennsylvania Stranded Cost Recovery and CTC Reconciliation

In 1998, the Pennsylvania PUC authorized West Penn to defer the difference between authorized and billed CTC revenues, with an 11% return on the deferred amounts, for future full and complete recovery from customers. Therefore, Allegheny has recorded a regulatory asset for recovery in Pennsylvania of stranded cost, which represent the portion of transition costs determined by the Pennsylvania PUC to be recoverable by West Penn under its deregulation plan. The CTC regulatory asset is being recovered over the transition period that was scheduled to end in 2008. On April 21, 2005, the Pennsylvania PUC extended the transition period through 2010 and authorized West Penn to securitize additional transition costs including the deferred portion of the CTC from 1999 through 2004. CTC rates include return on, as well as recovery of, transition costs. The amount of under-recovery of CTC during the transition period, if any, will be determined at the end of the transition period through 2010.

On an annual basis, the Pennsylvania PUC has approved the amount of CTC reconciliation recorded as a regulatory asset by Allegheny.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

See Note 13, “Accounting for the Effects of Price Regulation,” for a discussion regarding Monongahela and Potomac Edison’s reapplication of the provisions of SFAS No. 71 to their West Virginia generation assets in the first quarter of 2003.

See Note 6, “Asset Retirement Obligations,” for a discussion of a regulatory liability identified in conjunction with the application of a recent accounting pronouncement.

NOTE 15:  DIVIDEND RESTRICTION

There were no dividends declared or paid on AE’s common stock during 2005 or 2004. AE may not declare or pay cash dividends on its common stock under the New AE Credit Facility. See Note 2, “Capitalization,” for additional information.

NOTE 16:  RESTRUCTURING CHARGES AND WORKFORCE REDUCTION EXPENSES

In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction and a reorganization of Allegheny’s energy trading division. For the year ended December 31, 2002, Allegheny recorded a charge for the restructuring and workforce reduction of $128.3 million, before income taxes ($77.5 million, net of income taxes). In addition, as a result of the restructuring, Allegheny recorded a charge of $7.9 million, before income taxes ($4.9 million, net of income taxes), for impairment of leasehold improvements.

The following table provides a roll forward of Allegheny’s pre-tax expenses and liabilities related to the restructuring charge to the liability balance at December 31, 2005 (excluding the $7.9 million impairment charge related to the abandoned leasehold improvements):

(In millions)	Personnel Costs			Other Exit Costs			Total
2002 restructuring expenses:
Non-ERO program expenses	$	25.0		$	21.0		$	46.0
ERO program expenses		82.3			—			82.3
Total 2002 restructuring expenses		107.3			21.0			128.3
2003 additional expense for lease impairment		—			4.5			4.5
ERO program costs accounted for in accrued obligations for pensions and other postretirement benefits		(82.3	)		—			(82.3	)
Cash expenditures—2002		(10.0	)		—			(10.0	)
Cash expenditures—2003		(15.0	)		(4.5	)		(19.5	)
Liability balance at December 31, 2003		—			21.0			21.0
2004 additional expense for lease impairment		—			3.9			3.9
Cash expenditures—2004		—			(6.9	)		(6.9	)
Liability balance at December 31, 2004		—			18.0			18.0
2005 additional expense for lease impairment		—			0.4			0.4
Cash expenditures—2005					(3.7	)		(3.7	)
Liability balance at December 31, 2005	$	—		$	14.7		$	14.7

The table above does not include Allegheny’s transition and severance expense of $1.4 million, $5.7 million and $6.1 million in 2005, 2004 and 2003, respectively, which is included in “Operations and maintenance” expense on the Consolidated Statements of Operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 17:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year and preferred stock of a subsidiary, at December 31, were as follows:

	2005				2004
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	4,101.7	$	4,272.6	$	4,925.9	$	5,445.5
Preferred stock of subsidiary (all series)	$	24.0	$	17.8	$	74.0	$	67.6

The above table excludes long-term debt with a carrying amount of $86.7 million and a fair value of $95.1 million related to liabilities associated with assets held for sale at December 31, 2004. This debt was transferred to the buyer in connection with the September 30, 2005 sale of these assets.

The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The fair value of preferred stock is based on quoted market prices. The carrying amounts of cash equivalents and short-term debt approximate the fair values of these financial instruments because of the short maturities of those instruments.

NOTE 18:  JOINTLY OWNED ELECTRIC UTILITY PLANTS

AGC jointly owns the Bath County generation facility with a non-affiliated third party. AGC’s investment and accumulated depreciation in the Bath County generation facility jointly owned with a third party, at December 31 were as follows:

(Dollars in millions)	2005			2004
Utility plant investment	$	839.0		$	829.5
Accumulated depreciation	$	316.3		$	303.7
Ownership %		40	%		40	%

NOTE 19:  OTHER INCOME AND EXPENSES, NET

Other income and expenses, net represent non-operating income and expenses before income taxes. The following table summarizes Allegheny’s other income and expenses, net:

(In millions)	2005		2004			2003
Interest and dividend income	$	14.3	$	6.5		$	10.5
Cash received from a former trading executive’s forfeited assets		11.2		—			—
Proceeds from a previously written-off equity investment		5.5		—			—
Premium services		3.7		3.9			3.6
Coal brokering income, net		2.2		2.1			1.8
Gain on land sales		1.7		9.7			13.2
Reapplication of SFAS No. 71		—		—			75.8
Impairment charges related to certain assets		—		(2.1	)		—
Impairment charges related to unregulated investments		—		(1.9	)		—
Storm restoration, net		—		1.9			—
Other		5.6		4.4			1.1
Total other income and expenses, net	$	44.2	$	24.5		$	106.0

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 20:  QUARTERLY FINANCIAL INFORMATION (Unaudited)

	2005 Quarter Ended (1)											2004 Quarter Ended (1)
(In millions, except per share data)	December 31			September 30			June 30			March 31		December 31			September 30			June 30			March 31
Total operating revenues	$	724.1		$	845.1		$	714.7		$	754.0	$	688.5		$	723.3		$	608.9		$	735.4
Operating income (loss)	$	73.6		$	171.1		$	112.1		$	180.0	$	231.2		$	159.1		$	30.2		$	168.7
Income (loss) from continuing operations	$	3.4		$	43.5		$	(6.1	)	$	34.4	$	81.2		$	50.7		$	(32.8	)	$	30.6
Income (loss) from discontinued operations, net		5.6			(7.8	)		(12.3	)		8.2		(8.8	)		(427.5	)		(6.7	)		2.7
Cumulative effect of accounting change, net		(5.9	)		—			—			—		—			—			—			—
Net income (loss)	$	3.1		$	35.7		$	(18.4	)	$	42.6	$	72.4		$	(376.8	)	$	(39.5	)	$	33.3
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.02		$	0.27		$	(0.04	)	$	0.25	$	0.59		$	0.40		$	(0.26	)	$	0.24
Income (loss) from discontinued operations, net		0.04			(0.05	)		(0.08	)		0.06		(0.06	)		(3.36	)		(0.05	)		0.02
Cumulative effect of accounting change, net		(0.04	)		—			—			—		—			—			—			—
Net income (loss)	$	0.02		$	0.22		$	(0.12	)	$	0.31	$	0.53		$	(2.96	)	$	(0.31	)	$	0.26
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.02		$	0.26		$	(0.04	)	$	0.24	$	0.53		$	0.37		$	(0.26	)	$	0.23
Income (loss) from discontinued operations, net		0.04			(0.05	)		(0.08	)		0.05		(0.05	)		(2.77	)		(0.05	)		0.02
Cumulative effect of accounting change, net		(0.04	)		—			—			—		—			—			—			—
Net income (loss)	$	0.02		$	0.21		$	(0.12	)	$	0.29	$	0.48		$	(2.40	)	$	(0.31	)	$	0.25

(1) Amounts may not total to year to date results due to rounding.

NOTE 21:  GUARANTEES AND LETTERS OF CREDIT

As of December 31, 2005, Allegheny’s Consolidated Balance Sheet reflected liabilities of $6.6 million, related to AE Supply’s $6.4 million guarantee of the performance of a put option issued in connection with an asset sale and $0.2 million of certain other guarantees.

As of December 31, 2004, Allegheny’s Consolidated Balance Sheet reflected liabilities of $9.1 million related to AE Supply’s $6.4 million guarantee of the performance of a put option issued in connection with an asset sale and a $2.7 million guarantee related to the CDWR contract. The CDWR guarantee was released during the third quarter of 2005.

As of December 31, 2005, Allegheny had an additional $17.3 million in guarantees for which no liability had been recorded. Of these guarantees, approximately $3.9 million related to the purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services, $4.7 million related to a lease agreement that was signed in 2001 and $8.7 million related to loans and other financing-related matters.

As of December 31, 2004, Allegheny had an additional $18.2 million in guarantees for which no liability had been recorded, of which approximately $3.6 million related to guarantees associated with the purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services, $9.9 million related to loans and other financing related guarantees and $4.7 million related to a lease agreement that was signed in 2001.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Letters of Credit

The New AE Credit Facility includes a $400 million Revolving Credit Facility, which is available for the issuance of letters of credit. There were $136.5 million of outstanding letters of credit drawn against the Revolving Credit Facility at December 31, 2005. Of this amount, a letter of credit for $125.0 million that expires in June 2006 was issued on September 23, 2005 on behalf of Allegheny as collateral to stay enforcement of the judgment in Allegheny’s litigation against Merrill Lynch while an appeal is pending, and letters of credit for $9.5 million and $2.0 million that expire in July 2006 and September 2006, respectively, were issued on behalf of Allegheny Energy Solutions, Inc. AE Supply also had a $1.6 million letter of credit outstanding that is collateralized by cash and was not issued under the Revolving Credit Facility. The $1.6 million letter of credit expired in February 2006 and was replaced with a $2.1 million letter of credit. The $2.1 million letter of credit is collateralized by cash, is not issued under the Revolving Credit Facility and expires in February 2007. None of these letters of credit are recorded on Allegheny’s Consolidated Balance Sheets.

See Note 2, “Capitalization” for additional information.

NOTE 22:  VARIABLE INTEREST ENTITIES

FASB Interpretation No. 46R (“FIN 46R”), “Consolidation of Variable Interest Entities,” requires an investor with the majority of the variable interests in a variable interest entity to consolidate the entity and also requires majority and significant variable interest investors to provide certain disclosures. A variable interest entity is an entity in which the entity’s equity investors do not have a controlling interest or the equity investment at risk is insufficient to finance the entities activities without receiving financial support from the other parties.

Through its wholly owned subsidiary, AE Supply Hunlock Creek, LLC (“AE Hunlock”), Allegheny owns a 50% partnership interest in Hunlock Creek Energy Ventures, LLC (“HCEV”), a partnership that owns and operates a 48 MW coal fired generating facility and a 44 MW gas fired combustion turbine generating facility. UGI Hunlock Development Company (“UGI”) also owns a 50% interest in HCEV. Allegheny and UGI are each entitled to 50% of the power generated by HCEV. At December 31, 2005, UGI held a put option under which it could require AE Hunlock to purchase UGI’s 50% interest in either the coal-fired facility, the gas-fired facility, or both, for a 90 day period beginning on January 24, 2006. In accordance with FIN 46R, Allegheny has consolidated HCEV in its financial statements since March 31, 2004.

Allegheny expects to enter into an agreement with UGI in the first quarter of 2006, although Allegheny can provide no assurance that it will enter into any such agreement. Under the agreement as anticipated, Allegheny will pay approximately $13.8 million in cash to UGI, will acquire full ownership of the gas-fired combustion generating facility and will relinquish its 50% interest in the coal fired generating facility to UGI. The transactions would be subject to certain closing conditions. Closing is expected during the first quarter of 2006.

Potomac Edison and West Penn each have a long-term electricity purchase contract with an unrelated independent power producer (“IPP”) that represents a variable interest under FIN 46R. Allegheny has been unable to obtain certain information from the IPPs necessary to determine if the related variable interest entities (“VIEs”) should be consolidated under FIN 46R.

Potomac Edison and West Penn had power purchases from these two IPPs in the amount of $105.3 million and $43.8 million, respectively, for 2005 and $93.6 million and $47.3 million, respectively, for 2004. Potomac Edison recovers the full amount, and West Penn recovers a portion, of the cost of the applicable power contract in their respective rates charged to consumers or through customer surcharges. Neither Potomac Edison nor West Penn is subject to any risk of loss associated with the applicable VIE, because neither of them has any obligation to the applicable IPP other than to purchase the power that the IPP produces according to the terms of the applicable electricity purchase contract.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 23:  COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Allegheny is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.

Clean Air Act Matters.  Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through reduction of output. From time to time, minor excursions of stack emission opacity that are normal to fossil fuel operations are experienced and are accommodated by the regulatory process. Allegheny meets current emission standards for sulfur dioxide (“SO₂”) by using emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

Allegheny’s compliance with the Clean Air Act of 1970 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the U.S. Environmental Protection Agency (the “EPA”) on March 10, 2005, may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Based on current forecasts, Allegheny estimates that it may have an SO₂ allowance market exposure of less than 10,000 tons in 2006 and approximately 20,000 tons and 75,000 tons in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Allegheny continues to evaluate options for continuing compliance, and current plans include the potential installation of scrubbers at its Fort Martin generation facility by 2010, the elimination of a scrubber bypass at its Pleasants generation facility by 2008 and consideration of scrubbers at its Hatfield generation facility.

Allegheny meets current emission standards for nitrogen oxides (“NO_X”) by using low NO_X burners, Selective Catalytic Reduction, Selective Non-Catalytic Reduction and over-fire air and optimization software, as well as through the use of emission allowances. Allegheny is currently evaluating its options for CAIR compliance. In 1998, the EPA finalized its NOx State Implementation Plan (“SIP”) call rule (known as the “NOx SIP call”), which addressed the regional transport of ground-level ozone and required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Pennsylvania, Maryland and West Virginia.

AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. AE Supply estimates that its emission control activities, in concert with its inventory of banked allowances, will facilitate its compliance with NOx limits established by the SIP through 2008. Allegheny’s current capital expenditure forecast includes the expenditure of $2 million of capital costs during 2007 for additional NO_X emission controls. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities. Therefore, there can be no assurance that Allegheny’s need to purchase NO_X allowances for these periods will not vary from current estimates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On March 15, 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”) establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and its strategy for compliance.

In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these generation facilities. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the new source review (“NSR”) standards of the Clean Air Act, which can require the installation of additional air pollution control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues.

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology. There are three recent, significant federal court decisions that have addressed the application of NSR requirements to electric utility generation facilities: the Ohio Edison decision, the Duke Energy decision and the Alabama Power decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy and Alabama Power decisions support the industry’s understanding of NSR requirements. The U.S. Court of Appeals for the Fourth Circuit affirmed the Duke Energy decision on June 15, 2005.

In 2003, the EPA issued the Equipment Replacement Rule, which sets forth a clearer set of rules for projects that may be undertaken without triggering NSR requirement. This rule would apply the Routine Maintenance, Repair and Replacement (“RMRR”) exception to the NSR requirement in a manner that is more consistent with the energy industry’s historical compliance approach. That rule was challenged by some states and environmental groups and, on December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the implementation of that rule. At this time, AE and its subsidiaries are not able to determine the effect that these actions may have on them.

On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from the Pennsylvania Department of Environmental Protection (“PA DEP”). The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

On January 6, 2005, AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal district court in West Virginia (“West Virginia DJ Action”). This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia comply with the Clean Air Act. The Attorneys General filed a motion to dismiss the West Virginia DJ Action. It is possible that the EPA and other state authorities may join or move to transfer the West Virginia DJ Action.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Distribution Companies in the U.S. District Court for the Western District of Pennsylvania (the “PA Enforcement Action”). This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the federal District Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. Allegheny’s motion to stay the PA Enforcement Action was denied on November 21, 2005. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On February 15, 2006, Allegheny filed a motion to dismiss the amended complaint.

On February 16, 2005, Citizens for Pennsylvania’s Future, an environmental group, sued Allegheny in the U.S. District Court for the Western District of Pennsylvania. The action alleges violations of opacity limits and particulate matter emission limits at the Hatfield’s Ferry generation facility.

Allegheny intends to vigorously pursue and defend against the environmental matters described above but cannot predict their outcomes.

Canadian Toxic-Tort Class Action:  On June 30, 2005, AE Supply, Monongahela and AGC, along with 18 other companies with coal-fired generation facilities, were named as defendants in a toxic-tort, purported class action lawsuit filed in the Ontario Superior Court of Justice. On behalf of a purported class comprised of all persons residing in Ontario within the past six years (and/or their family members or heirs), the named plaintiffs allege that the defendants negligently failed to prevent their generation facilities from emitting air pollutants in such a manner as to cause death and multiple adverse health effects, as well as economic damages, to the plaintiff class. The plaintiffs seek damages in the approximate amount of Canadian $49.1 billion (approximately US $41.6 billion, assuming an exchange rate of 1.18 Canadian dollars per US dollar), along with continuing damages in the amount of Canadian $4.1 billion per year and punitive damages of Canadian $1.0 billion (approximately US $3.5 billion and US $850 million, respectively, assuming an exchange rate of 1.18 Canadian dollars per US dollar) along with such other relief as the court deems just. Allegheny has not yet been served with this lawsuit. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

Claims Related to Alleged Asbestos Exposure:  The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties in these actions are seeking an allocation of responsibility for historic and potential future asbestos liability.

Allegheny and numerous others are plaintiffs in a similar action filed against Zurich Insurance Company in California, Fuller-Austin Asbestos Settlement Trust, et al. v. Zurich-American Insurance Co., et al., Case No. CGC 04 431719 (Superior Court of California, County of San Francisco).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In connection with a settlement, Allegheny received payment from one of its insurance companies in the amount of $625,000 on July 5, 2005, with the next payment of $625,000 due July 1, 2006. As part of the settlement, Allegheny released this insurance company from potential liabilities associated with claims against Allegheny alleging asbestos exposure.

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2005, Allegheny had 930 open cases remaining in West Virginia and five open cases remaining in Pennsylvania.

Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”) Claim:  On March 4, 1994, Monongahela and certain affiliated companies received notice that the EPA had identified them as potentially responsible parties (“PRPs”) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site in Pennsylvania. Initially, approximately 175 PRPs were involved; however, the current number of active PRPs has been reduced as a result of settlements with de minimis contributors and other contributors to the site. The costs of remediation will be shared by all past and active responsible parties. In 1999, a PRP group that included Monongahela and certain affiliated companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30.0 million. Allegheny has an accrued liability representing its estimated share of the remediation costs as of December 31, 2005.

Other Litigation

Putative Class Actions Under California Statutes.  Eight related putative class action lawsuits were filed against and served on AE Supply and more than two dozen other named defendant power suppliers in various California superior courts during 2002. These class action suits were removed from state court and transferred to the U.S. District Court for the Southern District of California. Seven of the suits were commenced by consumers of wholesale electricity in California. The eighth, Millar v. Allegheny Energy Supply Co., et al., was filed on behalf of California consumers and taxpayers. The complaints allege, among other things, that AE Supply and the other defendant power suppliers violated California’s antitrust statute and the California unfair business practices statutes by manipulating the California electricity market. The suits also challenge the validity of various long-term power contracts with the State of California, including the CDWR contract.

On August 25, 2003, the U.S. District Court granted AE Supply’s motion to dismiss the seven consumer class actions with prejudice. On February 25, 2005, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s judgment dismissing the seven class actions with prejudice.

The District Court separately granted plaintiffs’ motion to remand in the eighth action, Millar, on July 9, 2003. On December 18, 2003, the plaintiffs filed an amended complaint in California state court, solely on behalf of consumers, naming certain additional defendants, including The Goldman Sachs Group, Inc. (“Goldman Sachs”). The case was removed to federal court based on the amended complaint. On January 11, 2005, the federal district court remanded the case back to the state court in San Francisco. On May 6, 2005, the defendants in the Millar action filed a series of demurrers seeking to have the action dismissed. On September 7, 2005, the state court ruled that the plaintiff’s complaint would be dismissed without leave to amend. On October 7, 2005, the state court entered judgment dismissing the complaint without leave to amend. Plaintiffs have agreed not to appeal the state court’s judgment. Thus, the eight actions filed against and served on AE Supply each have been dismissed.

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Nevada Power Contracts.  On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with FERC against AE Supply seeking action by FERC to modify prices payable to AE Supply under three trade confirmations between Merrill Lynch and NPC. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with Merrill Lynch under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers. On December 19, 2002, the Administrative Law Judge (“ALJ”) issued findings that no contract modification was warranted. The ALJ determined in favor of NPC that AE Supply, rather than Merrill Lynch, was a proper subject of NPC’s complaint.

On June 26, 2003, FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others. FERC did not decide whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, FERC issued an order, on rehearing, affirming its conclusion that the long-term contracts should not be modified. Snohomish County and other parties filed petitions for review of FERC’s June 26, 2003 order with the U.S. Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. The Ninth Circuit heard oral argument in these cases on December 8, 2004.

AE Supply intends to vigorously defend against these actions but cannot predict their outcomes.

Sierra/Nevada.  On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted claims against AE and AE Supply for: (a) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (b) conspiracy and (c) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada filed an amended complaint on May 30, 2003, which asserted a fourth cause of action against AE and AE Supply for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys’ fees and seeks in excess of $850 million under the RICO count. AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. Thereafter, plaintiffs filed a motion to stay the action, pending the outcome of certain state court proceedings in which they are seeking to reverse the Nevada PUC’s disallowance of expenses. On April 4, 2005, the District Court granted the stay motion, and the action is currently stayed.

AE Supply intends to vigorously defend against this action but cannot predict its outcome.

Litigation Involving Merrill Lynch.  AE and AE Supply entered into an asset purchase agreement with Merrill Lynch and affiliated parties in 2001, under which AE and AE Supply purchased Merrill Lynch’s energy marketing and trading business for approximately $489 million and an equity interest in AE Supply of nearly 2%. The asset purchase agreement provided that Merrill Lynch would have the right to require AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest calculated from March 16, 2001 in the event that certain conditions were not met.

On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the U.S. District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million. On September 25, 2002, AE and AE Supply filed an action against Merrill Lynch in New York state court alleging fraudulent inducement and breaches of representations and warranties in the purchase agreement.

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On May 29, 2003, the U.S. District Court for the Southern District of New York denied AE’s motion to stay Merrill Lynch’s action and ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York state court, as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply dismissed the New York state action and filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the U.S. District Court for the Southern District of New York. The counterclaims, as amended, alleged that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, that Merrill Lynch negligently misrepresented certain facts relating to the purchase agreement and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims sought damages in excess of $605 million, among other relief.

On April 12, 2005, the court granted Merrill Lynch’s motion for summary judgment on its breach of contract claim, thereby requiring AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest from March 16, 2001, to be offset by any judgment in favor of AE and AE Supply on their counterclaims. The court denied Merrill Lynch’s summary judgment motion with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of contract, and granted Merrill Lynch’s motion with respect to the counterclaims for breach of fiduciary duty and negligent misrepresentations.

In May and June of 2005, the District Court conducted a trial with respect to the damages owed Merrill Lynch on its breach of contract claim and with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of contract. Following the trial, on July 18, 2005, the District Court entered an order: (a) ruling against AE and AE Supply on their fraudulent inducement and breach of contract claims; (b) requiring AE to pay $115 million plus interest to Merrill Lynch; and (c) requiring Merrill Lynch to return its equity interest in AE Supply to AE. On August 26, 2005, the court entered its final judgment in accordance with its July 18, 2005 ruling. On September 22, 2005, AE and AE Supply filed a notice of appeal of the District Court’s judgment to the U.S. Court of Appeals for the Second Circuit. Although AE will not be required to pay Merrill Lynch the amount of the judgment while the appeal is pending, AE has posted a letter of credit to secure the judgment.

As a result of the District Court’s ruling, AE recorded a charge during the first quarter of 2005 in the amount of $38.5 million, representing interest from March 16, 2001 through March 31, 2005, and continues to accrue interest expense thereafter.

The federal government is holding certain assets of Daniel L. Gordon, the former head of energy trading for AE Supply. Both AE and AE Supply, on the one hand, and Merrill Lynch, on the other hand, filed petitions with the U.S. District Court for the Southern District of New York claiming rights to the funds. In June 2005, AE, AE Supply, Merrill Lynch and the U.S. Attorney’s Office entered into a settlement agreement pursuant to which AE Supply and Merrill Lynch will receive equal portions of certain of the assets held by the federal government. AE Supply has received approximately $11 million from the forfeited assets and may receive additional amounts if certain funds are released from a separate escrow.

Putative Shareholder, Benefit Plan Class Actions and Derivative Action.  From October 2002 through December 2002, plaintiffs claiming to represent purchasers of AE’s securities filed 14 putative class action lawsuits against AE and several of its former senior managers in U.S. District Courts for the Southern District of New York and the District of Maryland. The complaints alleged that AE and senior management violated federal securities laws when AE purchased Merrill Lynch’s energy marketing and trading business with the knowledge that the business was built on illegal wash or round-trip trades with Enron, which the complaints alleged artificially inflated trading revenue, volume and growth. All of the securities cases were transferred to the District of Maryland and consolidated. The plaintiffs filed an amended complaint on May 3, 2004 that alleged that the defendants violated federal securities laws by failing to disclose weaknesses in Merrill Lynch’s energy marketing and trading business, as well as other internal control and accounting deficiencies.

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In June 2003, a shareholder derivative action was filed against AE’s Board of Directors and several former senior managers in the Supreme Court of the State of New York for the County of New York. The suit alleges that the Board and former senior management breached fiduciary duties to AE that have exposed AE to the securities class action lawsuits. On April 8, 2005, a second shareholder derivative action was filed against AE’s Board of Directors and several former senior managers and former directors. The action was filed in the U.S. District Court for the District of Maryland and consolidated with the securities class actions pending in that court. The Maryland derivative action contains allegations similar to the New York state court derivative action.

AE entered into agreements to settle the consolidated securities class action as well as the related shareholder derivative actions. The proposed settlements remain subject to a number of conditions, including the negotiation of final settlement documents and court approval following notice to shareholders and class members. Under the proposed settlement in the consolidated securities class action, the action will be dismissed with prejudice in exchange for a cash payment of $15.05 million, which will be made by AE’s insurance carrier. Pursuant to the proposed settlement of the shareholder derivative actions, those actions will be dismissed with prejudice in exchange for a cash payment of $450,000, which will be made by AE’s insurance carrier, and AE’s agreement to adopt certain corporate governance changes. In connection with the settlements, AE and the other settling defendants continue to deny allegations of wrongdoing, and, if the settlements are approved, they will receive a full release of all claims asserted in the litigation. Pursuant to AE’s charter and bylaws and Section 2-418 of the Maryland General Corporation Law, AE has agreed to advance reasonable expenses to members of its Board of Directors in connection with the shareholder derivative actions.

In February and March 2003, two putative class action lawsuits were filed against AE in U.S. District Courts for the Southern District of New York and the District of Maryland. The suits alleged that AE and a senior manager violated ERISA by: (a) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (b) failing to diversify plan assets; (c) failing to monitor investment alternatives; (d) failing to avoid conflicts of interest and (e) violating fiduciary duties. The ERISA cases were consolidated in the District of Maryland. On April 26, 2004, the plaintiffs in the ERISA cases filed an amended complaint, adding a number of current and former directors of AE as defendants and clarifying the nature of their claims. On June 25, 2004, the defendants filed a motion to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding. AE intends to vigorously defend against these actions but cannot predict their outcome.

Suits Related to the Gleason Generation Facility.  Allegheny Energy Supply Gleason Generation Facility, LLC, a subsidiary of AE Supply, is the defendant in a suit brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generation facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the generation facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generation facility. They seek a restraining order with respect to the operation of the plant and damages of $200 million. Mediation sessions were held on June 17, 2004 and February 22 and 23, 2006, but the parties did not reach settlement. AE has undertaken property purchases and other mitigation measures. AE intends to vigorously defend against this action but cannot predict its outcome.

AE Supply demanded indemnification from Siemens Westinghouse, the manufacturer of the turbines used in the Gleason Generation Facility, pursuant to the terms of the related equipment purchase agreement. On October 17, 2002, Siemens Westinghouse filed a declaratory judgment action in the Court of Common Pleas of Allegheny County, Pennsylvania, against AE Supply and its subsidiary seeking a declaration that the prior owner released Siemens Westinghouse from this liability through a release executed after AE Supply purchased the Gleason facility. On September 23, 2005, AE Supply entered into a confidential Settlement Agreement with Siemens Westinghouse that resolved various disputes between the parties. As a result, the declaratory judgment action filed by Siemens Westinghouse was dismissed with prejudice.

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SEC Matters.  On October 9, October 25 and November 5, 2002, AE received subpoenas from the SEC. The subpoenas principally concerned: (a) the departure of Daniel L. Gordon; (b) AE’s litigation with Merrill Lynch; (c) AE Supply’s valuation and management of its trading business; (d) AE’s November 4, 2002 press release concerning its financial statements; (e) the departure of AE’s and its subsidiaries’ Controller, Thomas Kloc, in June 2002 and (f) AE’s acquisition of power plants from Enron. AE and AE Supply responded to the subpoenas.

On January 16, 2004, the SEC requested that AE voluntarily produce certain documents in connection with an informal investigation of AE that focused on various accounting, internal control and disclosure issues. In the course of its informal investigation, the SEC requested and received various documents and took testimony from several current and former employees. Throughout the investigation, AE cooperated fully with the SEC. In its letter dated February 24, 2006, the SEC Division of Enforcement said, “This investigation has been terminated and no enforcement action has been recommended to the Commission.”

LTI Arbitration.  On April 22, 2004, Leasing Technologies International, Inc. and its shareholders (collectively, “LTI”) filed a demand for arbitration against Allegheny Ventures and AE before the American Arbitration Association. In December 2000, Allegheny Ventures entered into an agreement to acquire LTI, an equipment leasing company. Allegheny Ventures terminated the agreement on May 4, 2001 based on the existence of a material adverse charge under the agreement. LTI alleged that the termination of the agreement was unjustified and sought damages in an unspecified amount for breach of the agreement, as well as other consequential damages. On June 11, 2004, AE and Allegheny Ventures filed an answer to LTI’s demand, denying all claims. On December 15, 2005, AE and Allegheny Ventures entered into a settlement agreement with LTI pursuant to which they paid $15 million in exchange for a full release of all claims asserted by LTI and the dismissal with prejudice of the arbitration. The settlement does not constitute an admission of fault, and Allegheny continues to deny the allegations made by LTI in the arbitration.

Litigation with Mobotec.  On July 20, 2004, MobotecUSA, Inc. (“MobotecUSA”) filed a lawsuit in the Court of Common Pleas of Greene County, Pennsylvania, against AE, AE Supply and an Allegheny employee (the “MobotecUSA Action”). Allegheny had contracted with MobotecUSA for the installation of NO_x emissions reduction equipment at certain Allegheny facilities. MobotecUSA’s complaint alleged that AE and AE Supply had breached the contracts by failing to pay MobotecUSA approximately $3.3 million. The complaint also asserted claims for enforcement of mechanics’ liens and claims for (a) intentional interference with prospective business relations; (b) trade libel and defamation; (c) breach of the covenant of good faith and fair dealing; (d) unjust enrichment and quantum meruit; and (e) civil conspiracy. MobotecUSA alleges that Allegheny falsely told third parties that MobotecUSA was unsuccessful in installing equipment and claims that it lost approximately $50 million in prospective business as a result.

On September 9, 2004, AE and AE Supply filed and answer denying MobotecUSA’s claims and asserting a counterclaim for breach of contract based on MobotecUSA’s failure to achieve the emissions reduction levels guaranteed in the agreements. On September 23, 2005, MobotecUSA filed a Second Amended Complaint, which added AESC as a party and added claims for breaches of confidentiality agreements and misappropriation of trade secrets. The Allegheny defendants have filed an answer denying MobotecUSA’s claims. On October 19, 2005, AE Supply and Monongahela commenced in the Court of Common Pleas of Greene County, Pennsylvania, a separate but related action against MobotecUSA, Mobotec AB (MobotecUSA’s parent company) and certain individuals affiliated with Mobotec (the “Mobotec Parties”). This separate action was soon thereafter consolidated with the Mobotec Action for all purposes. In their amended complaint, AE Supply and Monongahela asserted claims for breach of contract, restitution, breach of warranty, negligence and negligent misrepresentation, based on Mobotec’s conduct. The Mobotec Parties have filed a motion seeking dismissal of certain claims and certain parties with respect to the amended complaint filed by AE Supply and Monongahela. Allegheny intends to vigorously defend against MobotecUSA’s claims and pursue its affirmative claims in the consolidated action, but cannot predict the outcome.

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Ordinary Course of Business.  The registrants are from time to time involved in litigation and other legal disputes in the ordinary course of business. Each registrant is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.

Construction and Capital Program

Allegheny’s expenditures for capital programs are estimated to be approximately $430.0 million for 2006 and $644.0 million for 2007. Capital expenditure levels in 2006 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. See “Environmental Matters and Litigation—Clean Air Act Matters,” above.

Leases

Allegheny has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles, computer equipment, communication lines and buildings.

Total capital and operating lease rent payments of $22.5 million, $28.4 million and $33.6 million were recorded as rent expense in 2005, 2004 and 2003, respectively. Allegheny’s estimated future minimum lease payments for capital and operating leases, with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are:

(In millions)	2006		2007		2008		2009		2010		Thereafter		Total		Less: amount representing interest and fees		Present value of net minimum capital lease payments
Capital Leases	$	10.3	$	7.4	$	5.6	$	4.1	$	3.0	$	1.5	$	31.9	$	7.4	$	24.5
Operating Leases	$	5.0	$	3.5	$	3.4	$	3.3	$	3.3	$	19.5	$	38.0	$	—	$	—

The carrying amount of assets recorded under capitalized lease agreements included in “Property, plant and equipment, net” at December 31, consisted of the following:

(In millions)	2005		2004
Equipment	$	24.1	$	33.6
Building		0.4		0.5
Property held under capital leases	$	24.5	$	34.1

In December 2005, Allegheny signed a coal lease and sales agreement with an affiliate of Alliance Resource Partners, L.P. to permit, develop and mine Allegheny’s coal reserve in Washington County, Pennsylvania. Alliance will evaluate the feasibility of mining the reserve and seek the necessary permits and other governmental approvals to mine the reserve. If the reserve is developed, it is expected to produce high BTU, “scrubber-quality” coal suitable for use in Allegheny’s power plants with SO₂ emission controls, and Allegheny has agreed to purchase up to two million tons annually of the mine’s output. Allegheny also will receive estimated royalty payments of $5 to $10 million per year on coal that is mined and sold from the reserve, depending upon production levels and coal prices, after the mine reaches full commercial operation.

PURPA

The Public Utility Regulatory Policies Act of 1978 (“PURPA”) has required electric utility companies, such as Allegheny’s regulated utility subsidiaries, to interconnect with, provide back-up electric service to and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

purchase electric capacity and energy from qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. State public service commissions or legislatures establish the rates paid for electric energy purchased from qualifying facilities.

The Energy Policy Act has amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contractual obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission This amendment has no impact on Allegheny’s current long-term power purchase agreements under PURPA.

Allegheny’s regulated utilities are committed to purchasing the electrical output from 479 MWs of qualifying PURPA capacity. Payments for PURPA capacity and energy in 2005, 2004 and 2003 were $209.0 million, $197.8 million and $196.4 million, respectively, before amortization of West Penn’s adverse power purchase commitment. The amount for 2003 excludes a contractually required payment from a hydroelectric facility that supplies power to Monongahela. The average cost of these power purchases was approximately 5.3, 5.2 and 5.6 cents per kilowatt-hour for 2005, 2004 and 2003, respectively.

The table below reflects Allegheny’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2005, by entity. Actual values can vary substantially depending upon future conditions.

	Monongahela			Potomac Edison			West Penn
(In millions)	kWhs	Amount		kWhs	Amount		kWhs	Amount
2006	1,302.6	$	58.1	1,450.7	$	99.4	1,114.1	$	50.9
2007	1,302.6	$	58.3	1,450.7	$	100.7	1,114.1	$	52.5
2008	1,305.5	$	58.7	1,454.6	$	102.4	1,116.9	$	54.0
2009	1,302.6	$	58.8	1,450.7	$	103.5	1,114.1	$	55.5
2010	1,302.6	$	61.4	1,450.7	$	105.1	1,114.1	$	57.3
Thereafter	23,679.2	$	1,162.7	27,703.2	$	2,126.9	8,184.2	$	422.4

Fuel Purchase and Transportation Commitments

Allegheny has entered into various long-term commitments for the procurement and transportation of fuel (primarily coal and lime) to supply its generation facilities. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Allegheny’s fuel consumed in electric generation was $736.6 million, $614.4 million and $592.0 million in 2005, 2004 and 2003, respectively. In 2005, Allegheny purchased approximately 57% of its fuel from one vendor. Total estimated long-term fuel purchase and transportation commitments (primarily coal and lime), at December 31, 2005, were as follows, by entity and in total:

(In millions)	AE Supply		Monongahela		Total
2006	$	518.1	$	134.2	$	652.3
2007		421.9		111.8		533.7
2008		313.6		85.7		399.3
2009		240.6		66.6		307.2
2010		212.6		55.1		267.7
Thereafter		1,732.2		467.8		2,200.0
Total	$	3,439.0	$	921.2	$	4,360.2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Other Purchase Obligations

On September 19, 2005, AE entered into a Professional Services Agreement (the “PSA”) with Electronic Data Systems Corporation and EDS Information Services, LLC (together, the “Service Provider”). On November 1, 2005, the Service Provider assumed responsibility for many of Allegheny’s information technology functions and agreed to assist Allegheny with the installation of an enterprise resource planning system. Unless extended by AE, the Professional Service Agreement will expire on December 31, 2012. Expected cash payments relating to the Professional Service Agreement are as follows:

(In millions)	2006		2007		2008		2009		2010		Thereafter		Total
Other purchase obligations	$	34.7	$	26.9	$	26.4	$	25.7	$	24.7	$	44.9	$	183.3

SMEPA Agreement

In December 2001, an indirect subsidiary of AE entered into an agreement to provide design, construction and installation services for seven natural gas-fired turbine generators for SMEPA. The seven units, with a combined output of approximately 450 MWs, will be located at three sites in southern Mississippi. The units will be owned by SMEPA. Construction started in May 2002, and installation of all of the units is expected to be completed by May 2006. The agreement allows for liquidated damages, for a maximum of $10 million, in the event the indirect subsidiary fails to meet specified delivery dates or the generators fail to meet specified performance requirements.

UGI Put Option

UGI holds a put option under which it can require AE Supply Hunlock Creek, LLC to purchase its 50% interest in either a coal-fired facility, gas-fired facility or both. The option can be exercised for a period of 90 days beginning on January 24, 2006. See Note 22, “Variable Interest Entities,” for additional information.

NOTE 24:  SUBSEQUENT EVENT

Land Sale

On January 11, 2006, AE Supply entered into an agreement with Harquahala Valley 3000, LLC (the “Buyer”) to sell approximately 2,900 acres of land located in Maricopa and La Paz Counties, Arizona for $32.5 million. After a 60 day due diligence period, the Buyer has the option to proceed with the transaction. If the Buyer decides to proceed, the sale is expected to close during April 2006 and result in a pre-tax gain of approximately $27.0 million.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

of Allegheny Energy, Inc.

We have completed integrated audits of Allegheny Energy, Inc.’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedules

In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive loss present fairly, in all material respects, the financial position of Allegheny Energy, Inc. and its subsidiaries (the “Company”) 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. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of the financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 6, the Company changed the manner in which it accounts for asset retirement obligations as of January 1, 2003 and conditional asset retirement obligations as of December 31, 2005. As discussed in Note 5, the Company changed the manner in which it accounts for gains and losses on energy trading contracts as of January 1, 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

187

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

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

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 28, 2006

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Statements of Operations

	Year ended December 31,
(In thousands)	2005			2004			2003
Operating revenues	$	789,886		$	683,760		$	718,863
Operating expenses:
Fuel consumed in electric generation		148,413			119,110			135,088
Purchased power and transmission		270,518			187,510			164,224
Loss on sale of Ohio T&D assets		29,256			—			—
Operations and maintenance		200,751			214,451			228,976
Depreciation and amortization		66,295			65,759			63,693
Taxes other than income taxes		49,727			50,176			41,809
Total operating expenses		764,960			637,006			633,790
Operating income		24,926			46,754			85,073
Other income and expenses, net (Note 14)		12,928			9,085			69,500
Interest expense		43,430			43,219			43,434
Income (loss) from continuing operations before income taxes		(5,576	)		12,620			111,139
Income tax expense (benefit) from continuing operations		(14,756	)		(3,812	)		39,187
Income from continuing operations		9,180			16,432			71,952
Income (loss) from discontinued operations, net of tax (Note 3)		1,028			(13,945	)		9,197
Income before cumulative effect of accounting change		10,208			2,487			81,149
Cumulative effect of accounting change, net of tax		—			—			(456	)
Net income	$	10,208		$	2,487		$	80,693

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Cash Flows

	Year ended December 31,
(In thousands)	2005			2004			2003
				(Revised Note 1)
Cash Flows From Operating Activities:
Net income	$	10,208		$	2,487		$	80,693
Loss (income) from discontinued operations, net of tax		(1,028	)		13,945			—
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change, net		—			—			456
Reapplication of SFAS No. 71		—			—			(61,724	)
Depreciation and amortization		66,295			65,759			73,702
Loss (gain) on asset sales and disposals		29,060			(110	)		—
Deferred income taxes and investment tax credit, net		(10,678	)		(4,309	)		40,892
Deferred energy costs, net		—			—			(33,913	)
Other, net		848			166			(28	)
Changes in certain assets and liabilities:
Accounts receivable, net		(20,647	)		(2,246	)		(733	)
Materials, supplies and fuel		1,657			(4,412	)		(30,297	)
Taxes receivable / accrued, net		7,949			7,402			35,199
Collateral deposits		(9,533	)		—			—
Other current assets		2,522			(321	)		3,676
Accounts payable		9,940			(1,577	)		(6,248	)
Accounts payable to affiliates, net		60,253			17,150			6,044
Other current liabilities		(2,127	)		9,189			2,003
Other assets		(1,447	)		1,233			(17,822	)
Non-current income taxes payable		—			—			4,604
Other liabilities		795			(5,293	)		21,413
Net cash provided by (used in) operating activities of discontinued operations		63,883			(49,429	)		—
Net cash provided by operating activities		207,950			49,634			117,917
Cash Flows From Investing Activities:
Capital expenditures		(70,042	)		(54,221	)		(68,194	)
Proceeds from sale of business and assets		52,079			162			—
Contribution to affiliate		—			—			(9,188	)
Other investments		—			8			(1,283	)
Net cash provided by (used in) investing activities of discontinued operations		127,644			(12,949	)		—
Net cash provided by (used in) investing activities		109,681			(67,000	)		(78,665	)
Cash Flows From Financing Activities:
Notes receivable from affiliates		(21,268	)		(4,205	)		8,503
Net borrowings (repayments) of short-term debt		—			(53,610	)		52,756
Issuance of long-term debt		69,201			117,179			—
Retirement of long-term debt		(72,067	)		(66,316	)		(63,073	)
Redemption of preferred stock		(50,000	)		—			—
Return of capital to AE		(80,000	)		—			—
Cash dividends paid on capital stock:
Preferred stock		(5,037	)		(5,037	)		(5,037	)
Common stock		—			(33,226	)		(43,593	)
Net cash provided by (used in) financing activities of discontinued operations		(67,061	)		63,702			—
Net cash provided by (used in) financing activities		(226,232	)		18,487			(50,444	)
Net increase (decrease) in cash and cash equivalents		91,399			1,121			(11,192	)
Cash and cash equivalents at beginning of period		45,092			43,971			55,163
Cash and cash equivalents at end of period	$	136,491		$	45,092		$	43,971
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest (net of amount capitalized)	$	44,150		$	49,947		$	49,569
Income taxes, net	$	(9,767	)	$	(2,764	)	$	(39,386	)

See accompanying Notes to Consolidated Financial Statements.

190

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets

	As of December 31,
(In thousands)	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	136,491		$	45,092
Accounts receivable:
Customer		45,061			39,736
Unbilled utility revenue		38,200			36,332
Wholesale and other		20,598			4,399
Allowance for uncollectible accounts		(2,489	)		(2,616	)
Note receivable from affiliate		25,473			4,205
Materials and supplies		15,916			17,123
Fuel		14,751			15,310
Prepaid taxes		20,075			21,579
Assets held for sale (Note 3)		—			147,862
Collateral deposits		9,533			—
Regulatory assets		4,379			4,702
Other		3,827			4,638
Total current assets		331,815			338,362
Property, Plant and Equipment, Net:
Generation		951,636			938,214
Transmission		281,048			291,558
Distribution		930,817			945,431
Other		73,807			82,767
Accumulated depreciation		(890,548	)		(869,077	)
Subtotal		1,346,760			1,388,893
Construction work in progress		17,401			15,533
Total property, plant and equipment, net		1,364,161			1,404,426
Investments and Other Assets:
Non-current assets held for sale (Note 3)		—			176,742
Investment in AGC		48,197			46,055
Other		6,904			4,033
Total investments and other assets		55,101			226,830
Deferred Charges:
Regulatory assets		101,117			99,502
Other		6,985			12,307
Total deferred charges		108,102			111,809
Total Assets	$	1,859,179		$	2,081,427

See accompanying Notes to Consolidated Financial Statements.

191

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets—(Continued)

	As of December 31,
(In thousands, except share amounts)	2005		2004
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Long-term debt due within one year	$	299,959	$	—
Accounts payable		48,232		38,292
Accounts payable to affiliates, net		57,434		11,534
Accrued taxes		41,766		40,833
Deferred income taxes		—		5,344
Accrued interest		8,929		8,794
Liabilities associated with assets held for sale (Note 3)		—		95,501
Ohio power commitment		25,900		—
Other		24,378		28,078
Total current liabilities		506,598		228,376
Long-term Debt (Note 2)		385,067		684,001
Deferred Credits and Other Liabilities:
Investment tax credit		442		2,590
Non-current income taxes payable		45,671		45,671
Deferred income taxes		194,248		190,511
Obligations under capital leases		5,554		8,747
Regulatory liabilities		242,416		243,974
Liabilities associated with assets held for sale (Note 3)		—		100,988
Other		41,219		24,197
Total deferred credits and other liabilities		529,550		616,678
Commitments and Contingencies (Note 16)
Preferred Stock		24,000		74,000
Common Stockholder’s Equity:
Common stock, $50 par value, 8 million shares authorized and 5,891,000 shares outstanding at December 31, 2005 and 2004		294,550		294,550
Other paid-in capital		40,719		111,182
Retained earnings		78,694		72,557
Accumulated other comprehensive income		1		83
Total common stockholder’s equity		413,964		478,372
Total Liabilities and Stockholder’s Equity	$	1,859,179	$	2,081,427

See accompanying Notes to Consolidated Financial Statements.

192

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Statements of Capitalization

			As of December 31,
(In thousands, except share amounts)			2005			2004
Common Stockholder’s Equity (See Consolidated Balance Sheets)			$	413,964		$	478,372
Preferred Stock, $100 par value per share:
Series	December 31, 2005 Regular Call Price Per Share
4.40%-4.80%—190,000 shares outstanding at December 31, 2005 and 2004	$	103.50 to $106.50	$	19,000		$	19,000
$6.28-$7.73—50,000 and 550,000 shares outstanding at December 31, 2005 and 2004, respectively		$102.86		5,000			55,000
Total Preferred Stock of Subsidiary			$	24,000		$	74,000
	December 31, 2005 Interest Rate %
Long-term Debt:
First mortgage bonds, maturity:
2006		5.000	$	300,000		$	300,000
2014-2015		5.375-6.700		190,000			120,000
2022-2025		—		—			70,000
Pollution control bonds and other secured & unsecured notes due 2007-2029		4.700-6.875		85,750			85,750
Medium-term debt due 2010		7.360		110,000			110,000
Unamortized debt discount				(724	)		(1,749	)
Total long-term debt (including current maturities of $299,959 and $0)				685,026			684,001
Total long-term debt associated with assets held for sale			$	—		$	86,732
Total Capitalization			$	1,122,990		$	1,323,105

See accompanying Notes to Consolidated Financial Statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Statements of Stockholder’s Equity

(In thousands, except shares)	Shares outstanding	Common stock		Other paid-in capital			Retained earnings			Accumulated other comprehensive income			Total common stockholder’s equity
Balance at January 1, 2003	5,891,000	$	294,550	$	106,770		$	76,270		$	—		$	477,590
Net income	—		—		—			80,693			—			80,693
Pollution control bond principal and interest paid by AE	—		—		3,722			—			—			3,722
Dividends declared on preferred stock	—		—		—			(5,037	)		—			(5,037	)
Dividends declared on common stock	—		—		—			(43,593	)		—			(43,593	)
Other comprehensive income	—		—		—			—			84			84
Balance at December 31, 2003	5,891,000		294,550		110,492			108,333			84			513,459
Net income	—		—		—			2,487			—			2,487
Pollution control bond interest paid by AE	—		—		690			—			—			690
Dividends declared on preferred stock	—		—		—			(5,037	)		—			(5,037	)
Dividends declared on common stock	—		—		—			(33,226	)		—			(33,226	)
Other comprehensive income	—		—		—			—			(1	)		(1	)
Balance at December 31, 2004	5,891,000		294,550		111,182			72,557			83			478,372
Net income	—		—		—			10,208			—			10,208
Pollution control bond interest paid by AE	—		—		749			—			—			749
Dividends declared on preferred stock	—		—		—			(4,071	)		—			(4,071	)
Return of capital	—		—		(80,000	)		—			—			(80,000	)
Sale of sulfur dioxide allowance to affiliate	—		—		8,788			—			—			8,788
Other comprehensive income	—		—		—			—			(82	)		(82	)
Balance at December 31, 2005	5,891,000	$	294,550	$	40,719		$	78,694		$	1		$	413,964

See accompanying Notes to Consolidated Financial Statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note No.		Page No.
1	Basis of Presentation	196
2	Capitalization	203
3	Discontinued Operations and Assets Held for Sale	204
4	Asset Sales	205
5	Asset Retirement Obligations (“ARO”)	205
6	Business Segments	206
7	Intangible Assets	208
8	Income Taxes	208
9	Pension Benefits and Postretirement Benefits Other Than Pensions	210
10	Accounting for the Effects of Price Regulation	212
11	Regulatory Assets and Liabilities	212
12	Fair Value of Financial Instruments	213
13	Jointly Owned Electric Utility Plants	213
14	Other Income and Expenses, Net	214
15	Quarterly Financial Information (Unaudited)	214
16	Commitments and Contingencies	214

195

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1:  BASIS OF PRESENTATION

Monongahela Power Company, together with its consolidated subsidiaries (“Monongahela”), is a wholly owned subsidiary of Allegheny Energy, Inc. (“AE,” and together with its consolidated subsidiaries, “Allegheny”). Monongahela, along with its regulated utility affiliates, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”), collectively doing business as Allegheny Power, operates electric transmission and distribution (“T&D”) systems. Monongahela operates an electric T&D system in West Virginia. Monongahela also generates power for its West Virginia customers. Monongahela has two principal business segments. The Generation and Marketing segment includes Monongahela’s power generation operations. The Delivery and Services segment includes Monongahela’s electric T&D operations.

Monongahela conducted electric T&D operations in Ohio, until December 31, 2005 and a natural gas T&D business in West Virginia until September 30, 2005.

On September 30, 2005, Monongahela sold its West Virginia natural gas operations. The results of operations relating to these assets have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. The assets and liabilities associated with these discontinued operations were classified as held for sale in the consolidated balance sheets from September 30, 2004 to the date of sale.

Monongahela completed the sale of its Ohio electric T&D assets to Columbus Southern Power Company (“Columbus Southern”), a subsidiary of American Electric Power, Inc., on December 31, 2005. The results of operations related to the Ohio electric T&D assets were not reclassified as discontinued operations, because the terms of the sale include a power sales agreement under which Monongahela will sell power to Columbus Southern to serve Monongahela’s former Ohio retail customer base through May 31, 2007.

Monongahela is subject to regulation by the Securities and Exchange Commission (“SEC”), the Public Service Commission of West Virginia (the “West Virginia PSC”) and the Federal Energy Regulatory Commission (“FERC”).

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny. As of December 31, 2005, AESC employed approximately 4,460 employees, of which approximately 1,290 are subject to collective bargaining arrangements.

Certain prior period amounts have been reclassified to conform to the financial statement presentation for the current period.

In addition, the accompanying Consolidated Statements of Cash Flows present the cash flows from discontinued operations in each of the three major categories (operating, investing and financing activities). The consolidated statement of cash flows for the year ended December 31, 2004 was revised during 2005 to conform to this presentation. Accordingly, for the year ended December 31, 2004, approximately $12.9 million in cash outflows for capital expenditures of discontinued operations and approximately $63.7 million in cash inflows for debt activities of discontinued operations were moved from cash flows provided by operating activities to cash flows of investing and financing activities of discontinued operations, respectively.

Significant accounting policies of Monongahela and its subsidiaries are summarized below.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires Monongahela to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting

196

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

period. On a continuous basis, Monongahela evaluates its estimates, including those related to the calculation of unbilled revenues, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Monongahela bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Consolidation

The Consolidated Financial Statements reflect investments in controlled subsidiaries on a consolidated basis. The Consolidated Financial Statements include the accounts of Monongahela and all subsidiary companies after elimination of intercompany transactions and balances. The Consolidated Financial Statements are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of FERC and applicable state regulatory commissions.

Revenues

Revenues from the sale of electricity to Monongahela’s customers are recognized in the period that the electricity is delivered and consumed by customers, including an estimate for unbilled revenues.

Debt Issuance Costs

Costs incurred to issue debt are recorded as deferred charges on the Consolidated Balance Sheets. These costs are amortized over the term of the related debt instrument using the effective interest method.

Property, Plant and Equipment

Utility and electric generation property, plant and equipment are stated at original cost. Cost includes direct labor and materials, allowance for funds used during construction on regulated property, and indirect costs, such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes and other benefits related to employees engaged in construction. Upon normal retirement, the costs of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation with no gain or loss recorded.

Monongahela consolidates its proportionate interest in the electric generating facilities that it owns jointly with AE Supply.

Long-Lived Assets

Monongahela’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows. See Note 3, “Discontinued Operations and Assets Held for Sale” for information related to asset impairment charges recorded during 2005 and 2004.

197

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Allowance for Funds Used During Construction (“AFUDC”)

AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is recognized as a cost of the Delivery and Services segment’s regulated property, plant and equipment, and beginning in 2003, the Generation and Marketing segment’s regulated property, plant and equipment as a result of the reapplication of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). Rates used for computing AFUDC in 2005, 2004 and 2003 averaged 7.50%, 6.93% and 7.38%, respectively. Monongahela recorded AFUDC of $1.2 million, $0.7 million and $2.1 million for 2005, 2004 and 2003, respectively.

Depreciation and Maintenance

Depreciation expense is determined in accordance with currently enacted regulatory rates. Depreciation expense was approximately 3.0% of average depreciable property in 2005, 2004 and 2003. Estimated service lives for generation, T&D and other property are as follows:

Type of Property	Years
Generation property:
Steam scrubbers and equipment	20-40
Steam generator units	40-75
Transmission and distribution property:
Gas equipment	21-63
Electric equipment	15-58
Other property:
Office buildings and improvements	46
General office/other equipment	14-20
Vehicles and transportation	7-25
Computers, software and information systems	5-10

The Delivery and Service segment’s depreciation expense was $30.4 million, $30.3 million and $29.1 million for 2005, 2004 and 2003, respectively. The Generation and Marketing segment’s depreciation expense was $34.8 million, $34.4 million and $33.9 million for 2005, 2004 and 2003, respectively. Depreciation expense is provided for under currently enacted regulatory rates.

Maintenance expenses represent costs incurred to maintain the generation facilities, the electric T&D systems and general plant. These expenses reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the generation facilities and periodic storm damage to the T&D system. Maintenance costs are expensed as incurred.

Investments

Investments are generally accounted for under the equity method of accounting. The income or loss on such investments is recorded in “Other income and expenses, net” in the Consolidated Statements of Operations.

Monongahela’s interest in the common stock of AGC was 22.97% at December 31, 2005 and 2004. AE Supply owns the remaining shares of AGC. Monongahela reports AGC in its Consolidated Financial Statements using the equity method of accounting. AGC owns an undivided 40% interest (1,010 megawatts (“MWs”)) in the 2,525 MWs pumped-storage hydroelectric station in Bath County, Virginia. This station is operated by the 60% owner, Virginia Electric and Power Company, a nonaffiliated utility.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Following is a summary of financial information for AGC in its entirety:

	Year Ended December 31,
(In millions)	2005		2004		2003
Statement of Operations information:
Operating revenues	$	66.6	$	69.2	$	70.5
Operating expenses	$	24.8	$	26.1	$	25.4
Operating income	$	41.9	$	43.1	$	45.1
Net income	$	31.1	$	27.4	$	20.8

	December 31,
(In millions)	2005		2004
Balance sheet information:
Assets:
Current assets	$	6.6	$	9.2
Property, plant and equipment, net		535.2		539.1
Deferred charges		8.4		8.9
Total assets	$	550.2	$	557.2
Liabilities and stockholders’ equity:
Current liabilities	$	9.7	$	5.9
Long-term debt		99.4		114.4
Deferred credits and other liabilities		231.3		236.4
Stockholders’ equity		209.8		200.5
Total liabilities and stockholders’ equity	$	550.2	$	557.2

Cash Equivalents

For purposes of the Consolidated Statements of Cash Flows and Balance Sheets, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, repurchase agreements and money market funds, are considered to be the equivalent of cash.

Transfer of Assets

On June 1, 2001, Monongahela transferred, at book value, approximately 352 MWs of Ohio and FERC generation assets to AE Supply. The PUCO approved the transfer as part of Ohio’s deregulation efforts. In conjunction with the transfer of these assets, AE Supply assumed Monongahela’s obligations with respect to certain pollution control bonds. As of December 31, 2005 and 2004, Monongahela and AE Supply were co-obligors with respect to $12.8 million of these pollution control bonds. These pollution control bonds are included as debt in Monongahela’s Consolidated Balance Sheets. Although AE Supply assumed responsibility for the payment of the pollution control bonds, Monongahela accrues interest expense associated with the bonds. As AE Supply remits payment, Monongahela reduces accrued interest and increases paid-in capital.

AE Supply and Monongahela own certain generation assets jointly as tenants in common. AE Supply operates these jointly-owned assets. Each owner is entitled to the available energy output and capacity in proportion to its ownership of the asset. Monongahela does the billing for the jointly-owned stations located in West Virginia, while AE Supply is responsible for the billing for the Hatfield’s Ferry generation facility, a Pennsylvania station.

See Note 13, “Jointly Owned Electric Utility Plants,” for additional information.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Intercompany Transactions

Monongahela has various operating transactions with affiliates. It is Monongahela’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented on a net basis on the Consolidated Balance Sheets and the Consolidated Statements of Cash Flows.

Substantially all of the employees who work for Monongahela are employed by AESC, which performs services at cost for Monongahela and its affiliates. Monongahela is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to Monongahela for 2005, 2004 and 2003 were $169.2 million, $209.7 million and $212.3 million, respectively.

During 2004, Monongahela’s Delivery and Services segment purchased the majority of the power necessary to serve its Ohio customers who did not choose an alternate electricity generation provider directly from its unregulated generation company affiliate, AE Supply, in accordance with agreements approved by FERC. Monongahela’s expense for these purchases is reflected in “Purchased power and transmission” on its Consolidated Statements of Operations. Beginning in 2005, Monongahela purchased power to serve its commercial industrial customers in Ohio directly from the PJM market. Accordingly, purchased power for Monongahela’s commercial and industrial customers in Ohio was not recorded as affiliated in 2005. For 2005, 2004 and 2003, Monongahela purchased power from AE Supply in the amount of $11.7 million, $48.3 million and $46.7 million, respectively, to serve its Ohio customers. For 2005, 2004 and 2003, Monongahela also paid AE Supply $0.5 million, $0.7 million and $1.1 million, respectively, for ancillary transmission expenses.

Monongahela’s Generation and Marketing segment completes energy purchases and capacity sales transactions with AE Supply at PJM market prices. Prior to January 2005, an affiliated power sales agreement with AE Supply covering these transactions contained a pricing mechanism that included financial transmission rights (“FTRs”) and congestion values, and the transactions were recorded as affiliated revenues and affiliated purchased power and transmission expenses. In January 2005, Monongahela entered into a revised affiliated power sales agreement with AE Supply. Under the revised affiliated power sales agreement, Monongahela records energy and capacity purchase transactions with AE Supply as affiliated purchased power. FTR and congestion values are no longer recorded as affiliated revenue and are classified as nonaffiliated revenue. Monongahela also sells electricity and capacity to AE Supply under a market rate as affiliated revenue. For 2005, 2004 and 2003 Monongahela purchased power from AE Supply in the amount of $94.0 million, $26.3 million and $6.7 million, respectively. For 2005, 2004 and 2003, Monongahela sold power to AE Supply in the amount of $(15.4) million, $19.6 million and $51.0 million, respectively.

Monongahela purchases power from AGC related to AGC’s capacity in the Bath County, Virginia pumped-storage hydroelectric station, in proportion to Monongahela’s equity ownership in AGC. AGC, for reporting purposes, is consolidated with AE Supply. For 2005, 2004 and 2003, these and other purchases from AE Supply amounted to $15.4 million, $15.9 million and $16.2 million, respectively.

In December 2005, Monongahela sold 9,500 vintage 2005 sulfur dioxide (“SO₂”) allowances to its affiliate, AE Supply, for $14.8 million in cash. These allowances were transferred at their carrying value, and the difference between the cash received and the carrying value was recorded as an adjustment to Monongahela’s paid-in capital, net of tax.

AE and its subsidiaries, including Monongahela, file a consolidated federal income tax return. The consolidated income tax liability is allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability. In accordance with this consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various registrants at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the

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intercompany balance. Income taxes payable to affiliates, including both short and long-term obligations, at December 31, 2005 and 2004, were $51.3 million and $53.1 million, respectively.

Monongahela manages excess cash and short-term requirements through an internal money pool. The money pool provides funds at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. Monongahela can lend money into, or borrow money from, the money pool. At December 31, 2005 and 2004, Monongahela had $25.5 million and $42.1 million, respectively, invested in the money pool.

At December 31, 2005 and 2004, Monongahela had net accounts payable to affiliates of $57.4 million and $11.5 million, respectively.

Regulatory Assets and Liabilities

Under cost-based regulation, regulated enterprises are generally permitted to recover their operating expenses and earn a reasonable return on their utility investment.

Monongahela accounts for its operations under the provisions of SFAS No. 71. The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs or revenues would be recognized by an unregulated enterprise. Accordingly, Monongahela records assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” Monongahela periodically evaluates the applicability of SFAS No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities.

See Note 11, “Regulatory Assets and Liabilities,” for additional information.

Inventory

Monongahela values materials, supplies and fuel inventory using an average cost method.

Income Taxes

AE and its subsidiaries, including Monongahela, file a consolidated federal income tax return. The consolidated income tax liability is allocated between AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability.

Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. Mononghela does not expect that any settlement related to such examination will have a material impact on its consolidated statement of operations, financial position or cash flow.

See Note 8, “Income Taxes,” for additional information.

Pension and Other Postretirement Benefits

AE and its subsidiaries have noncontributory, defined benefit pension plans covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. AE’s

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funding policy is to contribute annually to these plans at least the minimum amount required under the Employee Retirement Income Security Act of 1974 (“ERISA”) and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments.

AE’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured. AE does not provide subsidized medical coverage in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees.

Through AESC, Monongahela is responsible for its proportionate share of pension and postretirement benefit costs.

See Note 9, “Pension Benefits and Postretirement Benefits Other than Pensions,” for additional information.

Other Comprehensive Income

Other comprehensive income consists of unrealized gains and losses, net of income taxes, from the temporary change in the fair value of available-for-sale securities.

Recent Accounting Pronouncements

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (“SFAS 153”).    In December of 2004, the FASB issued SFAS 153, which was effective for Monongahela as of July 1, 2005. SFAS 153 amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions” (“APB 29”), by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. The adoption of SFAS 153 did not have a material impact on Monongahela’s consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations” (“EITF 03-13”).    In November of 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”) have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified as held for sale in fiscal periods beginning after

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December 15, 2004. The adoption of EITF 03-13 did not have a material impact on Monongahela’s consolidated results of operations, cash flows or financial position.

NOTE 2:  CAPITALIZATION

Monongahela’s consolidated capital structure, including short-term debt and debt associated with assets held for sale, as of December 31, 2005 and 2004, was as follows:

	2005			2004
(In millions, except percent)	Amount		%	Amount		%
Debt	$	685.0	61.0	$	770.7	58.2
Common equity		414.0	36.9		478.4	36.2
Preferred equity		24.0	2.1		74.0	5.6
Total	$	1,123.0	100.0	$	1,323.1	100.0

Preferred Stock

Each share of Monongahela’s preferred stock is entitled, upon voluntary liquidation, to its then current call price and, on involuntary liquidation, to $100 a share.

On October 31, 2005, Monongahela fully redeemed its $50.0 million of outstanding $7.73, Series L ($100 par value) Cumulative Preferred Stock. In connection with the redemption, Monongahela paid accrued and unpaid dividends of approximately $1 million.

Return of Capital

During October 2005, Monongahela returned $80.0 million of capital to AE using a portion of the cash proceeds from the sale of its West Virginia natural gas operations.

Short-term Debt

No short-term debt was outstanding at December 31, 2005 and 2004.

Average short-term debt outstanding for 2005 and 2004 consisted of:

	2005				2004
(In millions)	Amount		Rate		Amount		Rate
Average amount outstanding and interest rate during the year:
Bridge loan	$	—	—	%	$	23.5	4.59	%

Long-term Debt

At December 31, 2005, contractual maturities for long-term debt, excluding unamortized discounts of $0.7 million, are as follows:

(In millions)	2006		2007		2008		2009		2010		Thereafter		Total
First Mortgage Bonds	$	300.0	$	—	$	—	$	—	$	—	$	190.0	$	490.0
Pollution Control Bonds		—		15.5		—		—		—		70.2		85.7
Medium-Term Notes		—		—		—		—		110.0		—		110.0
Total	$	300.0	$	15.5	$	—	$	—	$	110.0	$	260.2	$	685.7

At December 31, 2005, substantially all of Monongahela’s properties were held subject to liens of various relative priorities securing debt obligations.

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2005 Debt Activity

In connection with Monongahela’s sale of its West Virginia natural gas operations, $86.7 million of debt previously classified as liabilities associated with assets held for sale was transferred to the buyer.

On October 17, 2005, Monongahela issued $70.0 million of 5.375% First Mortgage Bonds due 2015. Monongahela used the proceeds and available cash to redeem $70.0 million of its 7 ⁵/8% First Mortgage Bonds due May 2025 on November 19, 2005.

The following issuances and redemptions of debt were made during 2005:

(In millions)	Issuances		Redemptions
First Mortgage Bonds	$	70.0	$	70.0
Debt associated with assets held for sale:
Other Notes (a)	$	—	$	86.7

(a) Represents debt related to Monongahela’s natural gas operations in West Virginia. In connection with the sale of these operations on September 30, 2005, the purchaser assumed this debt.

2004 Debt Activity

In June 2004, Monongahela issued $120.0 million of 6.70% First Mortgage Bonds, which mature on June 15, 2014. The net proceeds of the bond issuance were used to repay Monongahela’s $53.6 million short-term bridge loan in June 2004 and to fund the July 2004 redemption of $40 million of 8.375% First Mortgage Bonds due 2022 and $25 million of 7.25% First Mortgage Bonds due 2007.

The following issuances and redemptions of debt were made during 2004:

(In millions)	Issuances		Redemptions
First Mortgage Bonds	$	120.0	$	65.0
Short-Term Debt		—		53.6
Total	$	120.0	$	118.6

NOTE 3:  DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

On September 30, 2005, Monongahela sold its West Virginia natural gas operations. The results of operations relating to these assets have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. In addition, the assets and liabilities associated with these discontinued operations were classified as held for sale in the accompanying balance sheet from the third quarter of 2004 to the date of sale.

The components of income (loss) from discontinued operations are as follows:

(In millions)	2005			2004			2003
Operating revenues	$	218.1		$	306.4		$	268.8
Operating expenses		(201.6	)		(285.2	)		(246.2	)
Other income (expenses)		1.0			0.2			0.5
Interest expense		(6.1	)		(8.3	)		(8.7	)
Income (loss) before income taxes		11.4			13.1			14.4
Income tax benefit (expense)		(3.4	)		(5.3	)		(5.2	)
Impairment charge, net of tax		(7.0	)		(21.7	)		—
Income (loss) from discontinued operations, net of tax	$	1.0		$	(13.9	)	$	9.2

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Impairment charges, reflected in the table above, represent adjustments of the carrying values of assets held for sale to current estimates of sales proceeds, less costs to sell.

Assets held for sale and liabilities associated with assets held for sale were as follows:

(In millions)	2004
Assets:
Current assets	$	147.8
Property, plant and equipment		163.7
Investments and other assets		6.8
Deferred charges		6.3
Total assets	$	324.6
Liabilities:
Current liabilities	$	95.5
Long-term debt		83.4
Deferred credits and other liabilities		17.6
Total liabilities	$	196.5

See Note 4, “Asset Sales,” for additional information.

NOTE 4:  ASSET SALES

On December 31, 2005, Monongahela completed the sale of its Ohio electric T&D assets to Columbus Southern for net cash proceeds of $51.8 million. The purchase price for the assets was the net book value at the time of closing, plus $10.0 million, less certain property taxes. The sale included a power sales agreement under which Monongahela will provide power to Columbus Southern to serve Monongahela’s former Ohio retail customer base through May 31, 2007 at $45 per megawatt-hour, which is less than the projected market price for power. Monongahela recorded a loss on the sale in the amount of $29.3 million based, in part, on the estimated fair value at December 31, 2005 of its agreement to provide power at below-market prices through May 31, 2007.

On September 30, 2005, Monongahela completed the sale of its natural gas operations in West Virginia to Mountaineer Gas Holdings Limited Partnership, a partnership composed of IGS Utilities LLC, IGS Holdings LLC and affiliates of ArcLight Capital Partners, LLC, for approximately $161.0 million in cash and the assumption of approximately $87.0 million of long-term debt. The assets sold included all of the issued and outstanding capital stock of Mountaineer Gas and certain other assets related to the West Virginia natural gas operations.

NOTE 5:  ASSET RETIREMENT OBLIGATIONS (“ARO”)

Effective January 1, 2003, Monongahela adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS No. 143 requires that the fair value of asset retirement costs for which Monongahela has a legal obligation be recorded as liabilities, with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.

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The effect of adopting SFAS No. 143 on Monongahela’s Consolidated Financial Statements in 2003 was as follows:

(In millions)	Property, Plant and Equipment, Net		Non-current Regulatory asset		Non-current liabilities (ARO’s)		Decrease in Pre-Tax income			Decrease in Net income
Monongahela	$	3.0	$	2.3	$	6.1	$	(0.8	)	$	(0.4	)

Effective December 31, 2005, Monongahela adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations (“Conditional AROs”)” which requires an entity to recognize a liability for the fair value of a Conditional ARO if the fair value of the liability can be reasonably estimated. The obligation to perform the asset retirement activity is unconditional, even though uncertainty exists about the timing and (or) method of settlement.

Monongahela recorded Conditional AROs related to asbestos contained in its generating facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”). The effect of adopting FIN 47 on Monongahela’s Consolidated Financial Statements in 2005 was a $0.3 million increase in property, plant and equipment, net, a $5.3 million increase in non-current regulatory assets, and the recognition of a $5.6 million non-current liability.

Under the rate-making process, regulators generally permit recovery of costs associated with removing property, plant and equipment. Monongahela believes it is probable that any difference between expenses recorded under SFAS No. 143 and FIN 47 and expenses recovered currently in rates with respect to these assets will be recoverable in future rates. Therefore, Monongahela is deferring these differences in expenses as a regulatory asset.

For 2005, Monongahela’s total ARO balance, which includes AROs and Conditional AROs, increased $6.2 million, from $6.7 million at December 31, 2004 to $12.9 million at December 31, 2005. This increase was primarily due to Monongahela recording $5.6 million of certain Conditional ARO liabilities associated with the adoption of FIN 47 for Conditional Asset Retirement Obligations” and $0.6 million of accretion expense.

Estimated removal costs of $242.1 million and $241.8 million at December 31, 2005 and December 31, 2004, respectively, are being recovered through the rate-making process. These amounts are reported as regulatory liabilities.

Had the provisions of FIN No. 47 been adopted on January 1, 2003, there would have been no impact on Monongahela’s income before cumulative effect of accounting change and net income.

Had the provisions of FIN No. 47 been adopted on January 1, 2003, Monongahela’s ARO liability would have been $5.0 million at January 1, 2004 and $5.3 million at December 31, 2004.

NOTE 6:  BUSINESS SEGMENTS

Monongahela manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. The Delivery and Services segment includes Monongahela’s electric T&D operations. The Generation and Marketing segment owns, operates and manages electric generation capacity. The Generation and Marketing segment includes intersegment sales to provide energy to Monongahela’s Delivery and Services segment. Monongahela accounts for intersegment sales based on cost or regulatory commission approved tariffs or contracts.

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Business segment information is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts.

(In millions)	2005			2004			2003
Operating revenues:
Delivery and Services	$	691.4		$	669.0		$	655.4
Generation and Marketing		415.5			312.8			350.9
Eliminations		(317.0	)		(298.0	)		(287.4	)
Total	$	789.9		$	683.8		$	718.9
Depreciation and amortization:
Delivery and Services	$	31.5		$	31.4		$	29.8
Generation and Marketing		34.8			34.4			33.9
Total	$	66.3		$	65.8		$	63.7
Operating income (loss):
Delivery and Services	$	28.0		$	64.2		$	51.2
Generation and Marketing		(3.1	)		(17.4	)		33.9
Total	$	24.9		$	46.8		$	85.1
Interest expense:
Delivery and Services	$	25.1		$	24.8		$	22.2
Generation and Marketing		18.3			18.5			21.2
Total	$	43.4		$	43.3		$	43.4
Income (loss) from continuing operations, net:
Delivery and Services	$	8.4		$	30.4		$	16.2
Generation and Marketing		0.8			(14.0	)		55.8
Total	$	9.2		$	16.4		$	72.0
Income (loss) from discontinued operations, net:
Delivery and Services	$	1.0		$	(13.9	)	$	9.2
Generation and Marketing		—			—			—
Total	$	1.0		$	(13.9	)	$	9.2
Cumulative effect of accounting change, net:
Delivery and Services	$	—		$	—		$	(0.5	)
Generation and Marketing		—			—			—
Total	$	—		$	—		$	(0.5	)
Net income (loss):
Delivery and Services	$	9.4		$	16.5		$	24.9
Generation and Marketing		0.8			(14.0	)		55.8
Total	$	10.2		$	2.5		$	80.7
Capital expenditures:
Delivery and Services	$	47.3		$	40.1
Generation and Marketing		24.4			13.6
Total	$	71.7		$	53.7
Identifiable assets:
Delivery and Services	$	916.9		$	1,272.7
Generation and Marketing		526.1			524.6
Other		416.2			284.1
Total	$	1,859.2		$	2,081.4

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NOTE 7:  INTANGIBLE ASSETS

Intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:

	December 31, 2005				December 31, 2004
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Land easements, amortized	$	0.5	$	0.2	$	0.5	$	0.2
Land easements, unamortized		30.6		—		31.8		—
Software		0.3		0.3		7.9		7.2
Total	$	31.4	$	0.5	$	40.2	$	7.4

In addition, “Assets held for sale” included intangible assets related to natural gas rights, amortized with a gross carrying amount and accumulated amortization of $6.6 million and $4.0 million, respectively, at December 31, 2004.

Amortization expense for other intangible assets for 2005, 2004 and 2003 was $1.0 million, $2.3 million and $2.9 million, respectively.

Amortization expense is estimated to be less than $0.1 million for 2006 through 2010.

NOTE 8:  INCOME TAXES

Details of federal and state income tax from continuing operations are as follows:

(In millions)	2005			2004			2003
Income tax expense (benefit)—current:
Federal	$	3.6		$	(0.4	)	$	7.0
State		(3.2	)		0.8			0.2
Total		0.4			0.4			7.2
Income tax—expense (benefit) deferred, net		(13.1	)		(2.1	)		34.1
Amortization of deferred investment tax credit		(2.1	)		(2.1	)		(2.1	)
Total income tax expense (benefit)	$	(14.8	)	$	(3.8	)	$	39.2

Taxable income differs from pre-tax accounting income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using enacted tax rates in effect in the years in which the differences are expected to reverse.

During the second quarter of 2005, Allegheny determined that it had not claimed certain income tax deductions in its 2003 income tax returns relating to commodity trading contracts. Allegheny filed a claim for these additional deductions, which increased Monongahela’s allocated share of consolidated tax savings. Accordingly, Monongahela recorded a tax benefit of $4.3 million during the second quarter of 2005 to recognize the additional tax savings. The effect of this adjustment was not material to Monongahela’s results of operations for the years ended December 31, 2005 and 2003.

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Monongahela has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.

The total provision for income tax from continuing operations differs from the amount produced by applying the federal statutory income tax rate of 35% to income (loss) from continuing operations, before income taxes, as set forth below:

	2005					2004					2003
(In millions, except percent)	Amount			%		Amount			%		Amount			%
Income (loss) from continuing operations, before income taxes	$	(5.6	)			$	12.6				$	111.1
Income tax expense (benefit) calculated using the federal statutory rate of 35%		(1.9	)	35.0			4.4		35.0			38.9		35.0
Increases (reductions) resulting from:
Tax deductions for which deferred tax was not provided:
Depreciation		1.5		(26.8	)		0.7		5.5			7.0		6.3
Plant removal costs		(0.8	)	14.3			(0.9	)	(7.1	)		(1.8	)	(1.6	)
State income tax, net of federal income tax benefit		(7.1	)	126.8			(3.3	)	(26.2	)		6.2		5.6
Amortization of deferred investment tax credit		(2.1	)	37.5			(2.1	)	(16.7	)		(2.1	)	(1.9	)
Consolidated return benefit		(2.6	)	46.4			(0.2	)	(1.6	)		(0.3	)	(0.2	)
Equity in earnings of subsidiaries		(2.5	)	44.6			(2.2	)	(17.5	)		(1.8	)	(1.6	)
Accrual versus return adjustment		—		—			(0.9	)	(7.1	)		2.3		2.1
Reapplication of SFAS No. 71		—		—			—		—			(9.7	)	(8.8	)
Other, net		0.7		(13.5	)		0.7		5.5			0.5		0.4
Total income tax expense (benefit)	$	(14.8	)	264.3		$	(3.8	)	(30.2	)	$	39.2		35.3

The total provision for income tax expense (benefit) from discontinued operations differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount, as set forth below:

(In millions)	2005			2004			2003
Income (loss) from discontinued operations, before income taxes	$	(0.4	)	$	(23.6	)	$	14.4
Income tax expense (benefit) calculated using the federal statutory rate of 35%	$	(0.1	)	$	(8.3	)	$	5.0
Adjusted for state income tax, net of federal income tax benefit		(1.3	)		(1.3	)		0.8
Other		—			—			(0.6	)
Total income tax expense (benefit)	$	(1.4	)	$	(9.6	)	$	5.2

The total provision for income tax benefit for the cumulative effect of accounting change differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount, as set forth below:

(In millions)	2005		2004		2003
Cumulative effect of accounting change, before income taxes	$	—	$	—	$	(0.8	)
Income tax benefit calculated using the federal statutory rate of 35%	$	—	$	—	$	(0.3	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At December 31, the deferred tax assets and liabilities consisted of the following:

(In millions)	2005		2004
Deferred tax assets:
Unamortized investment tax credit	$	0.3	$	1.8
Tax effect of net operating loss carryforwards		66.2		44.2
Other		20.0		29.3
Total deferred tax assets		86.5		75.3
Deferred tax liabilities:
Plant asset basis differences, net		262.1		246.5
Other		18.4		24.6
Total deferred tax liabilities		280.5		271.1
Total net deferred tax liabilities		194.0		195.8
Portion above included in current assets (liabilities)		0.2		(5.3	)
Total long-term net deferred tax liabilities	$	194.2	$	190.5

Monongahela recorded as deferred tax assets the effect of net operating losses, which will more likely than not be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2025. In addition, Monongahela is a party to a consolidated tax sharing agreement, which was amended effective July 1, 2003. Monongahela can realize the benefits of its net operating loss carryforwards generated prior to this date only to the extent of its future taxable income. Monongahela expects to realize benefits represented by deferred tax assets through its participation in the consolidated tax return in future years.

NOTE 9:  PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Monongahela is responsible for its proportionate share of the net periodic cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. Monongahela’s share of the costs, of which approximately 21%, 19% and 16% in 2005, 2004 and 2003, respectively, were allocated to “Construction work in progress,” a component of “Property, plant and equipment, net,” was as follows:

(In millions)	2005		2004		2003
Pension	$	10.0	$	11.6	$	8.1
Medical and life insurance	$	9.0	$	9.3	$	8.4

The assumptions used to determine net periodic benefit costs for years ended December 31, 2005, 2004 and 2003 are shown in the table below.

	Pension Benefits						Postretirement Benefits Other Than Pensions
	2005		2004		2003		2005		2004		2003
Discount rate	5.90	%	6.00	%	6.50	%	5.90	%	6.00	%	6.50	%
Expected long-term rate of return on plan assets *	8.50	%	8.50	%	9.00	%	8.50	%	8.50	%	9.00	%
Rate of compensation increase	3.25	%	3.75	%	4.00	%	3.25	%	3.75	%	4.00	%

* Excluding administrative expenses.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The assumptions used to determine benefit obligations at year-end 2005 and 2004 are shown in the table below:

	Pension Benefits				Postretirement Benefits Other Than Pensions
	2005		2004		2005		2004
Discount rate	5.60	%	5.90	%	5.60	%	5.90	%
Rate of compensation increase	3.25	%	3.25	%	3.25	%	3.25	%

In selecting an assumed discount rate, Allegheny uses a modeling process that involves selecting a portfolio of high-quality bonds (AA- or better) whose cash flows (via coupons and maturities) match the timing and amount of Allegheny’s expected future benefit payments. Allegheny considers the results of this modeling process, as well as overall rates of return on high quality corporate bonds and changes in such rates over time, in the determination of its assumed discount rate.

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs for 2006 is 8.25%, which is net of administrative expenses.

Assumed health care cost trend rates at December 31 are as follows:

	2005		2004
Health care cost trend rate assumed for next year	9.5	%	9.5	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2015		2014

For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.5% beginning with 2006 and grading down by 0.5% each year to an ultimate rate of 5.0%, and plan provisions that limit future medical and life insurance benefits. Because of the plan provisions that limit future benefits, changes in the assumed health care cost trend rate would have a limited effect on the amounts displayed in the table above.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) became law. Beginning in 2006, the federal government will provide subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. The subsidy would be 28% of eligible drug costs for retirees that are over age 65 and covered under Allegheny’s postretirement benefits other than pensions plan.

Allegheny elected to follow the deferral provisions of FASB Staff Position (“FSP”) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-1”). FSP 106-1 permits employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until guidance on the accounting for the federal subsidy is issued. On May 19, 2004, FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”), which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Allegheny has determined that the prescription drug benefit offered under its postretirement benefits other than pensions plan is at least actuarially equivalent to Medicare Part D and therefore, expects to receive the federal subsidy offered under the Medicare Act. Allegheny expects to receive subsidies of approximately $2.0 million to $3.0 million annually during the period 2006 through 2010, and expects to receive an aggregate of approximately $3.0 million during the period 2011 through 2015. Also, beginning in 2006, Allegheny’s annual net periodic postretirement benefit cost was reduced by approximately $1.8 million as a result of the expected sharing of the cost of the program by Medicare.

NOTE 10:  ACCOUNTING FOR THE EFFECTS OF PRICE REGULATION

In 1998, the West Virginia legislature passed legislation directing the West Virginia PSC to determine whether retail electric competition was in the best interests of West Virginia and its citizens. In response, the West Virginia PSC submitted a plan to introduce full retail competition on January 1, 2001. This plan was approved, but never implemented, by the legislature. In 2002, the West Virginia PSC issued orders dismissing deregulation proceedings. Based on these actions, Monongahela concluded that retail competition and the deregulation of generation assets is no longer probable and that the generation operations in West Virginia meet the requirements of SFAS No. 71.

Monongahela reapplied the provisions of SFAS No. 71 to its West Virginia generation assets in the first quarter of 2003 and recorded a gain of $61.7 million as part of “Other income and expenses, net” in the Consolidated Statements of Operations. This gain was primarily the result of the elimination of its transition obligation and the reestablishment of regulatory assets related to deferred income taxes.

The Consolidated Balance Sheets do not include any amounts for generation assets not subject to SFAS No. 71 as of December 31, 2005 and 2004.

NOTE 11:  REGULATORY ASSETS AND LIABILITIES

Monongahela’s electric generation and T&D operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:

(In millions)	2005		2004
Regulatory assets, including current portion:
Income taxes	$	77.4	$	85.0
Unamortized loss on reacquired debt		16.2		14.9
Other		11.9		4.3
Subtotal		105.5		104.2
Regulatory liabilities:
Non-legal asset removal costs		242.1		241.8
Other		0.3		2.2
Subtotal		242.4		244.0
Net regulatory liabilities	$	136.9	$	139.8

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Income Taxes, Net

In certain jurisdictions, deferred income tax expense is not permitted as a cost in the determination of rates charged to customers. In these jurisdictions a deferred income tax liability is recorded with an offsetting regulatory asset. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. These deferred income taxes relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. No return is allowed on the regulatory asset for income taxes.

See Note 10, “Accounting for the Effects of Price Regulation,” for a discussion regarding Monongahela’s reapplication of the provisions of SFAS No. 71.

See Note 5, “Asset Retirement Obligation,” for additional information on non-legal ARO costs.

NOTE 12:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year, and preferred stock of subsidiary, at December 31, were as follows:

	2005				2004
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	685.0	$	703.4	$	684.0	$	702.2
Preferred stock (all series)	$	24.0	$	17.8	$	74.0	$	67.6

The above table excludes long-term debt with a carrying amount of $86.7 million and a fair value of $95.1 million related to liabilities associated with assets held for sale at December 31, 2004. This debt was transferred to the buyer in connection with the September 30, 2005 sale of these assets.

The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The fair value of preferred stock is based on quoted market prices. The carrying amounts of cash equivalents and short-term debt approximate the fair values of these financial instruments because of the short maturities of those instruments.

NOTE 13:  JOINTLY OWNED ELECTRIC UTILITY PLANTS

Monongahela shares ownership of seven generation facilities with AE Supply. Monongahela records its proportionate share of operating costs, assets and liabilities in the corresponding lines in the Consolidated Financial Statements. As of December 31, 2005 and 2004, Monongahela’s utility plant investment and accumulated depreciation in these generation facilities were as follows:

	December 31, 2005						December 31, 2004
Generation facility	Ownership %		Utility Plant Investment		Accumulated Depreciation		Ownership %		Utility Plant Investment		Accumulated Depreciation
(Dollars in millions)
Albright	57.6	%	$	68.9	$	49.1	56.7	%	$	68.3	$	48.3
Fort Martin	19.1	%	$	70.6	$	61.0	19.1	%	$	68.9	$	59.2
Harrison	21.3	%	$	294.8	$	174.7	21.3	%	$	288.5	$	164.1
Hatfield’s Ferry	23.4	%	$	143.9	$	77.3	23.4	%	$	139.0	$	74.0
Pleasants	21.3	%	$	247.1	$	148.9	21.3	%	$	246.4	$	141.9
Rivesville	85.1	%	$	48.9	$	39.0	85.1	%	$	48.4	$	37.1
Willow Island	85.1	%	$	89.7	$	63.0	85.1	%	$	88.3	$	60.0

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Through its 22.97% interest in AGC, Monongahela also owns an interest in AGC’s jointly owned electric utility plant. AGC’s 40% investment and accumulated depreciation in the Bath County generation facility jointly owned with a third party at December 31, 2005 and 2004, were as follows:

(Dollars in millions)	2005			2004
Utility plant investment	$	839.0		$	829.5
Accumulated depreciation	$	316.3		$	303.7
Ownership %		40	%		40	%

NOTE 14:  OTHER INCOME AND EXPENSES, NET

Other income and expenses, net represents non-operating income and expenses before income taxes. The following table summarizes Monongahela’s other income and expenses, net:

(In millions)	2005		2004		2003
Equity in earnings of AGC	$	7.1	$	6.3	$	4.8
Interest income		4.4		0.8		0.9
Premium services		0.4		0.9		0.7
Reapplication of SFAS No. 71		—		—		61.7
Storm restoration, net		—		0.5		—
Other		1.0		0.6		1.4
Total other income and expenses, net	$	12.9	$	9.1	$	69.5

NOTE 15:  QUARTERLY FINANCIAL INFORMATION (Unaudited)

	2005 Quarters Ended (1)											2004 Quarters Ended (1)
(In millions)	December 31			September 30			June 30			March 31		December 31		September 30			June 30			March 31
Operating revenues	$	204.7		$	220.5		$	178.1		$	186.6	$	172.1	$	171.2		$	160.3		$	180.2
Operating income (loss)	$	(1.2	)	$	(1.8	)	$	8.4		$	19.5	$	17.7	$	13.8		$	(9.8	)	$	25.0
Income (loss) from continuing operations	$	(5.8	)	$	(5.4	)	$	9.1		$	11.3	$	12.2	$	7.2		$	(10.7	)	$	7.7
Income (loss) from discontinued operations, net		3.4			(6.8	)		(6.5	)		10.9		1.4		(25.2	)		(1.1	)		11.0
Net income (loss)	$	(2.4	)	$	(12.2	)	$	2.6		$	22.2	$	13.6	$	(18.0	)	$	(11.8	)	$	18.7

(1) Amounts may not total to year to date results due to rounding.

NOTE 16:  COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Allegheny is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Clean Air Act Matters.  Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through reduction of output. From time to time, minor excursions of stack emission opacity that are normal to fossil fuel operations are experienced and are accommodated by the regulatory process. Allegheny meets current emission standards for SO₂ by using emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

Allegheny’s compliance with the Clean Air Act of 1970 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the U.S. Environmental Protection Agency (the “EPA”) on March 10, 2005, may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Based on current forecasts, Allegheny estimates that it may have an SO₂ allowance market exposure of less than 10,000 tons in 2006 and approximately 20,000 tons and 75,000 tons in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Allegheny continues to evaluate options for compliance, and current plans include the potential installation of scrubbers to its Fort Martin generation facility by 2010, as well as the elimination of a scrubber bypass at its Pleasants generation facility by 2008 and the consideration of scrubbers at its Hatfield generation facility.

Allegheny meets current emission standards for nitrogen oxides (“NO_X”) by using low NO_X burners, Selective Catalytic Reduction, Selective Non-Catalytic Reduction and over-fire air and optimization software, as well as through the use of emission allowances. Allegheny is currently evaluating its options for CAIR compliance. In 1998, the EPA finalized its NOx State Implementation Plan (“SIP”) call rule (known as the “NOx SIP call”), which addressed the regional transport of ground-level ozone and required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Pennsylvania, Maryland and West Virginia.

AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. AE Supply estimates that its emission control activities, in concert with its inventory of banked allowances, will facilitate its compliance with NOx limits established by the SIP through 2008. Allegheny’s current capital expenditure forecast includes the expenditure of $2 million of capital costs during 2007 for additional NO_X emission controls. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates.

On March 15, 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”) establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and its strategy for compliance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these generation stations. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the new source review (“NSR”) standards of the Clean Air Act, which can require the installation of additional air pollution control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues.

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology. There are three recent, significant federal court decisions that have addressed the application of NSR requirements to electric utility generation facilities: the Ohio Edison decision, the Duke Energy decision and the Alabama Power decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy and Alabama Power decisions support the industry’s understanding of NSR requirements. The U.S. Court of Appeals for the Fourth Circuit affirmed the Duke Energy decision on June 15, 2005.

In 2003, the U.S. EPA issued the Equipment Replacement Rule, which sets forth a clearer set of rules for projects that may be undertaken without triggering NSR requirement. This rule would apply the Routine Maintenance, Repair and Replacement (“RMRR”) exception to the NSR requirement in a manner that is more consistent with the energy industry’s historical compliance approach. That rule was challenged by some states and environmental groups and, on December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the implementation of that rule. At this time, AE and its subsidiaries are not able to determine the effect that these actions may have on them.

On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from the Pennsylvania Department of Environmental Protection (“PA DEP”). The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

On January 6, 2005, AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal district court in West Virginia (“West Virginia DJ Action”). This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia comply with the Clean Air Act. The Attorneys General filed a motion to dismiss the West Virginia DJ Action. It is possible that the EPA and other state authorities may join or move to transfer the West Virginia DJ Action.

On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Distribution Companies in the U.S. District Court for the Western District of Pennsylvania (the “PA Enforcement Action”). This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the federal District Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. Allegheny’s motion to stay the PA Enforcement Action was denied on November 21, 2005. On January 17, 2006, the PA DEP and the Attorneys General filed an amended compliant. On February 15, 2006, Allegheny filed a motion to dismiss the amended complaint.

On February 16, 2005, Citizens for Pennsylvania’s Future, an environmental group, sued Allegheny in the U.S. District Court for the Western District of Pennsylvania. The action alleges violations of opacity limits and particulate matter emission limits at the Hatfield’s Ferry generation facility.

Allegheny intends to vigorously pursue and defend against the environmental matters described above but cannot predict their outcomes.

Canadian Toxic-Tort Class Action:  On June 30, 2005, AE Supply, Monongahela and AGC, along with 18 other companies with coal-fired generation facilities, were named as defendants in a toxic-tort, purported class action lawsuit filed in the Ontario Superior Court of Justice. On behalf of a purported class comprised of all persons residing in Ontario within the past six years (and/or their family members or heirs), the named plaintiffs allege that the defendants negligently failed to prevent their generation facilities from emitting air pollutants in such a manner as to cause death and multiple adverse health effects, as well as economic damages, to the plaintiff class. The plaintiffs seek damages in the approximate amount of Canadian $49.1 billion (approximately US $41.6 billion, assuming an exchange rate of 1.18 Canadian dollars per US dollar), along with continuing damages in the amount of Canadian $4.1 billion per year and punitive damages of Canadian $1.0 billion (approximately US $3.5 billion and US $850 million, respectively, assuming an exchange rate of 1.18 Canadian dollars per US dollar) along with such other relief as the court deems just. Allegheny has not yet been served with this lawsuit. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

Claims Related to Alleged Asbestos Exposure:  The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties in these actions are seeking an allocation of responsibility for historic and potential future asbestos liability.

Allegheny and numerous others are plaintiffs in a similar action filed against Zurich Insurance Company in California, Fuller-Austin Asbestos Settlement Trust, et al. v. Zurich-American Insurance Co., et al., Case No. CGC 04 431719 (Superior Court of California, County of San Francisco).

In connection with a settlement, Allegheny received payment from one of its insurance companies in the amount of $625,000 on July 5, 2005, with the next payment of $625,000 due July 1, 2006. As part of the settlement, Allegheny released this insurance company from potential liabilities associated with claims against Allegheny alleging asbestos exposure.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2005, Allegheny had 930 open cases remaining in West Virginia and five open cases remaining in Pennsylvania.

Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”) Claim: On March 4, 1994, Monongahela and certain affiliated companies received notice that the EPA had identified them as potentially responsible parties (“PRPs”) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site in Pennsylvania. Initially, approximately 175 PRPs were involved; however, the current number of active PRPs has been reduced as a result of settlements with de minimis contributors and other contributors to the site. The costs of remediation will be shared by all past and active responsible parties. In 1999, a PRP group that included Monongahela and certain affiliated companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30.0 million. Allegheny has an accrued liability representing its estimated share of the remediation costs as of December 31, 2005.

Ordinary Course of Business:  Monongahela is from time to time involved in litigation and other legal disputes in the ordinary course of business. Monongahela is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.

Construction and Capital Program

Monongahela’s expenditures for capital programs are estimated to be approximately $101.0 million for 2006 and $141.0 million for 2007. Capital expenditure levels in 2007 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. See “Environmental Matters and Litigation—Clean Air Act Matters,” above.

Leases

Monongahela has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles, buildings and computer equipment.

Total capital and operating lease rent payments of $7.3 million in 2005, $7.8 million in 2004 and $8.8 million in 2003 were recorded as rent expense. Monongahela’s estimated future minimum lease payments for capital and operating leases, including those leases entered into by AESC which are allocated to Monongahela and certain other leases related to discontinued operations, with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are:

(In millions)	2006		2007		2008		2009		2010		Thereafter		Total		Less amounts representing interest and fees		Present value of net minimum capital lease
Capital Leases	$	3.9	$	2.8	$	2.1	$	1.6	$	0.9	$	0.5	$	11.8	$	3.0	$	8.8
Allocated Capital Leases		0.3		0.1		0.1		—		0.2		—		0.7		0.1		0.6
Total Capital Leases	$	4.2	$	2.9	$	2.2	$	1.6	$	1.1	$	0.5	$	12.5	$	3.1	$	9.4
Operating Leases	$	0.5	$	0.2	$	0.1	$	0.1	$	—	$	—	$	0.9	$	—	$	—

218

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The carrying amount of assets recorded under capitalized lease agreements included in “Property, plant and equipment, net” at December 31 consists of the following:

(In millions)	2005		2004
Equipment	$	8.4	$	11.7
Building		0.4		0.5
Property held under capital leases	$	8.8	$	12.2

PURPA

The Public Utility Regulatory Policies Act of 1978 (“PURPA”) has required electric utility companies, such as Monongahela, to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. State public service commissions or legislatures establish the rates paid for electric energy purchased from qualifying facilities.

The Energy Policy Act has amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contract obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission. This change does not impact Monongahela’s current PURPA contracts

Monongahela is committed to purchase the electrical output from 161 MWs of qualifying PURPA capacity. Payments for PURPA capacity and energy in 2005, 2004 and 2003 totaled $57.9 million, $56.6 million and $48.9 million, respectively. The amount for 2003 excludes a contractually required payment received in accordance with certain contract provisions at a hydroelectric facility that supplies power to Monongahela. The average cost to Monongahela of these power purchases was approximately 4.4, 4.3 and 5.2 cents per kWh for 2005, 2004 and 2003, respectively. Monongahela is currently authorized to recover PURPA costs in its retail rates.

The table below reflects Monongahela’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2005. Actual values can vary substantially depending upon future conditions.

(In millions)	kWhs	Amount
2006	1,302.6	$	58.1
2007	1,302.6	$	58.3
2008	1,305.5	$	58.7
2009	1,302.6	$	58.8
2010	1,302.6	$	61.4
Thereafter	23,679.2	$	1,162.7

Fuel Purchase and Transportation Commitments

Monongahela has entered into various long-term commitments for the procurement and transportation of fuel (primarily coal and lime) to supply its generation facilities. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Monongahela’s fuel consumed in electric generation was $148.4 million, $119.1 million and $135.1 million in 2005, 2004 and 2003,

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

respectively. In 2005, Monongahela purchased approximately 57% of its fuel from one vendor. Total estimated long-term fuel purchase and transportation commitments (primarily coal and lime), were as follows, by year, and in total:

(In millions)	Amount
2006	$	134.2
2007		111.8
2008		85.7
2009		66.6
2010		55.1
Thereafter		467.8
Total	$	921.2

220

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Monongahela Power Company:

In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of operations, stockholder’s equity and cash flows present fairly, in all material respects, the financial position of Monongahela Power Company and its subsidiaries (the “Company”) 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. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule 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.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 28, 2006

221

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

Consolidated Statements of Operations

	Year Ended December 31,
(In thousands)	2005			2004		2003
Operating revenues	$	971,201		$	924,425	$	905,214
Operating expenses:
Purchased power and transmission		669,372			645,835		642,730
Deferred energy costs, net		(1,528	)		204		(1,737	)
Operations and maintenance		104,687			106,199		116,437
Depreciation and amortization		43,173			39,622		38,320
Taxes other than income taxes		35,366			34,207		38,214
Total operating expenses		851,070			826,067		833,964
Operating income		120,131			98,358		71,250
Other income and expenses, net (Note 10)		7,241			6,725		21,053
Interest expense		27,590			32,267		31,093
Income before income taxes and cumulative effect of accounting change		99,782			72,816		61,210
Income tax expense		33,428			34,835		20,652
Income before cumulative effect of accounting change		66,354			37,981		40,558
Cumulative effect of accounting change, net of tax		—			—		(79	)
Net income	$	66,354		$	37,981	$	40,479

See accompanying Notes to Consolidated Financial Statements.

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THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

Consolidated Statements of Cash Flows

	Year Ended December 31,
(In thousands)	2005			2004			2003
Cash Flows From Operating Activities:
Net income	$	66,354		$	37,981		$	40,479
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of accounting change, net		—			—			79
Reapplication of SFAS No. 71		—			—			(14,100	)
Depreciation and amortization		43,173			39,622			38,320
Loss (gain) on asset sales		4			(298	)		(1,885	)
Deferred income taxes and investment tax credit, net		11,348			29,557			3,160
Deferred energy costs, net		(1,528	)		204			(1,737	)
Other, net		1,864			2,458			713
Changes in certain assets and liabilities:
Accounts receivable, net		(11,821	)		3,120			11,460
Materials and supplies		(885	)		(1,105	)		328
Taxes receivable / accrued, net		(1,173	)		3,533			14,693
Other current assets		2,071			(3,666	)		39
Accounts payable		3,087			(2,763	)		6,032
Accounts payable to affiliates, net		(21,058	)		(828	)		8,868
Collateral deposits held		(9,719	)		9,719			—
Other current liabilities		4,363			3,581			4,813
Other assets		4,362			7,014			(18,540	)
Non-current income taxes payable		—			—			12,317
Other liabilities		257			(2,455	)		15,211
Net cash provided by operating activities		90,699			125,674			120,250
Cash Flows From Investing Activities:
Capital expenditures		(73,623	)		(66,879	)		(53,773	)
Proceeds from sale of assets		10,636			635			1,087
Decrease (increase) in restricted funds		9,719			(9,719	)		—
Net cash used in investing activities		(53,268	)		(75,963	)		(52,686	)
Cash Flows From Financing Activities:
Note receivable from affiliate		14,432			(14,432	)		—
Notes payable to affiliates		2,392			—			(8,500	)
Issuance of long-term debt		142,235			172,742			—
Retirement of long-term debt		(149,615	)		(180,600	)		—
Cash dividends paid on common stock		(63,084	)		(42,980	)		(30,443	)
Net cash used in financing activities		(53,640	)		(65,270	)		(38,943	)
Net increase (decrease) in cash and cash equivalents		(16,209	)		(15,559	)		28,621
Cash and cash equivalents at beginning of period		16,231			31,790			3,169
Cash and cash equivalents at end of period	$	22		$	16,231		$	31,790
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest (net of amount capitalized)	$	23,734		$	32,306		$	29,858
Income taxes, net	$	23,858		$	1,627		$	(14,103	)

See accompanying Notes to Consolidated Financial Statements.

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THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets

	As of December 31,
(In thousands)	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	22		$	16,231
Accounts receivable:
Customer		57,716			52,898
Unbilled utility revenue		40,520			39,570
Wholesale and other		10,819			5,121
Allowance for uncollectible accounts		(2,334	)		(2,689	)
Note receivable from affiliate		—			14,432
Materials and supplies		15,133			14,248
Taxes receivable		9,397			7,618
Deferred income taxes		1,803			2,948
Prepaid taxes		9,993			8,759
Regulatory assets		695			352
Other		1,217			13,888
Total current assets		144,981			173,376
Property, Plant and Equipment, Net:
Transmission		333,939			323,916
Distribution		1,214,872			1,160,307
Other		71,005			74,998
Accumulated depreciation		(496,838	)		(470,008	)
Subtotal		1,122,978			1,089,213
Construction work in progress		17,655			14,475
Total property, plant and equipment, net		1,140,633			1,103,688
Other Assets:
Assets held for sale (Note 3)		—			10,779
Other		3,880			9,529
Total other assets		3,880			20,308
Deferred Charges:
Regulatory assets		71,130			64,022
Other		5,818			4,186
Total deferred charges		76,948			68,208
Total Assets	$	1,366,442		$	1,365,580

See accompanying Notes to Consolidated Financial Statements.

224

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets—(Continued)

	As of December 31,
(In thousands, except share amounts)	2005		2004
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Long-term debt due within one year (Note 2)	$	99,956	$	—
Note payable to affiliate		2,392		—
Accounts payable		24,808		21,721
Accounts payable to affiliates, net		27,225		48,968
Accrued taxes		10,293		9,687
Accrued interest		5,015		3,652
Other		23,744		31,005
Total current liabilities		193,433		115,033
Long-term Debt (Note 2)		318,618		417,908
Deferred Credits and Other Liabilities:
Investment tax credit		5,629		6,614
Non-current income taxes payable		57,561		57,561
Deferred income taxes		196,409		183,895
Obligations under capital leases		4,695		6,210
Regulatory liabilities		176,723		168,862
Other		9,004		8,397
Total deferred credits and other liabilities		450,021		431,539
Commitments and Contingencies (Note 14)
Stockholder’s Equity:
Common stock, $0.01 par value, 26 million shares authorized and 22,385,000 shares outstanding at December 31, 2005 and 2004		224		224
Other paid-in capital		221,144		221,144
Retained earnings		183,001		179,731
Accumulated other comprehensive income		1		1
Total stockholder’s equity		404,370		401,100
Total Liabilities and Stockholder’s Equity	$	1,366,442	$	1,365,580

See accompanying Notes to Consolidated Financial Statements.

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THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

Consolidated Statements of Capitalization

	As of December 31,
(In thousands)	2005		2004
Stockholder’s Equity (See Consolidated Balance Sheets)	$	404,370	$	401,100

Long-term Debt:
	December 31, 2005 Interest Rate %
First mortgage bonds, maturity:
2022-2025	—	$	—		$	145,000
2014-2015	5.125 - 5.350		320,000			175,000
Medium-term debt due 2006	5.000		100,000			100,000
Unamortized debt discount			(1,426	)		(2,092	)
Total long-term debt (including current maturities of $99,956 and $0)			418,574			417,908
Total Capitalization		$	822,944		$	819,008

See accompanying Notes to Consolidated Financial Statements.

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THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

Consolidated Statements of Stockholder’s Equity

(In thousands, except shares)	Shares outstanding	Common stock		Other paid-in capital		Retained earnings			Accumulated other comprehensive income		Total stockholder’s equity
Balance at January 1, 2003	22,385,000	$	224	$	221,144	$	174,694		$	—	$	396,062
Net income	—		—		—		40,479			—		40,479
Dividends declared on common stock	—		—		—		(30,443	)		—		(30,443	)
Balance at December 31, 2003	22,385,000		224		221,144		184,730			—		406,098
Net income	—		—		—		37,981			—		37,981
Dividends declared on common stock	—		—		—		(42,980	)		—		(42,980	)
Other comprehensive income	—		—		—		—			1		1
Balance at December 31, 2004	22,385,000		224		221,144		179,731			1		401,100
Net income	—		—		—		66,354			—		66,354
Dividends declared on common stock	—		—		—		(63,084	)		—		(63,084	)
Balance at December 31, 2005	22,385,000	$	224	$	221,144	$	183,001		$	1	$	404,370

See accompanying Notes to Consolidated Financial Statements.

227

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note No.		Page No.
1	Basis of Presentation	229
2	Capitalization	234
3	Assets Held for Sale	235
4	Asset Retirement Obligations (“ARO”)	235
5	Income Taxes	236
6	Pension Benefits and Postretirement Benefits Other Than Pensions	238
7	Accounting for the Effects of Price Regulation	239
8	Regulatory Assets and Liabilities	240
9	Fair Value of Financial Instruments	240
10	Other Income and Expenses, Net	241
11	Quarterly Financial Information (Unaudited)	241
12	Letters of Credit	241
13	Variable Interest Entities	241
14	Commitments and Contingencies	242

228

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1:  BASIS OF PRESENTATION

The Potomac Edison Company, together with its consolidated subsidiaries (“Potomac Edison”), is a regulated wholly owned subsidiary of Allegheny Energy, Inc. (“AE,” and together with its consolidated subsidiaries, “Allegheny”). Potomac Edison, along with its regulated utility affiliates, Monongahela Power Company (“Monongahela”) and West Penn Power Company, collectively doing business as Allegheny Power, operates electric transmission and distribution (“T&D”) systems. Potomac Edison operates an electric T&D system in Maryland, Virginia and West Virginia. Potomac Edison currently operates under a single business segment, Delivery and Services.

Potomac Edison is subject to regulation by the Securities and Exchange Commission (“SEC”), the Maryland Public Service Commission (the “Maryland PSC”), the Public Service Commission of West Virginia, the Virginia State Corporation Commission and the Federal Energy Regulatory Commission (“FERC”).

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny. As of December 31, 2005, AESC employed approximately 4,460 employees, of which approximately 1,290 are subject to collective bargaining arrangements.

Certain prior period amounts have been reclassified to conform to the financial statement presentation for the current period.

Significant accounting policies of Potomac Edison and its subsidiaries are summarized below.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires Potomac Edison to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a continuous basis, Potomac Edison evaluates its estimates, including those related to the calculation of unbilled revenues, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Potomac Edison bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Consolidation

The Consolidated Financial Statements reflect investments in controlled subsidiaries on a consolidated basis. The Consolidated Financial Statements include the accounts of Potomac Edison and all subsidiary companies after elimination of intercompany transactions and balances and are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of FERC and applicable state regulatory commissions.

Revenues

Revenues from the sale of electricity to customers are recognized in the period that the electricity is delivered and consumed by customers, including an estimate for unbilled revenues.

229

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Revenues from one industrial customer, were 12.9% in 2005 and 2004 and 10.5% in 2003 of total operating revenues. It is anticipated that this customer will have significantly reduced electric usage in 2006, which curtailed its operations in December 2005.

Deferred Energy Costs, Net

To satisfy its obligations under the provisions of the Public Utility Regulatory Policies Act of 1978 (“PURPA”), Potomac Edison entered into a long-term contract to purchase capacity and energy from the AES Warrior Run facility through the beginning of 2030. Effective July 1, 2000, Potomac Edison was authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run cogeneration facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, by means of a retail revenue surcharge. Any under or over-recovery of net costs related to AES Warrior Run is being deferred on Potomac Edison’s Consolidated Balance Sheets, as deferred energy costs, pending subsequent recovery from, or return to, customers through adjustments to this retail revenue surcharge.

Beginning on January 1, 2005, Maryland commercial and industrial generation rates transitioned to market-based rates. Potomac Edison is authorized by the Maryland PSC to recover the generation component of power sold to customers. An asset or liability is recorded on Potomac Edison’s balance sheet relative to any under-recovery or over-recovery for the generation component of costs charged to Maryland commercial and industrial customers. Deferred energy costs relate to the recovery from or payment to customers related to these generation costs.

See Note 14, “Commitments and Contingencies,” for additional information.

Debt Issuance Costs

Costs incurred to issue debt are recorded as deferred charges on the Consolidated Balance Sheets. These costs are amortized over the term of the related debt instrument using the effective interest method.

Property, Plant and Equipment

Property, plant and equipment are stated at original cost. Cost includes direct labor and materials, allowance for funds used during construction on regulated property for which construction work in progress is not included in rate base, and indirect costs, such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes and other benefits related to employees engaged in construction. Upon normal retirement, the costs of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation with no gain or loss recorded.

Long-Lived Assets

Potomac Edison’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows.

Allowance for Funds Used During Construction (“AFUDC”)

AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is recognized by Potomac Edison as a cost

230

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

of property, plant and equipment. Rates used for computing AFUDC in 2005, 2004 and 2003 averaged 8.7%, 9.28% and 9.04%, respectively. Potomac Edison recorded AFUDC of $1.0 million in 2005 and 2004 and $0.8 million in 2003.

Depreciation and Maintenance

Depreciation expense is determined in accordance with currently enacted regulatory rates. Depreciation expense was approximately 2.8% of average depreciable property in 2005, 2004 and 2003. Estimated service lives for T&D and other property are as follows:

	Years
Transmission and distribution property:
Electric equipment	14-59
Easements	75
Computers, software and information systems	5-10
Other property:
Office buildings and improvements	40-42
General office and other equipment	14-20
Vehicles and transportation	7-25
Computers, software and information systems	5-10

Maintenance expenses represent costs incurred to maintain the electric T&D systems. These expenses reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from periodic storm damage to the T&D system. Maintenance costs are expensed as incurred.

Intangible Assets

Intangible assets with indefinite lives are not amortized, but rather are tested for impairment at least annually. Intangible assets with finite lives are amortized over their useful lives and tested for impairment when events or circumstances warrant. Potomac Edison has intangible assets consisting of amortized land easements, which are included in property, plant and equipment on the Consolidated Balance Sheets, with a gross carrying amount and accumulated amortization as follows: at December 31, 2005, $55.6 million and $15.6 million, respectively, and at December 31, 2004, $55.5 million and $15.1 million, respectively. Amortization expense was $0.8 million in 2005 and 2004 and $0.9 in 2003. Amortization expense is estimated to be $0.8 million annually for 2006 through 2010.

Intercompany Transactions

Potomac Edison has various operating transactions with affiliates. It is Potomac Edison’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented on a net basis on the Consolidated Balance Sheets and the Consolidated Statements of Cash Flows.

Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for Potomac Edison and its affiliates. Potomac Edison is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to Potomac Edison for 2005, 2004 and 2003 were $104.2 million, $100.8 million and $102.2 million, respectively.

231

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Potomac Edison purchases the power necessary to serve a significant portion of its customers who do not choose an alternate electricity generation provider from Allegheny Energy Supply Company, LLC (“AE Supply”), with agreements approved by FERC. The expense for these purchases is reflected in “Purchased power and transmission cost” on the Consolidated Statements of Operations. For 2005, 2004 and 2003, Potomac Edison purchased power from AE Supply of $471.3 million, $528.3 million and $527.6 million, respectively. For 2005, 2004 and 2003, Potomac Edison also paid AE Supply $8.0 million, $10.2 million and $9.9 million, respectively, for ancillary transmission expenses.

AE and its subsidiaries, including Potomac Edison, file a consolidated federal income tax return. The consolidated income tax liability is allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability. In accordance with this consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various registrants at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the intercompany balance. Income taxes payable to affiliates, including both short and long-term obligations, at December 31, 2005 and 2004, were $45.3 million and $47.3 million, respectively.

Potomac Edison manages excess cash and short-term requirements through an internal money pool. The money pool provides funds at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. Potomac Edison can lend money into, or borrow money from, the money pool. At December 31, 2005 Potomac Edison had $2.4 million borrowed from the money pool. At December 31, 2004, Potomac Edison had $14.4 million invested in the money pool.

At December 31, 2005 and 2004, Potomac Edison had net accounts payable to affiliates of $27.2 million and $49.0 million, respectively.

Cash Equivalents

For purposes of the Consolidated Statements of Cash Flows and Consolidated Balance Sheets, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit repurchase agreements and money market funds, are considered to be the equivalent of cash.

Regulatory Assets and Liabilities

Under cost-based regulation, regulated enterprises generally are permitted to recover their operating expenses and earn a reasonable return on their utility investment.

Potomac Edison accounts for its regulated operations under the provisions of SFAS No. 71. “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs or revenues would be recognized by an unregulated enterprise. Accordingly, Potomac Edison records assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” Potomac Edison periodically evaluates the applicability of SFAS No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, Potomac Edison may have to reduce its asset balances to reflect a market basis less than cost and write-off its associated regulatory assets and liabilities.

232

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

See Note 8, “Regulatory Assets and Liabilities,” for additional details.

Inventory

Potomac Edison values materials and supplies inventory using an average cost method.

Income Taxes

AE and its subsidiaries, including Potomac Edison, file a consolidated federal income tax return. The consolidated income tax liability is allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability.

Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. Potomac Edison does not expect that any settlement related to such examination will have a material impact on its consolidated statement of operations, financial position or cash flow.

See Note 5, “Income Taxes,” for additional information.

Pension and Other Postretirement Benefits

AE and its subsidiaries have noncontributory, defined benefit pension plans covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. AE’s funding policy is to contribute annually to the plans at least the minimum amount required under the Employee Retirement Income Security Act of 1974 and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments.

AE’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured. AE does not provide subsidized medical coverage in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees.

Through AESC, Potomac Edison is responsible for its proportionate share of pension and postretirement benefit costs.

Other Comprehensive Income

Other comprehensive income consists of unrealized gains, net of income taxes, from the temporary change in the fair value of available-for-sale securities.

Recent Accounting Pronouncements

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (“SFAS 153”).    In December of 2004, the FASB issued SFAS 153, which was effective for Potomac Edison as of July 1, 2005. SFAS 153 amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions” (“APB 29”), by

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eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. The adoption of SFAS 153 did not have a material impact on Potomac Edison’s consolidated results of operations, cash flows or financial position.

NOTE 2:  CAPITALIZATION

Potomac Edison’s consolidated capital structure, including short-term debt was as follows:

	December 31, 2005			December 31, 2004
(In millions, except percent)	Amount		%	Amount		%
Debt	$	418.5	50.9	$	417.9	51.0
Common equity		404.4	49.1		401.1	49.0
Total	$	822.9	100.0	$	819.0	100.0

Short-term Debt

There was no short-term debt outstanding during the years ended December 31, 2005 and 2004.

Long-term Debt

As of December 31, 2005, contractual maturities of long-term debt, excluding unamortized discounts of $1.4 million, were as follows:

(In millions)	2006		2007		2007		2008		2009		Thereafter		Total
First Mortgage Bonds	$	—	$	—	$	—	$	—	$	—	$	320.0	$	320.0
Medium-Term Notes		100.0		—		—		—		—		—		100.0
Total	$	100.0	$	—	$	—	$	—	$	—	$	320.0	$	420.0

At December 31, 2005, substantially all of Potomac Edison’s properties were held subject to the lien securing its First Mortgage Bonds.

2005 Debt Activity

On August 15, 2005, Potomac Edison issued $145.0 million of 5.125% First Mortgage Bonds due 2015. Approximately $143 million of the proceeds, together with available cash, was used to redeem Potomac Edison’s $65.0 million of outstanding 7.75% First Mortgage Bonds due 2025 and its $80.0 million of outstanding 7.625% First Mortgage Bonds due 2025.

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The following issuances and redemptions of debt were made during 2005:

(In millions)	Issuances		Redemptions
First Mortgage Bonds	$	145.0	$	145.0

2004 Debt Activity

In November 2004, Potomac Edison issued $175.0 million of 5.35% First Mortgage Bonds, which mature on November 15, 2014. The net proceeds of the bond issuance were used to fund the December 2004 redemption of $55.0 million of 8.0% First Mortgage Bonds due 2022, $45.0 million of 7.75% First Mortgage Bonds due 2023 and $75.0 million of 8.0% First Mortgage Bonds due 2024.

The following issuances and redemptions of debt were made during 2004:

(In millions)	Issuances		Redemptions
First Mortgage Bonds	$	175.0	$	175.0

NOTE 3:  ASSETS HELD FOR SALE

At December 31, 2004, Potomac Edison’s Hagerstown, Maryland property was recorded as an asset held for sale within “Other Assets” on the Consolidated Balance Sheet.

During May 2005, Potomac Edison completed the sale of its Hagerstown, Maryland property for $10.6 million in net cash proceeds.

NOTE 4:  ASSET RETIREMENT OBLIGATIONS (“ARO”)

Effective January 1, 2003, Potomac Edison adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS No. 143 requires that the fair value of asset retirement costs for which Potomac Edison has a legal obligation be recorded as liabilities, with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if it is settled at a different amount. Potomac Edison recorded AROs related to underground and aboveground storage tanks.

The effect of adopting SFAS No. 143 on Potomac Edison’s Consolidated Financial Statements in 2003 was not material.

Effective December 31, 2005, Potomac Edison adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations (“Conditional AROs”)” which requires an entity to recognize a liability for the fair value of a Conditional ARO if the fair value of the liability can be reasonably estimated. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement.

Potomac Edison recorded Conditional AROs related to transformers containing polychlorinated biphenyls (“PCBs”). The effect of adopting FIN 47 on Potomac Edison’s Consolidated Financial Statements in 2005 was a $0.3 million increase in non-current regulatory assets, and the recognition of a $0.4 million non-current liability.

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For 2005, Potomac Edison’s total ARO balance, which includes AROs and Conditional AROs, increased $0.3 million, from $0.2 million at December 31, 2004 to $0.5 million at December 31, 2005, primarily due to Potomac Edison recording $0.3 million of certain Conditional ARO liabilities associated with the adoption of FIN 47.

Estimated removal costs of $170.8 million and $162.3 million at December 31, 2005 and December 31, 2004, respectively, are being recovered through the rate-making process. These amounts are reported as regulatory liabilities.

Had the provisions of FIN No. 47 been adopted on January 1, 2003, there would have been no impact on Potomac Edison’s income before cumulative effect of accounting change and net income.

Had the provisions of FIN No. 47 been adopted on January 1, 2003, Potomac Edison’s ARO liability would have been $0.3 million at January 1, 2004 and $0.3 million at December 31, 2004.

NOTE 5:  INCOME TAXES

Details of federal and state income tax expense (benefit) from continuing operations are as follows:

(In millions)	2005			2004			2003
Income tax expense (benefit)—current:
Federal	$	19.0		$	3.6		$	14.5
State		3.1			1.7			3.0
Total		22.1			5.3			17.5
Income tax expense—deferred, net of amortization		12.3			30.5			4.2
Amortization of deferred investment tax credit		(1.0	)		(1.0	)		(1.0	)
Total income tax expense	$	33.4		$	34.8		$	20.7

Taxable income differs from pre-tax accounting income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using enacted tax rates in effect in the years in which the differences are expected to reverse.

During the second quarter of 2005, Allegheny determined that it had not claimed certain income tax deductions in its 2003 income tax returns relating to commodity trading contracts. Allegheny filed a claim for these additional deductions, which increased Potomac Edison’s allocated share of net consolidated tax savings. Accordingly, Potomac Edison recorded a tax benefit of $0.5 million during the second quarter of 2005 to recognize the additional tax savings.

Potomac Edison has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.

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The total provision for income tax expense differs from the amount produced by applying the federal statutory income tax rate of 35% to income before income taxes and cumulative effect of accounting change, as set forth below:

	2005					2004					2003
(In millions)	Amount			%		Amount			%		Amount			%
Income before income taxes and cumulative effect of accounting change	$	99.8				$	72.8				$	61.2
Income tax expense calculated using the federal statutory rate of 35%	$	34.9		35.0		$	25.5		35.0		$	21.4		35.0
Increases (reductions) resulting from:
Tax deductions for which deferred tax was not provided:
Depreciation		3.8		3.8			4.4		6.0			(0.4	)	(0.7	)
Plant removal costs		(0.6	)	(0.6	)		(0.6	)	(0.8	)		(0.9	)	(1.5	)
State income tax, net of federal income tax benefit		3.5		3.5			3.2		4.4			1.8		2.9
Amortization of deferred investment tax credit		(1.0	)	(1.0	)		(1.0	)	(1.4	)		(1.0	)	(1.6	)
Accrual versus return adjustment		—		—			4.3		6.0			—		—
Consolidated return benefit		(9.1	)	(9.1	)		(2.0	)	(2.8	)		(0.6	)	(1.0	)
Other, net		1.9		1.9			1.0		1.4			0.4		0.6
Total income tax expense	$	33.4		33.5		$	34.8		47.8		$	20.7		33.7

At December 31, the deferred tax assets and liabilities consisted of the following:

(In millions)	2005		2004
Deferred tax assets:
Unamortized investment tax credit	$	3.7	$	4.3
Other		12.2		14.7
Total deferred tax assets		15.9		19.0
Deferred tax liabilities:
Book versus tax plant asset basis differences, net		198.3		192.5
Other		12.2		7.5
Total deferred tax liabilities		210.5		200.0
Total net deferred tax liabilities		194.6		181.0
Plus portion above included in current assets		1.8		2.9
Total long-term net deferred tax liabilities	$	196.4	$	183.9

Potomac Edison is a party to a consolidated tax sharing agreement. Potomac Edison expects to realize benefits represented by deferred tax assets through its participation in the consolidated Allegheny tax return in future years.

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NOTE 6:  PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Potomac Edison is responsible for its proportionate share of the net periodic cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. Potomac Edison’s share of the costs, of which approximately 33%, 35% and 21% in 2005, 2004 and 2003, respectively were allocated to “Construction work in progress,” a component of “Property, plant and equipment, net,” was as follows:

(In millions)	2005		2004		2003
Pension	$	5.5	$	4.7	$	4.2
Medical and life insurance	$	5.0	$	4.2	$	5.1

The assumptions used to determine net periodic benefit costs for years ended December 31, 2005, 2004 and 2003 are shown in the table below.

	Pension Benefits						Postretirement Benefits Other Than Pensions
	2005		2004		2003		2005		2004		2003
Discount rate	5.90	%	6.00	%	6.50	%	5.90	%	6.00	%	6.50	%
Expected long-term rate of return on plan assets *	8.50	%	8.50	%	9.00	%	8.50	%	8.50	%	9.00	%
Rate of compensation increase	3.25	%	3.75	%	4.00	%	3.25	%	3.75	%	4.00	%

* Excluding administrative expenses.

The assumptions used to determine benefit obligations at year-end 2005 and 2004 are shown in the table below:

	Pension Benefits				Postretirement Benefits Other Than Pensions
	2005		2004		2005		2004
Discount rate	5.60	%	5.90	%	5.60	%	5.90	%
Rate of compensation increase	3.25	%	3.25	%	3.25	%	3.25	%

In selecting an assumed discount rate, Allegheny uses a modeling process that involves selecting a portfolio of high-quality bonds (AA- or better) whose cash flows (via coupons and maturities) match the timing and amount of Allegheny’s expected future benefit payments. Allegheny considers the results of this modeling process, as well as overall rates of return on high quality corporate bonds and changes in such rates over time, in the determination of its assumed discount rate.

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs for 2006 is 8.25% which is net of administrative expenses.

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Assumed health care cost trend rates at December 31 are as follows:

	2005		2004
Health care cost trend rate assumed for next year	9.5	%	9.5	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2015		2014

For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.5% beginning with 2006 and grading down by 0.5% each year to an ultimate rate of 5.0%, and plan provisions that limit future medical and life insurance benefits. Because of the plan provisions that limit future benefits, changes in the assumed health care cost trend rate would have a limited effect on the amounts displayed in the table above.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) became law. Beginning in 2006, the federal government will provide subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. The subsidy would be 28% of eligible drug costs for retirees that are over age 65 and covered under Allegheny’s postretirement benefits other than pensions plan.

Allegheny elected to follow the deferral provisions of FASB Staff Position (“FSP”) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-1”). FSP 106-1 permits employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until guidance on the accounting for the federal subsidy is issued. On May 19, 2004, the FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”), which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.

Allegheny has determined that the prescription drug benefit offered under its postretirement benefits other than pensions plan is at least actuarially equivalent to Medicare Part D and therefore, expects to receive the federal subsidy offered under the Medicare Act. Allegheny expects to receive subsidies of approximately $2.0 million to $3.0 million annually during the period 2006 through 2010, and expects to receive an aggregate of approximately $3.0 million during the period 2011 through 2015. Also, beginning in 2006, Allegheny’s annual net periodic postretirement benefit cost was reduced by approximately $1.8 million as a result of the expected sharing of the cost of the program by Medicare.

NOTE 7:  ACCOUNTING FOR THE EFFECTS OF PRICE REGULATION

Potomac Edison recorded a transition obligation on its books associated with West Virginia deregulation. Potomac Edison also reapplied the provisions of SFAS No. 71 in the first quarter of 2003 and recognized a gain of approximately $14.1 million as a result of the elimination of its transition obligation. This gain is a component of “Other income and expenses, net” in the Consolidated Statements of Operations.

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NOTE 8:  REGULATORY ASSETS AND LIABILITIES

Potomac Edison’s operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:

(In millions)	2005		2004
Regulatory assets, including current portion:
Income taxes	$	46.8	$	46.1
Unamortized loss on reacquired debt		21.5		16.7
Other		3.5		1.6
Subtotal		71.8		64.4
Regulatory liabilities:
Non-legal asset removal costs		170.8		162.3
Income taxes		5.9		6.6
Subtotal		176.7		168.9
Net regulatory liabilities	$	104.9	$	104.5

Income Taxes, Net

In certain jurisdictions, deferred income tax expense is not permitted as a cost in the determination of rates charged to customers. In these jurisdictions a deferred income tax liability is recorded with an offsetting regulatory asset. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. These deferred income taxes relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. No return is allowed on the regulatory asset for income taxes.

See Note 7, “Accounting for the Effects of Price Regulation,” for a discussion regarding Potomac Edison’s reapplication of the provisions of SFAS No. 71 to their West Virginia generation assets in the first quarter of 2003.

See Note 4, “Asset Retirement Obligations,” for a discussion of a regulatory liability for a cost of removal.

NOTE 9:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year, at December 31, were as follows:

	2005				2004
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	418.6	$	417.4	$	417.9	$	429.2

The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The carrying amounts of cash equivalents and short-term debt approximate the fair values of such financial instruments because of the short maturities of those instruments.

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NOTE 10:  OTHER INCOME AND EXPENSES, NET

Other income and expenses, net represent non-operating income and expenses before income taxes. The following table summarizes Potomac Edison’s other income and expenses, net:

(In millions)	2005		2004			2003
Coal brokering income, net	$	2.2	$	2.1		$	1.8
Premium services		1.8		1.8			1.4
Interest income		1.3		1.0			0.3
Reapplication of SFAS No. 71		—		—			14.1
Gain on sale of land		—		0.3			1.9
Charge to write down Hagerstown, MD property to fair value		—		(0.9	)		—
Storm restoration, net		—		0.7			—
Other		1.9		1.7			1.6
Total other income and expenses, net	$	7.2	$	6.7		$	21.1

NOTE 11:  QUARTERLY FINANCIAL INFORMATION (Unaudited)

	2005 Quarters Ended (1)								2004 Quarters Ended (1)
(In millions)	December 31		September 30		June 30		March 31		December 31		September 30		June 30		March 31
Operating revenues	$	246.1	$	246.5	$	221.1	$	257.6	$	236.1	$	224.4	$	216.7	$	247.2
Operating income	$	30.4	$	31.6	$	25.0	$	33.1	$	27.5	$	20.0	$	22.4	$	28.5
Net income	$	14.9	$	16.4	$	15.0	$	20.1	$	7.5	$	5.7	$	11.0	$	13.8

(1) Amounts may not total to year to date results due to rounding.

NOTE 12:  LETTERS OF CREDIT

Potomac Edison did not have any letters of credit outstanding at December 31, 2005. Potomac Edison had two letters of credit outstanding at December 31, 2004 for an aggregate amount of approximately $9.7 million. Of this amount, $9.5 million was issued under the New Loan Facilities to support an energy conservation contract. This letter of credit expired in July 2005. The remaining $0.2 million represented a letter of credit issued by a bank that is not a lender under the New AE Facility to support a property purchase. This letter of credit expired in the first quarter of 2005.

NOTE 13:  VARIABLE INTEREST ENTITIES

Potomac Edison has a long-term electricity purchase contract with an unrelated independent power producer (“IPP”) that represents a variable interest under FASB’s Interpretation No. 46 (Revised December 2003) “Consolidation of Variable Interest Entities” (“FIN 46R”). Potomac Edison has been unable to obtain certain information from the IPP necessary to determine if the variable interest entity (“VIE”) should be consolidated under FIN 46R.

Potomac Edison had power purchases from the IPP in the amount of $105.3 million and $93.6 million for 2005 and 2004, respectively. Potomac Edison recovers the full amount of the cost of the applicable power contract in its rates charged to consumers. Potomac Edison is not subject to any risk of loss associated with the VIE, because it does not have any obligation to the IPP other than to purchase the power that the IPP produces according to the terms of the applicable electricity purchase contract.

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NOTE 14:  COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Allegheny is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.

Claims Related to Alleged Asbestos Exposure:  The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties in these actions are seeking an allocation of responsibility for historic and potential future asbestos liability. Allegheny and numerous others are plaintiffs in a similar action filed against Zurich Insurance Company in California, Fuller-Austin Asbestos Settlement Trust, et al. v. Zurich-American Insurance Co., et al., Case No. CGC 04 431719 (Superior Court of California, County of San Francisco).

In connection with a settlement, Allegheny received payment from one of its insurance companies in the amount of $625,000 on July 5, 2005, with the next payment of $625,000 due July 1, 2006. As part of the settlement, Allegheny released this insurance company from potential liabilities associated with claims against Allegheny alleging asbestos exposure.

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2005, Allegheny had 930 open cases remaining in West Virginia and five open cases remaining in Pennsylvania.

Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”) Claim: On March 4, 1994, Monongahela and certain affiliated companies received notice that the EPA had identified them as potentially responsible parties (“PRPs”) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site in Pennsylvania. Initially, approximately 175 PRPs were involved; however, the current number of active PRPs has been reduced as a result of settlements with de minimis contributors and other contributors to the site. The costs of remediation will be shared by all past and active responsible parties. In 1999, a PRP group that included Monongahela and certain affiliated companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30.0 million. Allegheny has an accrued liability representing its estimated share of the remediation costs as of December 31, 2005.

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Ordinary Course of Business:  Potomac Edison is, from time to time, involved in litigation and other legal disputes in the ordinary course of business. Potomac Edison is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.

Construction and Capital Program

Potomac Edison’s expenditures for capital programs are estimated to be approximately $81.0 million for 2006 and $98.0 million for 2007.

Leases

Potomac Edison has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles and computer equipment.

Total capital and operating lease rent payments of $4.5 million for 2005, $4.7 million in 2004 and $5.5 million in 2003 were recorded as rent expense. Potomac Edison’s estimated future minimum lease payments for operating leases, including leases entered into by AESC which are allocated to Potomac Edison, with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are as follows:

(In millions)	2006		2007		2008		2009		2010		Thereafter		Total		Amounts representing interest and fees		Present value of net minimum capital lease payments
Capital Leases	$	2.3	$	1.9	$	1.6	$	1.1	$	0.8	$	0.5	$	8.2	$	1.7	$	6.5
Allocated Capital Leases		0.2		0.1		0.1		0.1		0.2		—		0.7		0.1		0.6
Total Capital Leases	$	2.5	$	2.0	$	1.7	$	1.2	$	1.0	$	0.5	$	8.9	$	1.8	$	7.1
Operating Leases	$	0.3	$	0.1	$	—	$	—	$	—	$	—	$	0.4	$	—	$	—

The carrying amount of equipment recorded under capitalized lease agreements included in “Property, plant and equipment, net” was $6.5 million and $8.6 million at December 31, 2005 and 2004, respectively.

PURPA

PURPA has required electric utility companies, such as Potomac Edison, to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. State public service commissions or legislatures establish the rates paid for electric energy purchased from qualifying facilities.

The Energy Policy Act has amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contract obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission. This amendment does not change Potomac Edison’s existing PURPA contract.

Potomac Edison is committed to purchase the electrical output from 180 megawatts of qualifying PURPA capacity from the AES Warrior Run cogeneration facility. Payments for PURPA capacity and energy in 2005,

243

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2004 and 2003 totaled $105.3 million, $93.6 million and $95.2 million, respectively. The average cost to Potomac Edison of these power purchases was approximately 6.8, 6.7 and 6.6 cents per kWh for 2005, 2004 and 2003, respectively. Potomac Edison is currently authorized to recover these costs in its retail rates as described below.

As a result of the 1999 Maryland restructuring settlement, AES Warrior Run capacity and energy must be offered into the wholesale market over the life of the applicable PURPA contract. In November 2001, the Maryland PSC approved a power sales agreement between Potomac Edison and AE Supply, the winning bidder, covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2002 through December 31, 2004. The Warrior Run agreement between Potomac Edison and AE Supply expired on December 31, 2004 and Potomac Edison awarded a new contract to a non-affiliated company. The cost of purchases from AES Warrior Run under the PURPA contract not recovered through the market sale of the output are recovered, dollar-for-dollar, from Maryland customers through a retail revenue surcharge.

The table below reflects Potomac Edison’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2005. Actual values can vary substantially depending upon future conditions.

(In millions)	kWhs	Amount
2006	1,450.7	$	99.4
2007	1,450.7	$	100.7
2008	1,454.6	$	102.4
2009	1,450.7	$	103.5
2010	1,450.7	$	105.1
Thereafter	27,703.2	$	2,126.9

244

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of The Potomac Edison Company:

In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of operations, stockholder’s equity and cash flows present fairly, in all material respects, the financial position of The Potomac Edison Company and its subsidiaries (the “Company”) 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. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule 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.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 28, 2006

245

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ALLEGHENY GENERATING COMPANY

Statements of Operations

	Year Ended December 31,
(In thousands)	2005		2004		2003
Operating revenues	$	66,602	$	69,200	$	70,532
Operating expenses:
Operations and maintenance		4,642		6,181		5,163
Depreciation		17,180		17,056		17,038
Taxes other than income taxes		2,928		2,886		3,232
Total operating expenses		24,750		26,123		25,433
Operating income		41,852		43,077		45,099
Other income, net		226		94		164
Interest expense		7,395		8,455		12,447
Income before income taxes		34,683		34,716		32,816
Income tax expense		3,562		7,324		11,989
Net income	$	31,121	$	27,392	$	20,827

See accompanying Notes to Financial Statements.

246

ALLEGHENY GENERATING COMPANY

Statements of Cash Flows

	Year Ended December 31,
(In thousands)	2005			2004			2003
Cash Flows From Operating Activities:
Net income	$	31,121		$	27,392		$	20,827
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		17,180			17,056			17,038
Deferred income taxes and investment tax credit, net		(4,960	)		(5,937	)		(5,767	)
Other, net		286			1,202			700
Changes in certain assets and liabilities:
Accounts receivable due from/payable to affiliates, net		4,195			1,472			10,836
Materials and supplies		(120	)		(53	)		(65	)
Taxes receivable/accrued, net		(6,081	)		668			14,338
Other current assets		35			9			93
Accounts payable		2,662			26			—
Accrued interest		—			—			(946	)
Other assets		(129	)		1			(1	)
Other liabilities		—			1			(656	)
Net cash provided by operating activities		44,189			41,837			56,397
Cash Flows From Investing Activities:
Capital expenditures		(13,031	)		(9,109	)		(8,729	)
Cash Flows From Financing Activities:
Note payable to parent		(15,000	)		(15,000	)		30,000
Net repayments of short-term debt		—			—			(55,000	)
Retirement of long-term debt		—			—			(50,000	)
Parent company contribution		—			—			40,000
Cash dividends paid on common stock		(21,800	)		(12,500	)		(12,500	)
Net cash used in financing activities		(36,800	)		(27,500	)		(47,500	)
Net increase (decrease) in cash and cash equivalents		(5,642	)		5,228			168
Cash and cash equivalents at beginning of period		7,500			2,272			2,104
Cash and cash equivalents at end of period	$	1,858		$	7,500		$	2,272
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest	$	7,109		$	8,169		$	12,694
Income taxes, net	$	14,603		$	12,592		$	4,074

See accompanying Notes to Financial Statements.

247

ALLEGHENY GENERATING COMPANY

Balance Sheets

	As of December 31,
(In thousands)	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	1,858		$	7,500
Materials and supplies		1,551			1,431
Taxes receivable		3,004			—
Other		225			260
Total current assets		6,638			9,191
Property, Plant and Equipment, Net:
Generation		788,952			782,666
Transmission		47,098			43,642
Other		2,960			3,219
Accumulated depreciation		(316,250	)		(303,745	)
Subtotal		522,760			525,782
Construction work in progress		12,372			13,370
Total property, plant and equipment, net		535,132			539,152
Deferred Charges:
Regulatory assets		8,295			8,752
Other		97			102
Total deferred charges		8,392			8,854
Total Assets	$	550,162		$	557,197

See accompanying Notes to Financial Statements.

248

ALLEGHENY GENERATING COMPANY

Consolidated Balance Sheets—(Continued)

	As of December 31,
(In thousands, except share amounts)	2005		2004
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	2,687	$	26
Accounts payable to affiliates, net		4,696		501
Accrued taxes		—		3,077
Accrued interest		2,292		2,292
Total current liabilities		9,675		5,896
Long-term Debt:
Long-term debt (Note 2)		99,425		99,393
Long-term note payable to parent		—		15,000
Total long-term debt		99,425		114,393
Deferred Credits and Other Liabilities:
Investment tax credit		37,273		38,593
Non-current income taxes payable		17,544		17,544
Deferred income taxes		153,630		155,712
Regulatory liabilities		22,806		24,571
Total deferred credits and other liabilities		231,253		236,420
Commitments and Contingencies (Note 10)
Stockholders’ Equity:
Common stock, $1.00 par value, 5,000 shares authorized and 1,000 shares outstanding at December 31, 2005 and 2004		1		1
Other paid-in capital		172,669		172,669
Retained earnings		37,139		27,818
Total stockholders’ equity		209,809		200,488
Total Liabilities and Stockholders’ Equity	$	550,162	$	557,197

See accompanying Notes to Financial Statements.

249

ALLEGHENY GENERATING COMPANY

Statements of Stockholders’ Equity

(In thousands, except shares)	Shares outstanding	Common stock		Other paid-in capital		Retained earnings			Total stockholders’ equity
Balance at January 1, 2003	1,000	$	1	$	132,669	$	4,599		$	137,269
Net income	—		—		—		20,827			20,827
Parent company contribution	—		—		40,000		—			40,000
Dividends declared on common stock	—		—		—		(12,500	)		(12,500	)
Balance at December 31, 2003	1,000		1		172,669		12,926			185,596
Net income	—		—		—		27,392			27,392
Dividends declared on common stock	—		—		—		(12,500	)		(12,500	)
Balance at December 31, 2004	1,000		1		172,669		27,818			200,488
Net income	—		—		—		31,121			31,121
Dividends declared on common stock	—		—		—		(21,800	)		(21,800	)
Balance at December 31, 2005	1,000	$	1	$	172,669	$	37,139		$	209,809

See accompanying Notes to Financial Statements.

250

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS

Note No.		Page No.
1	Basis of Presentation	252
2	Capitalization	256
3	Asset Retirement Obligations (ARO)	256
4	Income Taxes	257
5	Pension Benefits and Postretirement Benefits Other Than Pensions	258
6	Regulatory Assets and Liabilities	260
7	Fair Value of Financial Instruments	260
8	Jointly Owned Electric Utility Plants	260
9	Quarterly Financial Information (Unaudited)	261
10	Commitments and Contingencies	261

251

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS

NOTE 1:  BASIS OF PRESENTATION

Allegheny Energy Supply Company, LLC (“AE Supply”) and Monongahela Power Company (“Monongahela” and together with AE Supply, the “Parents”), own 100% of Allegheny Generating Company (“AGC”). AE Supply owns 77.03% and Monongahela owns 22.97% of AGC. AGC owns an undivided 40% interest (1,010 megawatts (“MWs”)) in the 2,525 MWs pumped storage, hydroelectric station in Bath County, Virginia, operated by the 60% owner, Virginia Electric and Power Company, a nonaffiliated utility. AGC sells its generation capacity to its Parents. AGC operates under a single business segment, Generation and Marketing.

AGC is subject to regulation by the Securities and Exchange Commission (“SEC”), the Virginia State Corporation Commission and the Federal Energy Regulatory Commission (“FERC”).

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny. As of December 31, 2005, AESC employed approximately 4,460 employees, of which approximately 1,290 are subject to collective bargaining arrangements.

Significant accounting policies of AGC are summarized below.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires AGC to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a continuous basis, AGC evaluates its estimates, including those related to the calculation of the provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. AGC bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Revenues

Revenues are determined under a “cost-of-service” formula wholesale rate schedule approved by FERC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment. All capacity sales of AGC are made to AE Supply and Monongahela.

Debt Issuance Costs

Costs incurred to issue debt are recorded as deferred charges on the Balance Sheets. These costs are amortized over the term of the related debt instrument using the effective interest method.

Property, Plant and Equipment

Property, plant and equipment are stated at original cost and consist of a 40% undivided interest in the Bath County pumped-storage hydroelectric station and its connecting transmission facilities. Upon retirement, the costs of depreciable property, plus removal costs less salvage, are charged to accumulated depreciation.

252

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

Long-Lived Assets

AGC’s long-lived assets owned by AGC are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows.

Depreciation and Maintenance

Depreciation expense is determined in accordance with currently enacted regulatory rates. Depreciation expense amounted to approximately 2.1% of average depreciable property in 2005, 2004 and 2003. Estimated service lives for Generation, Transmission and other property are as follows:

	Years
Generation property:
Hydroelectric dams and facilities	50
Transmission property:
Electric equipment	35
Other property:
Computers, software and information systems	20
General office and other equipment	20

Maintenance expenses represent costs incurred to maintain the power station and general plant. These expenses reflect routine maintenance of equipment, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power station. Maintenance costs are expensed as incurred.

Intangible Assets

AGC has intangible assets consisting of amortized land easements, which are included in property, plant and equipment on the Balance Sheets, with a gross carrying amount of $1.7 million and $1.6 million at December 31, 2005 and 2004, respectively and accumulated depreciation of $0.9 million at December 31, 2005 and 2004.

Intercompany Transactions

AGC has various operating transactions with its affiliates. AGC’s policy is that the affiliated receivable and payable balances outstanding from these transactions are presented on a net basis on the Balance Sheets and the Statements of Cash Flows.

Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for AGC and its affiliates. AGC is responsible for its proportionate share of services provided by AESC. Total billings by AESC (including capital) to AGC for 2005, 2004 and 2003 were not material.

Pursuant to an agreement, AE Supply and Monongahela purchase all of AGC’s capacity in the Bath County, Virginia pumped-storage hydroelectric station priced under a “cost-of-service formula” wholesale rate schedule approved by FERC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment. AE Supply and Monongahela purchase power from AGC on a proportional basis, based on their respective equity ownership of AGC.

253

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

AE and its subsidiaries, including AGC, file a consolidated federal income tax return. The consolidated income tax liability is allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability. In accordance with this consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various companies at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the intercompany balance. Income taxes payable to affiliate, including both short and long-term obligations, at December 31, 2005 and 2004, were $19.3 million and $20.3 million, respectively.

Allegheny manages excess cash and short-term requirements through an internal money pool. The money pool provides funds at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. AGC can only borrow money from the money pool. At December 31, 2005 and 2004, AGC did not have any outstanding borrowings from the money pool.

At December 31, 2005 and 2004, AGC had notes payable to AE Supply of $0 million and $15 million, respectively. See Note 2, “Capitalization,” for information regarding AGC’s affiliated debt.

At December 31, 2005 and 2004, AGC had net accounts payable to affiliates of $4.7 million and $0.5 million, respectively.

Cash Equivalents

For purposes of the Statements of Cash Flows and Balance Sheets, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, repurchase agreements and money market funds, are considered to be the equivalent of cash.

Regulatory Assets and Liabilities

Under cost-based regulation, regulated enterprises generally are permitted to recover their operating expenses and earn a reasonable return on their utility investment.

AGC accounts for its regulated operations under the provisions of SFAS No. 71. The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs or revenues would be recognized by an unregulated enterprise. Accordingly, AGC records assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” AGC periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, AGC may have to reduce its asset balances to reflect a market basis less than cost and write-off its associated regulatory assets and liabilities.

See Note 6, “Regulatory Assets and Liabilities,” for additional details.

Inventory

AGC values materials and supplies inventory using an average cost method.

254

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

Income Taxes

AE and its subsidiaries, including AGC, file a consolidated federal income tax return. The consolidated income tax liability is allocated among AE and its subsidiaries, generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability.

Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. AGC does not expect that any settlement related to such examination will have a material impact on its consolidated statement of operations, financial position or cash flow.

See Note 4, “Income Taxes,” for additional information.

Pension and Other Postretirement Benefits

AE and its subsidiaries have noncontributory, defined benefit pension plans covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. The funding policy is to contribute annually to these plans at least the minimum amount required under the Employee Retirement Income Security Act of 1974 and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments.

AE’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits are self-insured. AE does not provide subsidized medical coverage in retirement to employees hired on, or after, January 1, 1993, with the exception of certain union employees.

Through AESC, AGC is responsible for its proportionate share of pension and postretirement benefit costs.

Recent Accounting Pronouncements

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (“SFAS 153”).    In December of 2004, the FASB issued SFAS 153, which was effective for AGC as of July 1, 2005. SFAS 153 amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions” (“APB 29”), by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. The adoption of SFAS 153 did not have a material impact on AGC’s results of operations, cash flows or financial position.

255

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

NOTE 2:  CAPITALIZATION

AGC’s capital structure, including short-term debt, as of December 31, 2005 and 2004, was as follows:

	2005			2004
(In millions, except percent)	Amount		%	Amount		%
Debt	$	99.4	32.1	$	114.4	36.3
Common equity		209.8	67.9		200.5	63.7
Total	$	309.2	100.0	$	314.9	100.0

Short-term Debt

AGC did not have any short-term debt during 2005 and 2004.

Long-term Debt

As of December 31, 2005, contractual maturities of long-term debt for the remainder of 2005 and for full years thereafter, excluding unamortized debt discounts of $0.6 million, are as follows:

(In millions)	2006		2007		2008		2009		2010		Thereafter		Total
Debentures	$	—	$	—	$	—	$	—	$	—	$	100.0	$	100.0

2005 Debt Activity

AGC repaid $15.0 million of its note payable to AE Supply during 2005.

2004 Debt Activity

AGC repaid $15.0 million of its note payable to AE Supply during 2004.

NOTE 3:  ASSET RETIREMENT OBLIGATIONS (“ARO”)

Effective January 1, 2003, AGC adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS No. 143 requires that the fair value of asset retirement costs for which AGC has a legal obligation be recorded as liabilities, with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if it is settled at a different amount.

The effect of adopting SFAS No. 143 on AGC’s Financial Statements in 2003 was not material.

Effective December 31, 2005, AGC adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations” which clarifies accounting and disclosure requirements for retirement obligations associated with long-lived assets. This Interpretation clarifies that the term conditional asset retirement obligation as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the

256

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.

The effect of adopting FIN 47 on AGC’s Financial Statements in 2005 was not material.

NOTE 4:  INCOME TAXES

Details of federal and state income tax expense (benefit) are:

(In millions)	2005			2004			2003
Income tax expense-current:
Federal	$	12.5		$	11.6		$	15.3
State		(4.0	)		1.7			2.5
Total		8.5			13.3			17.8
Income tax benefit deferred, net of amortization		(3.6	)		(4.7	)		(4.5	)
Amortization of deferred investment tax credit		(1.3	)		(1.3	)		(1.3	)
Total income tax expense	$	3.6		$	7.3		$	12.0

Taxable income differs from pre tax accounting income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using enacted tax rates in effect in the years in which the differences are expected to reverse.

AGC has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.

The total provision for income tax expense differs from the amount produced by applying the federal statutory income tax rate of 35% to financial accounting, as set forth below:

(In millions, except %)	2005					2004					2003
	Amount			%		Amount			%		Amount			%
Income before income taxes	$	34.7				$	34.7				$	32.8
Income tax expense calculated using the federal statutory rate of 35%	$	12.2		35.0		$	12.2		35.0		$	11.5		35.0
Increases (reductions) resulting from:
Consolidated return benefit		(5.8	)	(16.7	)		(3.2	)	(9.1	)		(0.9	)	(2.8	)
Amortization of deferred investment tax credit		(1.3	)	(3.7	)		(1.3	)	(3.8	)		(1.3	)	(4.0	)
State income tax, net of federal income tax		(1.6	)	(4.6	)		0.7		2.1			1.4		4.3
Depreciation for which deferred tax was not provided		—		—			—		—			1.3		4.0
Other, net		0.1		0.3			(1.1	)	(3.2	)		—		—
Total income tax expense	$	3.6		10.3		$	7.3		21.0		$	12.0		36.5

257

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

At December 31, the deferred income tax assets and liabilities consisted of the following:

(In millions)	2005		2004
Deferred tax assets:
Unamortized investment tax credit	$	22.8	$	24.6
Other deferred tax assets		0.3		0.2
Total deferred tax assets		23.1		24.8
Deferred tax liabilities:
Plant asset basis differences, net		175.1		178.7
Other deferred tax liabilities		1.6		1.8
Total deferred tax liabilities		176.7		180.5
Total net deferred tax liabilities	$	153.6	$	155.7

AGC is a party to a consolidated tax sharing agreement that allocates a portion of the consolidated tax liability or benefit on the basis of AGC’s relative contribution to such liability or benefit. To the extent AGC has a net operating loss, such loss may only be used to offset its past or future income tax liability determined on a separate company basis to the extent of AGC’s accumulated earnings and profits.

NOTE 5:  PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

AGC is responsible for its proportionate share of the net periodic cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. AGC’s share of these costs was not material for the years ended December 31, 2005, 2004 and 2003, respectively.

The assumptions used to determine net periodic benefit costs for years ended December 31, 2005, 2004 and 2003 are shown in the table below.

	Pension Benefits						Postretirement Benefits Other Than Pensions
	2005		2004		2003		2005		2004		2003
Discount rate	5.90	%	6.00	%	6.50	%	5.90	%	6.00	%	6.50	%
Expected long-term rate of return on plan assets *	8.50	%	8.50	%	9.00	%	8.50	%	8.50	%	9.00	%
Rate of compensation increase	3.25	%	3.75	%	4.00	%	3.25	%	3.75	%	4.00	%

* Excluding administrative expenses.

The assumptions used to determine benefit obligations at year-end 2005 and 2004 and are shown in the table below:

	Pension Benefits				Postretirement Benefits Other Than Pensions
	2005		2004		2005		2004
Discount rate	5.60	%	5.90	%	5.60	%	5.90	%
Rate of compensation increase	3.25	%	3.25	%	3.25	%	3.25	%

258

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

In selecting an assumed discount rate, Allegheny uses a modeling process that involves selecting a portfolio of high-quality bonds (AA- or better) whose cash flows (via coupons and maturities) match the timing and amount of Allegheny’s expected future benefit payments. Allegheny considers the results of this modeling process, as well as overall rates of return on high quality corporate bonds and changes in such rates over time, in the determination of its assumed discount rate.

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs for 2006 is 8.25%, which is net of administrative expenses.

Assumed health care cost trend rates at December 31 are as follows:

	2005		2004
Health care cost trend rate assumed for next year	9.5	%	9.5	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2015		2014

For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.5% beginning with 2006 and grading down by 0.5% each year to an ultimate rate of 5.0%, and plan provisions that limit future medical and life insurance benefits. Because of the plan provisions that limit future benefits, changes in the assumed health care cost trend rate would have a limited effect on the amounts allocated to AGC.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) became law. Beginning in 2006, the federal government will provide subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. The subsidy would be 28% of eligible drug costs for retirees that are over age 65 and covered under Allegheny’s postretirement benefits other than pensions plan.

Allegheny elected to follow the deferral provisions of FASB Staff Position (“FSP”) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-1”). FSP 106-1 permits employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until guidance on the accounting for the federal subsidy is issued. On May 19, 2004, FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”), which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.

Allegheny has determined that the prescription drug benefit offered under its postretirement benefits other than pensions plan is at least actuarially equivalent to Medicare Part D and therefore, expects to receive the federal subsidy offered under the Medicare Act. Allegheny expects to receive subsidies of approximately $2.0 million to $3.0 million annually during the period 2006 through 2010, and expects to receive an aggregate of approximately $3.0 million during the period 2011 through 2015. Also, beginning in 2006, Allegheny’s annual net periodic postretirement benefit cost was reduced by approximately $1.8 million as a result of the expected sharing of the cost of the program by Medicare.

259

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

NOTE 6:  REGULATORY ASSETS AND LIABILITIES

AGC’s operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities, reflected in the Balance Sheets at December 31 relate to:

(In millions)	2005		2004
Regulatory assets:
Income taxes	$	3.9	$	4.1
Unamortized loss on reacquired debt		4.4		4.7
Subtotal		8.3		8.8
Regulatory liabilities:
Income taxes		22.8		24.6
Net regulatory liabilities	$	14.5	$	15.8

NOTE 7:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of long-term debt, at December 31, were as follows:

	As of December 31,
	2005				2004
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	99.4	$	101.6	$	99.4	$	96.2

The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The carrying amounts of cash equivalents and short-term debt approximate the fair values of such financial instruments because of the short maturities of those instruments.

NOTE 8:  JOINTLY OWNED ELECTRIC UTILITY PLANTS

AGC jointly owns an electric generation facility with a third party. AGC records its proportionate share of operating costs, assets and liabilities related to this generation facility in the corresponding lines in the Financial Statements. As of December 31, 2005 and 2004, AGC’s investment and accumulated depreciation in the Bath County generation facility jointly owned with a third party, were as follows:

(Dollars in millions)	2005			2004
Utility plant investment	$	839.0		$	829.5
Accumulated depreciation	$	316.3		$	303.7
Ownership %		40	%		40	%

260

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

NOTE 9:  QUARTERLY FINANCIAL INFORMATION (Unaudited)

	2005 Quarters Ended (1)								2004 Quarters Ended (1)
(In millions)	December 31		September 30		June 30		March 31		December 31		September 30		June 30		March 31
Operating revenues	$	15.7	$	17.4	$	16.7	$	16.9	$	17.2	$	17.0	$	17.8	$	17.2
Operating income	$	9.4	$	11.1	$	10.6	$	10.7	$	11.0	$	10.6	$	10.7	$	10.8
Net income	$	8.6	$	7.4	$	7.8	$	7.4	$	7.9	$	6.7	$	5.8	$	7.0

(1) Amounts may not total to year to date results due to rounding.

NOTE 10:  COMMITMENTS AND CONTINGENCIES

Ordinary Course of Business

AGC is, from time to time, involved in litigation and other legal disputes in the ordinary course of business. AGC is of the belief that there are no other legal proceedings that could have a material effect on its business or financial condition.

Construction and Capital Program

AGC’s expenditures for capital programs are estimated to be approximately $10.0 million for 2006 and $6.0 million for 2007.

261

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

of Allegheny Generating Company:

In our opinion, the accompanying balance sheets and the related statements of operations, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of Allegheny Generating Company (the “Company”) at December 31, 2005 and 2004, and the results of its operations and its 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.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 28, 2006

262

S-1

SCHEDULE I

AE (Parent Company)

Condensed Financial Statements

Statements of Operations:
	Year ended December 31,
(In thousands)	2005			2004			2003
Operating revenues	$	—		$	—		$	—
Operating expenses		5,241			(572	)		13,952
Operating income (loss)		(5,241	)		572			(13,952	)
Other income and expenses, net		201,124			(237,437	)		(287,360	)
Interest expense		132,148			72,641			57,260
Income (loss) before income taxes		63,735			(309,506	)		(358,572	)
Income tax expense (benefit)		670			1,092			(3,593	)
Net income (loss)	$	63,065		$	(310,598	)	$	(354,979	)
Statements of Cash Flows:
	Year ended December 31,
(In thousands)	2005			2004			2003
Net cash provided by operating activities	$	155,442		$	408,658		$	83,578
Cash flows from investing activities:
Proceeds from sale of asset		—			7,140			—
Contributions to subsidiaries		—			(467,999	)		(210,774	)
Return of capital from subsidiaries		88,000			—			—
Net cash provided by (used in) investing activities		88,000			(460,859	)		(210,774	)
Cash flows from financing activities:
Notes receivable from subsidiaries		887			(18,217	)		(343	)
Net repayments of short-term debt		—			—			(335,000	)
Issuance of long-term debt, net of $9.1 million, $6.8 million and $17.6 million in debt issuance costs, respectively		459,861			218,243			588,439
Retirement of long-term debt		(670,000	)		(381,980	)		(58,020	)
Proceeds from issuance of common stock		—			151,360			—
Exercise of stock options		2,941			227			—
Net cash provided by (used in) financing activities		(206,311	)		(30,367	)		195,076
Net increase (decrease) in cash and cash equivalents		37,131			(82,568	)		67,880
Cash and cash equivalents at beginning of period		18,948			101,516			33,636
Cash and cash equivalents at end of period	$	56,079		$	18,948		$	101,516
Cash dividends received from consolidated subsidiaries	$	244,491		$	475,607		$	118,131
Balance Sheets:
				As of December 31,
(In thousands)				2005			2004
ASSETS
Current assets				$	93,038		$	43,047
Investments and other assets					1,982,152			2,115,007
Deferred charges					63,253			38,630
Total assets				$	2,138,443		$	2,196,684
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities				$	102,201		$	339,762
Long-term debt					197,500			100,000
Convertible notes held by Capital Trust					—			293,650
Deferred credits and other liabilities					725			715
Stockholders’ equity					1,838,017			1,462,557
Total liabilities and stockholders’ equity				$	2,138,443		$	2,196,684

See accompanying Notes to Condensed Financial Statements.

263

AE (Parent Company)

NOTES TO CONDENSED FINANCIAL STATEMENTS

NOTE 1:  BASIS OF PRESENTATION

The condensed financial statements represent the financial information required by Securities and Exchange Commission Regulation S-X 210.12-04 for AE, a diversified utility holding company and the parent company of Allegheny Energy, Inc. These financial statements do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States, therefore these financial statements should be read in conjunction with Allegheny’s Consolidated Financial Statements and related notes included herein.

AE has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements.

NOTE 2:  CAPITALIZATION, COMMITMENTS AND CONTINGENCIES

See Note 2, “Capitalization,” and Note 23, “Commitments and Contingencies,” to Allegheny’s Consolidated Financial Statements for a description of AE’s capitalization, commitments and contingencies as of December 31, 2005.

At December 31, 2005, contractual maturities for AE’s long-term debt, for the next five years are as follows:

(In millions)	2006	2007	2008	2009	2010	Total
New AE Credit Facility	1.5	3.0	3.0	3.0	188.5	199.0

264

S-2

SCHEDULE II

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

For Years Ended December 31, 2005, 2004 and 2003

			Additions
Description	Balance at Beginning Of Period		Charged to Costs and Expenses (a)		Charged to Other Accounts (b)		Deductions (c)		Balance at End of Period (d)
Allowance for uncollectible accounts:
Year Ended 12/31/05	$	19,854,168	$	14,386,601	$	5,018,081	$	22,480,610	$	16,778,240
Year Ended 12/31/04	$	29,329,476	$	18,930,902	$	4,299,139	$	32,705,349	$	19,854,168
Year Ended 12/31/03	$	29,644,868	$	26,489,179	$	3,353,373	$	30,157,944	$	29,329,476

(a) Amount accrued to bad debt expense during the year.

(b) Payment recoveries of bad debt accounts previously written off.

(c) Uncollectible accounts written off to bad debt expense during the year. In 2004, the amount includes $1,722,744 for uncollectible accounts related to the gas business that have been reclassified to assets held for sale.

(d) Balance for December 31, 2004 excludes the allowance for uncollectible accounts for the gas business of $3,525,033. Prior year balances include allowance for uncollectible accounts for the gas business of $1,626,346 for December 31, 2003.

265

S-3

SCHEDULE II

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Valuation and Qualifying Accounts

For Years Ended December 31, 2005, 2004 and 2003

			Additions
Description	Balance at Beginning Of Period		Charged to Costs and Expenses (a)		Charged to Other Accounts (b)		Deductions (c)		Balance at End of Period (d)
Allowance for uncollectible accounts:
Year Ended 12/31/05	$	2,616,205	$	2,687,770	$	1,292,125	$	4,107,300	$	2,488,800
Year Ended 12/31/04	$	4,955,196	$	3,165,129	$	1,048,752	$	6,552,872	$	2,616,205
Year Ended 12/31/03	$	4,878,396	$	12,180,111	$	2,165,568	$	14,268,879	$	4,955,196

(a) Amount accrued to bad debt expense during the year.

(b) Payment recoveries of bad debt accounts previously written off.

(c) Uncollectible accounts written off to bad debt expense during the year. In 2004, the amount includes $1,722,744 for uncollectible accounts related to the gas business that have been reclassified to assets held for sale.

(d) Balance for December 31, 2004 excludes the allowance for uncollectible accounts for the gas business of $3,525,033. Prior year balances include allowance for uncollectible accounts for the gas business of $1,626,346 for December 31, 2003.

266

S-4

SCHEDULE II

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

Valuation and Qualifying Accounts

For Years Ended December 31, 2005, 2004 and 2003

	Balance at Beginning Of Period		Additions				Deductions (c)		Balance at End of Period
Description			Charged to Costs and Expenses (a)		Charged to Other Accounts (b)
Allowance for uncollectible accounts:
Year Ended 12/31/05	$	2,689,220	$	1,834,083	$	1,251,347	$	3,440,980	$	2,333,670
Year Ended 12/31/04	$	2,589,979	$	4,045,434	$	1,012,006	$	4,958,199	$	2,689,220
Year Ended 12/31/03	$	3,479,135	$	4,318,472	$	654,126	$	5,861,754	$	2,589,979

(a) Amount accrued to bad debt expense during the year.

(b) Payment recoveries of bad debt accounts previously written off.

(c) Uncollectible accounts written off to bad debt expense during the year.

267

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable.

ITEM 9A.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.    Each Registrant carried out an evaluation, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, of the effectiveness of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, as of December 31, 2005 (the “Evaluation Date”). These disclosure controls and procedures are designed to provide reasonable assurance to each registrant’s management and board of directors that information required to be disclosed by us in the reports that we filed under the Exchange Act is accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, the principal executive officer and principal financial officer of each Registrant have concluded that the applicable Registrant’s disclosure controls and procedures as of December 31, 2005 were effective, at the reasonable assurance level, to ensure that (a) material information relating to each Registrant is accumulated and made known to the Registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure and (b) is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms.

As an accelerated filer, AE is required to meet the requirements under Section 404 of the Sarbanes-Oxley Act of 2002. See “Management’s Report on Internal Control Over Financial Reporting,” below.

Management’s Report on Internal Control Over Financial Reporting.    AE’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. AE’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. AE’s internal control over financial reporting includes those policies and procedures that:

(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of AE’s assets;

(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that AE’s receipts and expenditures are being made only in accordance with authorizations of its management and directors; and

(3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the AE’s assets that could have a material effect on the financial statements.

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

AE’s management assessed the effectiveness of AE’s internal control over financial reporting as of December 31, 2005. In making this assessment, AE’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control-Integrated Framework.”

Based on this assessment, management concluded that, as of December 31, 2005, AE’s internal control over financial reporting is effective based on those criteria.

268

Management’s assessment of the effectiveness of AE’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that appears herein.

Changes in Internal Control over Financial Reporting:    There have been no changes in the registrant’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) that have materially affected, or are reasonable likely to materially affect, internal control over financial reporting during the three months ended December 31, 2005.

ITEM 9B.    OTHER INFORMATION

Not Applicable.

269

PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

Directors of the Registrants

The names, ages and business experience during the past five years of the directors of AE, Monongahela (“MP”), Potomac Edison (“PE”) and AGC and their terms of office are set forth below:

Name	Term of Office Expires (a)	Age	Director since date shown of:
			AE	MP	PE	AGC
H. Furlong Baldwin (b)	2006	74	2003
Eleanor Baum (c)	2006	66	1988
John P. Campbell (d)	2006	50				2004
Paul J. Evanson (e)	2006	64	2003	2003	2003	2003
Cyrus F. Freidheim, Jr. (f)	2006	70	2003
Julia L. Johnson (g)	2006	43	2003
Ted J. Kleisner (h)	2006	61	2001
Steven H. Rice (i)	2006	62	1986
Joseph H. Richardson (j)	2006	56		2003	2003
Gunnar E. Sarsten (k)	2006	69	1992
Jeffrey D. Serkes (l)	2006	47		2003	2003	2003
Michael H. Sutton (m)	2006	65	2004

(a) At AE’s 2004 Annual Meeting of Stockholders, AE’s stockholders voted in favor of a stockholder proposal for the annual election of directors. AE implemented the declassification of its Board of Directors at its 2005 Annual Meeting of Stockholders. Each of the directors who were not up for reelection at that meeting resigned and were reelected, to serve until AE’s 2006 Annual Meeting of Stockholders and until a successor is duly elected and qualified. At AE’s 2006 Annual Meeting of Stockholders, each member of AE’s Board of Directors will stand for reelection, to serve a one-year term and until his or her successor is duly elected and qualified.

(b) H. Furlong Baldwin has been a director since November 2003. Mr. Baldwin has been Chairman of the Board of The NASDAQ Stock Market, Inc. (“NASDAQ”) since 2003 and has been a director of NASDAQ since 2000. Mr. Baldwin is also a director of W.R. Grace & Co., Platinum Underwriters Holdings, Ltd. and the Wills Group. From 1976 to 2001, Mr. Baldwin was Chairman, President and Chief Executive Officer of Mercantile Bankshares Corp. and Mercantile Safe Deposit & Trust Co. Mr. Baldwin is a former director of Mercantile Bankshares Corp., Constellation Energy Group, CSX Corp. and The St. Paul Companies, Inc. and a former Governor of the National Association of Securities Dealers, Inc. He is a member and former Chairman of the Johns Hopkins Medicine Board of Trustees and a member (emeritus) of the Johns Hopkins University Board of Trustees.

(c) Eleanor Baum has been a director since 1988. Dr. Baum has been Dean of the Albert Nerken School of Engineering of The Cooper Union for the Advancement of Science and Art since 1987. Dr. Baum is a director of Avnet, Inc. and United States Trust Company and is past Chair of the Engineering Workforce Commission. Dr. Baum is a Fellow of the Institute of Electrical and Electronic Engineers and past Chairman of the Board of Governors of the New York Academy of Sciences. She is a former President of the Accreditation Board for Engineering and Technology and a former President of the American Society for Engineering Education.

(d) John P. Campbell has been the President of AE Supply since July 2004. He has also been a Vice President of AE and a Vice President and director of AGC since July 2004. Prior to joining Allegheny, Mr. Campbell was responsible for Mirant Corporation’s worldwide generation portfolio from March 2004 to July 2004. He was Managing Director of Coal-Fired Generation for Reliant Energy, Inc. (“Reliant”) from February 2002 to February 2004. Prior to that, he was the East Region Engineering Director for Reliant. See “Executive Officers of the Registrants” below.

270

(e) Paul J. Evanson has been Chairman of the Board, President, Chief Executive Officer and a director of AE since June 2003. Mr. Evanson is the Chair of the Executive Committee. He has also been Chairman, Chief Executive Officer and a director of Monongahela, Potomac Edison and AGC since June 2003. Prior to joining Allegheny, Mr. Evanson was President of Florida Power & Light Company, the principal subsidiary of FPL Group, Inc., and a director of FPL Group, Inc. from 1995 to 2003. See “Executive Officers of the Registrants” below.

(f) Cyrus F. Freidheim, Jr. has been a director since October 2003. Mr. Freidheim has served as Chairman of the Board of Chiquita Brands International, Inc. (“Chiquita”) since 2002 and was Chief Executive Officer of Chiquita from 2002 to 2003. Mr. Freidheim was formerly Vice Chairman of Booz-Allen Hamilton, Inc., at which he also served in various other leadership capacities from 1996 to 2002. Mr. Freidheim also serves as a director of Hollinger International Inc., HSBC Finance Corporation and Sitel Corp.

(g) Julia L. Johnson has been a director since November 2003. Ms. Johnson has been President of NetCommunications, LLC since 2000. She is a director of MasTec and of NorthWestern Corporation. Ms. Johnson is a member of the Department of Energy/National Association of Regulatory Utility Commissioners Energy Market Access Board and the Florida State Board of Education. Ms. Johnson was Senior Vice President of Communications and Marketing for Milcom Technologies from 2000 to 2001. She was Chairman of the Florida Public Service Commission (the “Florida PSC”) from 1997 to 1999 and served as a Commissioner of the Florida PSC from 1992 to 1999.

(h) Ted J. Kleisner has been a director since 2001. Mr. Kleisner has been President of CSX Hotels, Inc. since 1987 and President of The Greenbrier Resort and Club Management Company since 1989. He is a director of Hershey Entertainment and Resorts Company and the American Hotel and Lodging Association. Mr. Kleisner is a member of the Executive Advisory Board for the Daniels College of Business at the University of Denver and a member of the Board of Trustees for the Culinary Institute of America.

(i) Steven H. Rice has been a director since 1986. Mr. Rice currently serves as Managing Director—New York of Gibraltar Private Bank, a federal savings bank. Mr. Rice was an attorney and bank consultant from 2001 to 2005. He is a former director of La Jolla Bank and La Jolla Bancorp, Inc., former President of La Jolla Bank, Northeast Region, former President and Chief Executive Officer of Stamford Federal Savings Bank, former President of The Seamen’s Bank for Savings and former director of the Royal Insurance Group, Inc.

(j) Joseph H. Richardson has been a Vice President of AE since August 2003. He has also been the President and a director of Monongahela and Potomac Edison since August 2003. Prior to joining Allegheny, Mr. Richardson served as President and Chief Executive Officer and as a director of Global Energy Group from March 2002 to August 2003. Prior to that, he served as President and Chief Executive Officer and as a director of Florida Power Corporation. See “Executive Officers of the Registrants” below.

(k) Gunnar E. Sarsten has been a director since 1992. He has been a Consulting Professional Engineer since 1994. He is a former President and Chief Operating Officer of Morrison Knudsen Corporation, former President and Chief Executive Officer of United Engineers & Constructors International, Inc. and former Deputy Chairman of the Third District Federal Reserve Bank in Philadelphia.

(l) Jeffrey D. Serkes has been Senior Vice President and Chief Financial Officer of AE since July 2003. Mr. Serkes has also been a director of Monongahela, Potomac Edison and AGC since July 2003. Prior to joining Allegheny, Mr. Serkes was President of JDS Opportunities LLC from May 2002 to June 2003. Prior to that, Mr. Serkes was employed with IBM as Vice President, Finance, Sales and Distribution, from June 1999 to May 2002, and Vice President and Treasurer from January 1995 to May 1999. Mr. Serkes also serves as a director and as chair of the audit committee of Refac, a Delaware corporation. See “Executive Officers of the Registrants” below.

(m) Michael H. Sutton has been a director since February 2004. Mr. Sutton has been an independent consultant on accounting and auditing regulation since 1999. He is a director of American International Group, Inc. and Krispy Kreme Doughnuts, Inc. Mr. Sutton is a former Chief Accountant for the SEC and a former senior partner and National Director of Accounting and Auditing Professional Practice for Deloitte & Touche LLP.

271

Executive Officers of the Registrants

The names of the executive officers of each Registrant, their ages, the positions they hold, and their business experience during the past five years appear below. All officers of the registrants are elected annually.

Name	Age	AE	MP	PE	AGC
Paul J. Evanson (a)	64	Chairman, President, Chief Executive Officer and Director	Chairman, Chief Executive Officer and Director	Chairman, Chief Executive Officer and Director	Chairman, Chief Executive Officer and Director
John P. Campbell (b)	50	Vice President			Vice President Director
Edward Dudzinski (c)	53	Vice President	Vice President	Vice President
Thomas R. Gardner (d)	48	Vice President, Controller, Chief Accounting Officer and Chief Information Officer	Controller	Controller	Vice President and Controller
Philip L. Goulding (e)	46	Vice President
Hyun Park (f)	44	Vice President, General Counsel and Secretary	Vice President and Secretary	Vice President and Secretary	Vice President and Secretary
Joseph H. Richardson (g)	56	Vice President	President and Director	President and Director
Jeffrey D. Serkes (h)	47	Senior Vice President and Chief Financial Officer	Vice President and Director	Vice President and Director	Vice President and Director

(a) Paul J. Evanson has been Chairman of the Board, President, Chief Executive Officer and a director of AE since June 2003. Mr. Evanson is the Chair of the Executive Committee. He has also been Chairman, Chief Executive Officer and a director of Monongahela, Potomac Edison and AGC since June 2003. Prior to joining Allegheny, Mr. Evanson was President of Florida Power & Light Company, the principal subsidiary of FPL Group, Inc., and a director of FPL Group, Inc. from 1995 to 2003.

(b) John P. Campbell has been the President of AE Supply since July 2004. He has also been a Vice President of AE and a Vice President and director of AGC since July 2004. Prior to joining Allegheny, Mr. Campbell was responsible for Mirant Corporation’s worldwide generation portfolio from March 2004 to July 2004. He was Managing Director, Coal-Fired Generation for Reliant from February 2002 to February 2004. Prior to that, he was the East Region Engineering Director for Reliant.

(c) Edward Dudzinski has been Vice President, Human Resources, of AE since August 2004. He has also been a Vice President of Monongahela and Potomac Edison since August 2004. Prior to joining Allegheny, Mr. Dudzinski was Vice President, Human Resources for the Agriculture and Nutrition Platform and Pioneer Hi-Bred International, Inc. on behalf of DuPont. Prior to that, he served in various other executive and leadership positions at DuPont.

(d) Thomas R. Gardner has been Vice President, Controller and Chief Accounting Officer of AE since October 2003 and has been Chief Information Officer of AE since June 2005. He has also been the Controller of Monongahela and Potomac Edison and a Vice President and the Controller of AGC since October 2003. Prior to joining Allegheny, Mr. Gardner was employed with Deloitte & Touche LLP from 1997 to 2003, most recently as a partner.

(e) Philip L. Goulding has been Vice President, Strategic Planning and Chief Commercial Officer of AE since October 2003. Prior to joining Allegheny, Mr. Goulding led the North American energy practice of L.E.K. Consulting from 1999 to October 2003.

(f) Hyun Park has been Vice President, General Counsel and Secretary of AE since April 2005. He has also been Vice President and Secretary of Monongahela, Potomac Edison and AGC since April 2005. Prior to joining Allegheny, Mr. Park was employed with Sithe Energies, Inc. as Senior Vice President, General Counsel and

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Secretary from March 2000 to February 2005 and as General Counsel and Secretary from July 1998 to March 2000. Prior to joining Sithe Energies, Inc., he was a partner with the law firm of Latham & Watkins.

(g) Joseph. H. Richardson has been a Vice President of AE since August 2003. He has also been the President and a director of Monongahela and Potomac Edison since August 2003. Prior to joining Allegheny, Mr. Richardson served as President and Chief Executive Officer and as a director of Global Energy Group from March 2002 to August 2003. Prior to that, he served as President and Chief Executive Officer and as a director of Florida Power Corporation.

(h) Jeffrey D. Serkes has been Senior Vice President and Chief Financial Officer of AE since July 2003. Mr. Serkes has also been a Vice President and director of Monongahela, Potomac Edison and AGC since July 2003. Prior to joining Allegheny, Mr. Serkes was President of JDS Opportunities LLC from May 2002 to June 2003. Prior to that, Mr. Serkes was employed with IBM as Vice President, Finance, Sales and Distribution, from June 1999 to May 2002, and Vice President and Treasurer from January 1995 to May 1999. Mr. Serkes also serves as a director and as chair of the audit committee of Refac, a Delaware corporation.

Code of Business Conduct and Ethics

In early 2004, Allegheny adopted a new Code of Business Conduct and Ethics for its directors, officers and employees in order to promote honest and ethical conduct and compliance with the laws and regulations to which Allegheny is subject. All directors, officers and employees of Allegheny are expected to be familiar with the Code of Business Conduct and Ethics and to adhere to its principles and procedures.

Audit Committee Financial Expert

The Board of Directors of AE has determined that one member of its audit committee, Michael H. Sutton, is an audit committee financial expert within the meaning of the SEC’s rules, and is independent within the meaning of Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act. Each of the respective Boards of Directors of AGC, Monongahela and Potomac Edison has determined that it does not have an audit committee financial expert.

Audit Committees of Listed Issuers

The information required to be provided pursuant to Item 401(i) of Regulation S-K with respect to AE is incorporated by reference to “Committees of the Board of Directors—Audit Committee” from AE’s definitive proxy statement to be filed with the SEC. Monongahela is exempt from the audit committee requirements of Rule 10A-3 under the Exchange Act under paragraph (c) of such Rule, which provides certain exemptions, including an exemption for companies that are consolidated subsidiaries of companies that are subject to the rule. Monongahela believes that its reliance on an available exemption from this rule is appropriate given that AE’s audit committee, the members of which meet applicable independence and financial literacy standards, perform an oversight function with respect to certain aspects of AE’s consolidated financial reporting. Potomac Edison and AGC are not listed issuers within the meaning of the SEC’s rules.

Website Access

Allegheny’s Code of Business Conduct and Ethics, its Corporate Governance Guidelines and the Charters for the Audit Committee, Management Compensation and Development Committee and Nominating and Governance Committee of AE’s Board of Directors are available on AE’s website, www.alleghenyenergy.com, in the Corporate Governance section. Amendments to these documents are also available on AE’s website. Copies of each of these documents are available free of charge to any stockholder upon request.

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Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires AE’s directors and executive officers and persons who own more than 10% of a registered class of AE’s equity securities to file with the SEC and the New York Stock Exchange reports on Forms 3, 4 and 5 concerning their ownership of the common stock and other equity securities of AE. Under SEC rules, AE must be furnished with copies of these reports.

Based on AE’s review of these filings, AE believes that all of its directors, executive officers and stockholders who are required to file reports filed all of such reports on a timely basis during the year ended December 31, 2005.

ITEM 11.    EXECUTIVE COMPENSATION

The annual compensation paid by Allegheny to its Chief Executive Officer and each of its four highest paid executive officers for the year ended December 31, 2005 (collectively, the “Named Executive Officers”) was as follows for 2005, 2004 and 2003:

Summary Compensation Table (a)

	Annual Compensation					Long-Term Compensation
Name and Principal Position	Year	Salary ($)(b)	Bonus ($)		Other Annual Compensation ($) (d)	Restricted Stock Awards ($) (e)	Securities Underlying Options	All Other Compensation ($) (f)
Paul J. Evanson Chairman, President and Chief Executive Officer	2005 2004 2003	940,900 914,272 467,308	1,500,000 1,500,000 7,087,500	(c)	135,204 —   —	—   27,360,010 —	—   1,500,000 —	7,496 104,072 97,330
Jeffrey D. Serkes Senior Vice President and Chief Financial Officer	2005 2004 2003	500,000 500,000 230,769	730,000 775,000 625,000	(c)	—   1,806 —	—   9,542,513 —	—   550,000 —	9,746 132,310 75,753
Hyun Park Vice President and General Counsel (g)	2005 2004 2003	320,192 —   —	605,000 —   —	(c)	—   —   —	1,054,000 —   —	150,000 —   —	82,504 —   —
Philip L. Goulding Vice President	2005 2004 2003	400,000 400,000 76,923	440,000 415,000 682,500	(c)	—   —   —	—   2,002,500 —	—   746,403 —	6,664 6,250 42,498
Joseph H. Richardson Vice President	2005 2004 2003	400,000 400,000 130,769	290,000 225,000 92,216		—   —   —	—   1,467,512 —	—   200,000 —	7,212 7,019 74,326

(a) The compensation shown is for all services in all capacities to Allegheny and its subsidiaries. All salaries, annual incentives and long-term payouts of these executives are paid by AESC.

(b) Mr. Park joined Allegheny on April 5, 2005.

(c) Incentive awards are based upon performance in the year in which the figure appears, but are paid in the following year. The figure in this column for 2005 includes a signing bonus of $240,000 for Mr. Park. The figure in this column for 2003 includes an initial make-whole payment of $6,300,000 for Mr. Evanson, an initial make-whole payment of $250,000 for Mr. Serkes and an initial make-whole payment of $600,000 for Mr. Goulding.

(d) The figures in this column include the aggregate incremental cost to the Company of providing personal benefits to the Named Executive Officers. The personal benefits included in this column are for the personal

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use of the company aircraft and use of a leased car. The amounts reported in this column include $134,422 for the personal use of the company aircraft by Mr. Evanson in 2005. The figures in this column also include an amount for the personal use of the company aircraft by Mr. Serkes for 2004 of $1,806. See “Valuation of Perquisites” below for additional information.

(e) Messrs. Evanson, Serkes, Goulding and Richardson entered into employment agreements in 2003 and Mr. Park entered into an employment agreement in 2005, under which they were to be granted stock units to induce them to accept employment at Allegheny. These stock units were granted to Messrs. Evanson, Serkes, Goulding and Richardson on February 18, 2004 and to Mr. Park on April 5, 2005. The amounts shown represent the dollar value of stock units issued under Allegheny’s Stock Unit Plan. For Messrs. Evanson, Serkes, Goulding and Richardson, the amounts are based on the closing price of $13.35 per share and for Mr. Park, the amount is based on the closing price of $21.08 per share, of the Company’s common stock on the New York Stock Exchange on the grant date. Each stock unit represents one share of Allegheny common stock. Holders of stock units are credited with any dividends that would be payable on the shares, which are deemed to be reinvested in additional stock units. These additional stock units vest on the same schedule as the underlying units in respect of which they are credited. On February 18, 2004, 2,049,439 units were granted to Mr. Evanson, 714,795 units were granted to Mr. Serkes, 150,000 units were granted to Mr. Goulding and 109,926 units were granted to Mr. Richardson. On April 5, 2005, 50,000 units were granted to Mr. Park. One-fifth of Mr. Evanson’s stock units vest on each June 9 from 2004 through 2008. One-third of Mr. Serkes’ stock units vest on each July 3 from 2004 through 2006. One-fifth of Mr. Park’s units vest on each April 5 from 2006 through 2010. One-fifth of Mr. Goulding’s stock units vest on each October 13 from 2004 through 2008. One-fifth of Mr. Richardson’s units vest on each August 25 from 2004 through 2008.

As of December 30, 2005, based on the closing price of $31.65 per share of Allegheny’s common stock on the New York Stock Exchange on that date, Mr. Evanson held 1,229,663 unvested stock units having an aggregate value of $38,918,834, Mr. Serkes held 238,265 unvested stock units having an aggregate value of $7,541,087, Mr. Park held 50,000 unvested stock units having an aggregate value of $1,582,500, Mr. Goulding held 90,000 unvested stock units having an aggregate value of $2,848,500 and Mr. Richardson held 65,956 unvested stock units having an aggregate value of $2,087,507.

(f) The figures in this column include the premium paid for the group life insurance plan. In addition, amounts in this column include Allegheny’s contribution for the ESOSP. For 2005, the figures shown include amounts representing the life insurance premiums on Allegheny’s group life insurance plan and ESOSP contributions, respectively, as follows: Mr. Evanson, $3,708 and $3,788; Mr. Serkes, $3,708 and $6,038; Mr. Park $2,514 and $0; Mr. Goulding, $2,981 and $3,683; and Mr. Richardson, $2,981 and $4,231.

(g) Mr. Park joined Allegheny on April 5, 2005. The figure in the All Other Compensation column for 2005 includes $79,990 for relocation expenses.

Valuation of Perquisites

The Company provided certain perquisites to senior executives in 2005 as summarized below.

Company Aircraft—With the approval of the Chief Executive Officer, the Company’s aircraft may be used by the Company’s senior executives for business purposes. Certain senior executives use the Company’s aircraft for other travel with the approval of the Chief Executive Officer. In 2005, Allegheny valued the personal use of Company aircraft, for purposes of compensation disclosure, using a method that takes into account the variable cost per flight hour, as well as other direct out of pocket expenses including landing, parking and certain hangar storage expenses, crew travel expenses, and passenger ground transportation. For tax purposes, any personal use is considered imputed income and is valued at a Standard Industry Fare Level (“SIFL”), a per-mile rate issued periodically by IRS, and multiplier factor based on aircraft size and employee position.

Company Vehicle—A Company vehicle is provided to the Chief Executive Officer and the Chief Financial Officer for business and personal use. Any personal use is considered imputed income and is based on the value of the vehicle. Based on IRS regulations, personal use of a Company-leased car has been valued at the cost of the annual lease for compensation disclosure purposes.

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Option Grants in the Last Fiscal Year

The following table sets forth information for each Named Executive Officer with regard to stock options granted in 2005.

	Individual Grants
Name	Number of Securities Underlying Options Granted (#) (a)	% of Total Options Granted to Employees in Fiscal Year	Exercise Price ($/sh)			Expiration Date	Grant Date Present Value ($) (b)
Hyun Park	150,000	34.0	$	21.08	(c)	April 5, 2015	1,384,500

(a) Mr. Park entered into an employment agreement in 2005, under which he was granted stock options to induce him to accept employment at Allegheny. The stock options were granted on April 5, 2005.

(b) The amounts shown are based on the Black-Scholes option-pricing model.

(c) Based on the closing price of a share of Allegheny’s common stock on the New York Stock Exchange on April 5, 2005.

Aggregate Option Exercises in Last Fiscal Year and FY-End Option Values

The following table sets forth information for each Named Executive Officer with regard to stock options held at December 31, 2005. None of the Named Executive Officers exercised options in 2005.

	Number of Securities Underlying Unexercised Options at FY-End		Value of Unexercised In-the-Money Options at FY-End ($) (a)
Name	Exercisable	Unexercisable	Exercisable	Unexercisable
Paul J. Evanson	600,000	900,000	10,980,000	16,470,000
Jeffrey D. Serkes	366,666	183,334	6,709,988	3,355,012
Hyun Park	—	150,000	—	1,585,500
Philip L. Goulding	298,560	447,843	5,463,648	8,195,527
Joseph H. Richardson	80,000	120,000	1,464,000	2,196,000

(a) The amounts shown are based on the closing price of a share of Allegheny’s common stock on the New York Stock Exchange on December 30, 2005, minus the exercise price. All of the options shown on the table above have an exercise price of $13.35 per share with the exception of the options held by Mr. Park, which have an exercise price of $21.08 per share.

Group Life Insurance Plan

Allegheny provides life insurance to all eligible employees under a group life insurance plan that pays a death benefit equal to the insured’s base salary, excluding bonuses, during employment, or $25,000 during retirement.

ESOSP

The ESOSP was established as a non-contributory stock ownership plan for all eligible employees, effective January 1, 1976, and was amended in 1984 to include a savings program. All of Allegheny’s employees, subject to meeting eligibility requirements, may elect to participate in the ESOSP. Each eligible employee can elect to have from 2% to 15% of his or her compensation contributed to the ESOSP on a pre-tax basis and an additional 1% to 6% on a post-tax basis. Participants direct the investment of contributions to specified mutual funds or to investments in Allegheny common stock. Allegheny matches 50% of the first 6% of pre-tax compensation deferred into the ESOSP by an employee. For 2003, 2004, and 2005, the maximum amount of compensation to be factored into these calculations was $200,000, $205,000, and $210,000 respectively. Pre-tax contributions may be withdrawn only if financial hardship requirements are met or employment is terminated.

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Retirement Plan

Allegheny maintains a retirement plan covering substantially all Allegheny employees (the “Retirement Plan”). The Retirement Plan is a noncontributory, trusteed pension plan designed to meet the requirements of Section 401(a) of the Internal Revenue Code of 1986, as amended (the “Code”). Each covered employee is eligible for retirement at their normal retirement date (age 65), with early retirement permitted.

Allegheny also maintains the SERP for executive officers and other senior managers. All executive officers, except Messrs. Evanson and Serkes, are participants in the SERP. Except as otherwise set forth in employment agreements between Allegheny and certain executives, a SERP participant will be eligible to receive benefits under the SERP only if he or she has been credited with at least 10 years of service with Allegheny and has reached his or her 55th birthday. The spouse of a SERP participant will be eligible to receive survivor benefits under the SERP if a SERP participant has been credited with at least 10 years of service (15 years of service if the SERP participant is under age 55) and dies before retirement. Under the SERP, an eligible participant will receive a supplemental retirement benefit equal to his or her average compensation multiplied by the sum of: (a) 2% for each year of service up to 25; (b) 1% for each year of service from 26 to 30 and (c) 0.5% for each year of service from 31 to 40, less benefits paid under the Retirement Plan and less 2% for each year that a participant retires prior to his or her 60th birthday. As such, a participant’s benefits are capped at 60% of average compensation, less amounts paid to the participant from the Retirement Plan, and less 2% for each year the participant retires prior to age 60.

The SERP defines average compensation as 12 times a participant’s average monthly compensation, including overtime, any award paid under the Annual Incentive Plan (the “AIP”) and other salary payments actually earned, whether or not payment is deferred, for the 36 consecutive calendar months constituting the period of highest average monthly compensation. The SERP takes into account compensation in excess of the Code maximums that apply to the Retirement Plan.

If a SERP participant is terminated by Allegheny for cause (as defined in his or her employment agreement, or, if no such agreement exists, as defined in the SERP), the participant will forfeit his SERP benefit. Similarly, if a SERP participant starts receiving SERP benefits and the participant commits a material breach of an employment, separation, covenant not to compete, confidentiality or other agreement with Allegheny or Allegheny later determines (based upon information previously unknown to the Management Compensation and Development Committee or senior management) that a basis existed to terminate the SERP participant for cause, payment of SERP benefits will cease.

The following table shows estimated maximum annual benefits payable to participants in the SERP and the Retirement Plan following retirement (assuming payments on a normal life annuity basis and not including any survivor benefit) to an employee in specified remuneration and years of credited service classifications. These amounts are based on an estimated average compensation, retirement at age 60, without consideration of any effect of various options which may be elected prior to retirement. The benefits under the SERP are not subject to any deduction for Social Security or any other offsetting amounts.

PENSION PLAN TABLE

	Years of Credited Service (b)
Average Compensation (a)	15 Years		20 Years		25 Years		30 Years		35 Years		40 Years
$  200,000	$	60,000	$	80,000	$	100,000	$	110,000	$	115,000	$	120,000
300,000		90,000		120,000		150,000		165,000		172,500		180,000
400,000		120,000		160,000		200,000		220,000		230,000		240,000
500,000		150,000		200,000		250,000		275,000		287,500		300,000
600,000		180,000		240,000		300,000		330,000		345,000		360,000
700,000		210,000		280,000		350,000		385,000		402,500		420,000
800,000		240,000		320,000		400,000		440,000		460,000		480,000
900,000		270,000		360,000		450,000		495,000		517,000		540,000
1,000,000		300,000		400,000		500,000		550,000		575,000		600,000
1,100,000		330,000		440,000		550,000		605,000		632,500		660,000
1,200,000		360,000		480,000		600,000		660,000		690,000		720,000
1,300,000		390,000		520,000		650,000		715,000		747,000		780,000

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(a) The earnings of Messrs. Park, Goulding, and Richardson covered by the SERP correspond substantially to the amounts shown for them in the Summary Compensation Table.

(b) As of December 31, 2005, Messrs. Goulding and Richardson each had been credited with two full years of service and Mr. Park had not been credited with any full years of service. Following five years of service, Messrs. Park, Goulding, and Richardson will be credited with an additional five years under the SERP. Following ten years of service, Messrs. Goulding and Richardson will be credited with a further five years under the SERP.

Annual Incentive Plan

The AIP, which was approved by Allegheny’s stockholders at the 2004 Annual Meeting, was established to recognize and reward executives who have contributed significantly to Allegheny’s success and to their respective business units, to align the corporate vision, goals and business strategy with compensation strategy and to provide a compensation environment that will attract, motivate and retain executives. The Management Compensation and Development Committee of the Board (the “Committee”) establishes a target award level for each participant. Each award is conditioned on Allegheny’s achievement of the performance threshold established by the Committee and the achievement of other financial, operational and corporate objectives. Each participant’s award is adjusted based on individual performance.

The Committee determined the target awards for 2005. Participants could earn from zero to 200% of the target award. For 2005, the targets were $953,900 for Mr. Evanson and from $200,000 to $500,000 for the other Named Executive Officers. Targets for other participants were up to $150,000, or up to approximately 50% of 2005 base salary. AIP awards are paid in the first quarter of the year following the year for which they are granted.

Certain executive officers were granted awards for 2003 under the provisions of their employment agreements. Awards earned for performance in 2003, 2004 and 2005 are disclosed in the Summary Compensation Table for the individuals named.

Long-Term Incentive Plan

The Board and stockholders approved the LTIP to assist Allegheny in attracting and retaining key employees and directors and motivating performance. The LTIP is administered by the Committee, which may delegate to an executive officer the power to determine the employees (other than himself or herself) eligible to receive awards. The Committee may from time to time designate key employees and directors to participate in the LTIP for a particular year. The number of shares of Allegheny common stock initially authorized for issuance under the LTIP is 10 million, subject to adjustments for recapitalizations or other changes to Allegheny’s common stock. No participant in the LTIP may be granted more than 600,000 shares (or rights or options in respect of more than 600,000 shares) in any calendar year. For purposes of this limit, shares subject to an award that is to be earned over a period of more than one calendar year will be allocated to the first calendar year in which the shares may be earned. The LTIP will terminate on May 14, 2008.

The Committee may, unless the relevant award agreement otherwise specifies, cancel, rescind or suspend an award if the LTIP participant engages in competitive activity, discloses confidential information, solicits employees, customers, partners or suppliers of Allegheny or undertakes any other action determined by the Committee to be detrimental to Allegheny.

Stock Option Awards

The LTIP permits awards of options to purchase Allegheny common stock on terms and conditions determined by the Committee. Stock options are issued at strike prices equal to the fair market value (as defined in the LTIP) of Allegheny common stock as of the date of the option grant. The terms of option awards are set forth in option award agreements. The Committee may award non-qualified stock options or incentive stock

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options (each as defined in the LTIP). No participant in the LTIP may receive incentive stock option awards under the LTIP or any other Allegheny compensation plan that would result in incentive stock options to purchase shares of Allegheny common stock with an aggregate fair market value of more than $100,000 first becoming exercisable by the participant in any one calendar year.

Options awarded under the LTIP will terminate upon the first to occur of: (a) the option’s expiration under the terms of the related option award agreement; (b) termination of the award following termination of the participant’s employment under the rules described in the next paragraph or (c) 10 years after the date of the option grant. The Committee may accelerate the exercise period of awarded options and may extend the exercise period of options granted to employees who have been terminated.

In the event of the termination of employment of a participant in the LTIP on or after January 1, 2004, options not exercisable at the time of the termination will expire as of the date of the termination, and exercisable options will expire 90 days from the date of termination. In the event of termination of a participant’s employment due to retirement or disability, options not exercisable will expire as of the date of termination, and exercisable options will expire three years after the date of termination. In the event of the death of a participant in the LTIP, all options not exercisable at the time of death will expire, and exercisable options will remain exercisable by the participant’s beneficiary until the first to occur of three years from the time of death or, if applicable, three years from the date of the termination of the participant’s employment due to retirement or disability.

The Committee may establish dividend equivalent accounts with respect to awarded options. A participant’s dividend equivalent account will be credited with notional amounts equal to dividends that would be payable on the shares for which the participant’s options are exercisable, assuming that the shares were issued to the participant. The participant or other holder of the option will be entitled to receive cash from the dividend equivalent account at the time or times and subject to the terms and conditions as the Committee determines and provides in the applicable option award agreement. If an option terminates or expires prior to exercise, the dividend equivalent account related to the option will be concurrently eliminated and no payment in respect of the account will be made.

The Committee may permit the exercise of options or the payment of applicable withholding taxes through tender of previously acquired shares of Allegheny common stock or through reduction in the number of shares issuable upon option exercise. The Committee may grant reload options to participants in the event that participants pay option exercise prices or withholding taxes by these methods.

In the event of a change of control of Allegheny (as defined in the LTIP), unless provided to the contrary in the applicable option award agreement, all options outstanding on the date of the change in control will become immediately vested and fully exercisable.

During 2005, Allegheny entered into an employment agreement with Mr. Park under which he was granted 150,000 stock options on April 5, 2005 to induce him to accept employment at Allegheny. The options vest ratably from 2006 through 2010.

Restricted Share Awards

The Committee may grant restricted shares of common stock on terms, conditions and restrictions determined by the Committee. The restrictions, terms and conditions may be based on performance standards, period of service, share ownership or other criteria. Performance-based awards are subject to the same performance targets as described under “Performance Awards” below. The terms of restricted stock awards are set forth in award agreements. No restricted share awards were issued under the LTIP in 2005.

Performance Awards

The Committee may grant performance awards, which will consist of a right to receive a payment that is either measured by the fair market value of a specified number of shares of Allegheny common stock, increases

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in the fair market value of Allegheny common stock during an award period and/or consists of a fixed cash amount. Performance awards may be made in conjunction with or in addition to restricted stock awards. Award periods are determined by the Committee. The Committee may permit newly eligible participants to receive performance awards after an award period has commenced.

The Committee establishes performance targets in connection with performance awards. In the case of awards intended to be deductible for federal income tax purposes, performance targets generally relate to operating income, return on investment, return on stockholders’ equity, stock price appreciation, earnings before interest, taxes and depreciation/amortization, earnings per share and/or growth in earnings per share. The Committee prescribes formulas to determine the percentage of the awards earned based on the degree to which award targets are achieved. Allegheny may make payments in respect of performance awards in cash, shares of Allegheny common stock or a combination of both.

In the event of a participant’s retirement during an award period, the participant will not receive a performance award unless otherwise determined by the Committee, in which case the participant will be entitled to a prorated portion of the award. In the event of the death or disability of a participant during an award period, the participant or his or her representative will be entitled to a prorated portion of the performance award. A participant will not be entitled to a performance award if his or her employment terminates prior to the conclusion of an award period, provided that the Committee may determine in its discretion to pay performance awards, including full (non-prorated) awards, to any participant whose employment is terminated. In the event of a change of control of Allegheny, all performance awards for all award periods will immediately become payable to all participants and will be paid within 30 days after the change in control.

No performance awards were issued under the LTIP in 2005.

Stock Unit Plan

The Board approved the Stock Unit Plan to assist Allegheny in attracting key executives. Allegheny awarded stock units to certain Named Executive Officers under the terms of their respective employment agreements or employment offers to induce them to accept employment at the Company. For more information regarding these grants, see “Summary Compensation Table” above.

During 2005, Allegheny entered into an employment agreement with Mr. Park under which he was granted 50,000 stock units on April 4, 2005 to induce him to accept employment at Allegheny. These stock units vest ratably from 2006 through 2010.

Agreements with Certain Executive Officers

Change In Control Contracts

In 2003 and 2005, Allegheny entered into employment agreements, as discussed below, with newly-appointed executive officers. These employment agreements contain change in control provisions that are discussed in more detail below with respect to some of the Named Executive Officers.

Employment Agreement with Paul J. Evanson

Paul J. Evanson’s employment agreement with Allegheny and AESC has a five-year term that began on June 16, 2003. The agreement provides for a base salary of $900,000 per year, subject to annual inflation adjustment, and may be increased, but not decreased, in the sole discretion of the Board. Mr. Evanson is eligible to receive annual incentive compensation under the AIP, with a target bonus opportunity of 100% of his base salary and a maximum bonus opportunity of 200% of his base salary. In lieu of benefits under the SERP, Mr. Evanson accrues a lump sum cash payment of $66,667 for each month that he is employed by Allegheny, to be paid on termination of employment. Mr. Evanson received an initial make-whole payment of $6,300,000 under the agreement in respect of financial and other benefits forfeited as a result of his accepting employment with Allegheny.

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Pursuant to his employment agreement, Mr. Evanson received a grant of stock options to purchase 1,500,000 shares of AE Common Stock under the LTIP and 2,049,439 stock units, each representing one share of Common Stock. Mr. Evanson’s employment agreement was amended as of February 18, 2004 to delay the grant date of the stock options from January 2, 2004 until February 18, 2004, which was five business days after receipt of SEC confirmation as to the issuance of these grants. The stock options and stock units were issued on February 18, 2004. One-fifth of the stock options and stock units vest on each June 9 from 2004 through 2008, provided that Mr. Evanson remains employed by Allegheny on the applicable vesting dates. The stock units are payable in stock on each vesting date or such later date as Mr. Evanson has elected. If a change in control (as defined in the agreement) occurs, or upon the occurrence of certain triggering events relating to an equity vesting event (as defined in the agreement), all of Mr. Evanson’s unvested stock options and stock units will immediately vest.

If Mr. Evanson’s employment by the Company is terminated, he will be entitled to certain salary and benefit amounts that are accrued but unpaid at the time of the termination. In addition, if the Company terminates the employment agreement other than for cause (as defined in the agreement), if the employment agreement terminates due to Mr. Evanson’s death or disability (as defined in the agreement) or if Mr. Evanson terminates the employment agreement for good reason (as defined in the agreement), Mr. Evanson will be entitled to additional payments and benefits, and the vesting of his unvested stock options, stock units and other equity compensation grants will be accelerated. The amount of severance and the other benefits to which Mr. Evanson is entitled in connection with the termination of his employment, and the amount of time following his termination that his stock options will remain exercisable, varies depending upon whether the employment agreement is terminated (a) due to Mr. Evanson’s death or disability, or (b) by the Company other than for cause, by Mr. Evanson for good reason or following a change in control. The severance and other benefits to which Mr. Evanson is entitled in each of these circumstances are more fully described in the employment agreement.

The employment agreement subjects Mr. Evanson to a non-competition obligation for one year and a non-solicitation obligation for two years following the termination of his employment and customary confidentiality obligations. Mr. Evanson is also entitled to a number of other customary benefits under the employment agreement, including indemnification rights, payment or reimbursement of temporary living and relocation expenses, vacation and reimbursement of reasonable and necessary business expenses. Additionally, the agreement entitles him to gross-up payments in the event his compensation is subject to excise tax.

Employment Agreement with Jeffrey D. Serkes

Jeffrey D. Serkes’ employment agreement with Allegheny and AESC has a three-year term that began on July 7, 2003, subject to successive one-year renewals. The agreement provides for a base salary of $500,000 per year, which may be increased, but not decreased, in the sole discretion of the Board. Mr. Serkes is eligible to receive annual incentive compensation under the AIP, with a target bonus opportunity of 100% of his base salary and a maximum bonus opportunity of 200% of his base salary. In lieu of benefits under the SERP, Mr. Serkes accrues a lump sum cash payment of $41,667 for each month that he is employed by Allegheny, to be paid at age 55 or earlier, if specified events occur. Mr. Serkes received an initial make-whole payment of $250,000 under the agreement in respect of financial and other benefits forfeited as a result of his accepting employment with Allegheny.

Pursuant to his employment agreement, Mr. Serkes received a grant of stock options to purchase 550,000 shares of AE Common Stock under the LTIP and 714,795 stock units, each representing one share of Common Stock. Mr. Serkes’ employment agreement was amended as of February 18, 2004 to delay the grant date of the stock options from January 2, 2004 until February 18, 2004, which was five business days after receipt of SEC confirmation as to the issuance of these grants. The stock options and stock units were issued on February 18, 2004. One-third of the stock options and stock units vest on each July 3 from 2004 through 2006, provided that Mr. Serkes remains employed by Allegheny on the applicable vesting dates. The stock units are payable in stock on each vesting date or such later date as Mr. Serkes has elected. If a change in control (as defined in the agreement) occurs, all of Mr. Serkes’ unvested stock options and stock units will immediately vest.

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If Mr. Serkes’s employment by the Company is terminated, he will be entitled to certain salary and benefit amounts that are accrued but unpaid at the time of the termination. In addition, if the Company terminates the employment agreement other than for cause (as defined in the agreement), if the employment agreement terminates due to Mr. Serkes’s death or disability (as defined in the agreement) or if Mr. Serkes terminates the employment agreement for good reason (as defined in the agreement), Mr. Serkes will be entitled to additional payments and benefits, and the vesting of his unvested stock options, stock units and other equity compensation grants will be accelerated. The amount of severance and the other benefits to which Mr. Serkes is entitled in connection with the termination of his employment, and the amount of time following his termination that his stock options will remain exercisable, varies depending upon whether the employment agreement is terminated (a) due to Mr. Serkes’s death or disability, or (b) by the Company other than for cause or by Mr. Serkes for good reason and, in the case of termination by the Company other than for cause or by Mr. Serkes for good reason, if the termination occurs following or in anticipation of a change in control. The severance and other benefits to which Mr. Serkes is entitled in each of these circumstances are more fully described in the employment agreement.

The employment agreement subjects Mr. Serkes to a non-competition obligation for one year and a non-solicitation obligation for two years following the termination of his employment and customary confidentiality obligations. Mr. Serkes is also entitled to a number of other customary benefits under the employment agreement, including indemnification rights, payment or reimbursement of temporary living and relocation expenses, vacation and reimbursement of reasonable and necessary business expenses. Additionally, the agreement entitles him to gross-up payments in the event his compensation is subject to excise tax.

Employment Agreement with Hyun Park

Hyun Park’s employment agreement with Allegheny and AESC has a five-year term that began on April 5, 2005. The agreement provides for a base salary of $450,000 per year, which may be increased, but not decreased, in the sole discretion of the Board. Mr. Park is eligible to receive annual incentive compensation under the AIP, with a target bonus opportunity of 77.78% of his base salary and a maximum bonus opportunity of 155.56% of his base salary. For 2005, the target and maximum bonus amounts were $262,500 and $525,000 respectively. Mr. Park received a signing bonus of $240,000 under the agreement.

Pursuant to his employment agreement, on April 5, 2005, Mr. Park received a grant of stock options to purchase 150,000 shares of AE Common Stock under the LTIP and 50,000 stock units, each representing one share of Common Stock. One-fifth of the stock options and stock units vest on each April 5 from 2006 through 2010, provided that Mr. Park remains employed by Allegheny on the applicable vesting dates. The units are payable in stock on each vesting date or such later date as Mr. Park has elected. If a change in control (as defined in the agreement) occurs, all of Mr. Park’s unvested stock options and stock units will immediately vest.

Mr. Park is eligible to participate in the SERP, as well as in the other employee benefit and compensation plans maintained by the Company. Solely for purposes of determining the amount of his benefits under the SERP, Mr. Park will be credited with five additional years of service, and will be deemed to be vested in the SERP, on April 5, 2010, provided that he remains employed by the Company at that time. If Mr. Park’s employment by the Company is terminated prior to April 5, 2010, in lieu of a benefit payable under the SERP, he will be entitled to receive a lump sum cash payment equal to $20,833.33 for each month that he was employed by the Company (the “Special Payment”). If Mr. Park’s employment by the Company is terminated after April 5, 2010, he will be entitled to receive the greater of the Special Payment or the benefit payable under the SERP.

If Mr. Park’s employment by the Company is terminated, he will be entitled to certain salary and benefit amounts that are accrued but unpaid at the time of the termination. In addition, if the Company terminates the employment agreement other than for cause (as defined in the agreement), if the employment agreement terminates due to Mr. Park’s death or disability (as defined in the agreement) or if Mr. Park terminates the employment agreement for good reason (as defined in the agreement), Mr. Park will be entitled to additional

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payments and benefits, and the vesting of his unvested stock options, stock units and other equity compensation grants will be accelerated. The amount of severance and the other benefits to which Mr. Park is entitled in connection with the termination of his employment, and the amount of time following his termination that his stock options will remain exercisable, varies depending upon whether the employment agreement is terminated (a) due to Mr. Park’s death or disability, or (b) by the Company other than for cause or by Mr. Park for good reason and, in the case of termination by the Company other than for cause or by Mr. Park for good reason, if the termination occurs following or in anticipation of a change in control. The severance and other benefits to which Mr. Park is entitled in each of these circumstances are more fully described in the employment agreement.

The employment agreement subjects Mr. Park to a non-competition obligation under certain circumstances for one year and a non-solicitation obligation for two years following the termination of his employment and customary confidentiality obligations. Mr. Park is also entitled to a number of other customary benefits under the employment agreement, including indemnification rights, payment or reimbursement of temporary living and relocation expenses, vacation and reimbursement of reasonable and necessary business expenses. Additionally, the agreement entitles him to gross-up payments in the event his compensation is subject to excise tax.

Employment Agreement with Philip L. Goulding

Philip L. Goulding’s employment agreement with Allegheny and AESC has a five-year term that began on October 13, 2003. The agreement provides for a base salary of $400,000 per year, which may be increased, but not decreased, in the sole discretion of the Board. Mr. Goulding will be eligible to receive an annual incentive compensation under the AIP, with a target bonus opportunity of 75% of his base salary and a maximum bonus opportunity of 150% of his base salary. Mr. Goulding received an initial make-whole payment of $600,000 under the agreement in respect of financial and other benefits forfeited as a result of his accepting employment with Allegheny.

Pursuant to his employment agreement, on February 18, 2004, Mr. Goulding received a grant of stock options to purchase 746,403 shares of AE Common Stock under the LTIP and 150,000 stock units, each representing one share of Common Stock. One-fifth of the stock options and stock units vest on each October 13 from 2004 through 2008, provided that Mr. Goulding remains employed by Allegheny on the applicable vesting dates. The stock units are payable in stock on each vesting date or such later date as Mr. Goulding has elected. If a change in control (as defined in the agreement) occurs, all of Mr. Goulding’s unvested stock options and stock units will immediately vest.

Mr. Goulding is eligible to participate in the SERP, as well as in the other employee benefit and compensation plans maintained by the Company. Solely for determining his eligibility for benefits and the amount of his benefits under the SERP, Mr. Goulding will be credited with five additional years of service on October 13, 2008 and an additional five years of service on October 13, 2013, provided he remains employed by the Company at such times. Solely for determining his eligibility for benefits under the SERP, Mr. Goulding will be deemed to have reached age 55 on the date his employment with the Company ends for any reason.

If Mr. Goulding’s employment by the Company is terminated, he will be entitled to certain salary and benefit amounts that are accrued but unpaid at the time of the termination. In addition, if the Company terminates the employment agreement other than for cause (as defined in the agreement), if the employment agreement terminates due to Mr. Goulding’s death or disability (as defined in the agreement) or if Mr. Goulding terminates the employment agreement for a specified good reason (as defined in the agreement), Mr. Goulding will be entitled to additional payments and benefits, and the vesting of his unvested stock options, stock units and other equity compensation grants will be accelerated. The amount of severance and the other benefits to which Mr. Goulding is entitled in connection with the termination of his employment, and the amount of time following his termination that his stock options will remain exercisable, varies depending upon whether the employment agreement is terminated (a) due to Mr. Goulding’s death or disability, or (b) by the Company other than for cause or by Mr. Goulding for good reason and (b) in the case of termination by the Company other than for cause or by

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Mr. Goulding for good reason, if the termination occurs following or in anticipation of a change in control. The severance and other benefits to which Mr. Goulding is entitled in each of these circumstances are more fully described in the employment agreement.

The employment agreement subjects Mr. Goulding to a non-competition obligation for one year and a non-solicitation obligation for two years following the termination of his employment and customary confidentiality obligations. Mr. Goulding is also entitled to a number of other customary benefits under the employment agreement, including indemnification rights, payment or reimbursement of temporary living and relocation expenses, vacation and reimbursement of reasonable and necessary business expenses. Additionally, the agreement entitles him to gross-up payments in the event his compensation is subject to excise tax.

Employment Agreement with Joseph H. Richardson

Joseph H. Richardson’s employment agreement dated August 6, 2003 with Allegheny and AESC has a three-year term that began on August 25, 2003, subject to successive one-year renewals. On January 1, 2006, Mr. Richardson’s agreement was amended and restated to extend the term of the agreement to August 25, 2008 and to make certain other revisions. The agreement provides for a base salary of $400,000 per year, which may be increased, but not decreased, in the sole discretion of the Board. On February 24, 2006, the Board approved a $10,000 increase in Mr. Richardson’s salary effective April 1, 2006. Mr. Richardson is eligible to receive annual incentive compensation under the AIP, with a target bonus opportunity of 50% of his base salary and a maximum bonus opportunity of 100% of his base salary.

Pursuant to his employment agreement, Mr. Richardson received a grant of stock options to purchase 200,000 shares of AE Common Stock under the LTIP and 109,926 stock units, each representing one share of Common Stock. Mr. Richardson’s employment agreement was initially amended as of February 18, 2004 to delay the grant date of the stock options from January 2, 2004 until February 18, 2004, which was five business days after receipt of SEC confirmation as to the issuance of these grants. The stock options and stock units also were issued on February 18, 2004. One-fifth of the stock options and stock units vest on each August 25 from 2004 through 2008, provided that Mr. Richardson remains employed by Allegheny on the applicable vesting dates. The stock units are payable in stock on each vesting date or such later date as Mr. Richardson has elected. If a change in control (as defined in the agreement) occurs, all of Mr. Richardson’s unvested stock options and stock units will immediately vest.

Mr. Richardson is eligible to participate in the SERP, as well as in the other employee benefit and compensation plans maintained by the Company. Solely for determining his eligibility for benefits and the amount of his benefits under the SERP, Mr. Richardson will be credited with five additional years of service on August 25, 2008 and an additional five years of service on August 25, 2013, provided he remains employed by the Company at such times. Solely for determining his eligibility for benefits under the SERP, Mr. Richardson will be deemed to have reached age 55 on the date his employment with the Company ends for any reason.

If Mr. Richardson’s employment by the Company is terminated, he will be entitled to certain salary and benefit amounts that are accrued but unpaid at the time of the termination. In addition, if the Company terminates the employment agreement other than for cause (as defined in the agreement), if the employment agreement terminates due to Mr. Richardson’s death or disability (as defined in the agreement) or if Mr. Richardson terminates the employment agreement for good reason (as defined in the agreement), following or in anticipation of a change in control, Mr. Richardson will be entitled to additional payments and benefits, and the vesting of his unvested stock options, stock units and other equity compensation grants will be accelerated. The amount of severance and the other benefits to which Mr. Richardson is entitled in connection with the termination of his employment, and the amount of time following his termination that his stock options will remain exercisable, varies depending upon whether the employment agreement is terminated (a) due to Mr. Richardson’s death or disability, or (b) by the Company other than for cause and, in the case of termination by the Company other than for cause or termination by Mr. Richardson for good reason, if the termination occurs following or in anticipation of a change in control. The severance and other benefits to which Mr. Richardson is entitled in each of these circumstances are more fully described in the employment agreement.

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The employment agreement subjects Mr. Richardson to a non-competition obligation for one year and a non-solicitation obligation for two years following the termination of his employment and customary confidentiality obligations. Mr. Richardson is also entitled to a number of other customary benefits under the employment agreement, including indemnification rights, payment or reimbursement of temporary living and relocation expenses, vacation and reimbursement of reasonable and necessary business expenses. Additionally, the agreement entitles him to gross-up payments in the event his compensation is subject to excise tax.

Compensation Committee Interlocks and Insider Participation

The members of the Management Compensation and Development Committee of the Board for the fiscal year ended December 31, 2005 were Messrs Baldwin, Freidheim, Kleisner and Sarsten. There were no interlocking directorships and no insider participation on this committee during the fiscal year ended December 31, 2005.

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ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The table below shows the number of shares of the Company’s common stock that are beneficially owned, directly or indirectly, by: (a) each of the Company’s directors and Named Executive Officers, (b) each person believed to own beneficially more than five percent of Allegheny’s outstanding common stock and (c) all of the company’s directors and executive officers as a group as of February 21, 2006.

Name (a)	Shares of Allegheny Common Stock (b)	Percent of Class
Paul J. Evanson	680,791	*
H. Furlong Baldwin	13,200	*
Eleanor Baum	34,660	*
Cyrus F. Freidheim, Jr.	10,000	*
Julia L. Johnson	5,200	*
Ted J. Kleisner	25,373	*
Steven H. Rice	30,946	*
Gunnar E. Sarsten	33,260	*
Michael H. Sutton	3,600	*
Jeffrey D. Serkes	420,502	*
Hyun Park	30,000	*
Philip L. Goulding	352,802	*
Joseph H. Richardson	82,019	*
All current directors and executive officers of Allegheny as a group (16 persons)	1,885,913	1.16

* Indicates less than one percent.

(a) The address for each stockholder listed is: c/o Allegheny Energy, Inc., 800 Cabin Hill Drive, Greensburg, Pennsylvania 15601.

(b) Includes the following options exercisable within 60 days of February 21, 2006: Mr. Evanson—600,000; Dr. Baum—23,000; Mr. Kleisner—20,000; Mr. Rice—23,000; Mr. Sarsten—23,000; Mr. Serkes—366,666; Mr. Park—30,000; Mr. Goulding—298,560; and Mr. Richardson—80,000.

Excludes 120,000 unvested options granted to Mr. Park in April 2005 and the following unvested options granted on February 18, 2004: Mr. Evanson—900,000; Mr. Serkes—183,334; Mr. Goulding—447,843; and Mr. Richardson—120,000. The unvested options held by Messrs. Evanson, Goulding and Richardson vest in equal installments annually through 2008. The unvested options held by Mr. Serkes vest in equal installments annually through 2006. The unvested options held by Mr. Park vest in equal installments annually through 2010.

Excludes 50,000 unvested stock units granted to Mr. Park in April 2005 and the following unvested stock units granted on February 18, 2004: Mr. Evanson—1,229,663; Mr. Serkes—238,265; Mr. Goulding—90,000; and Mr. Richardson—65,956. The unvested stock units held by Messrs. Evanson, Goulding, and Richardson vest in equal installments annually through 2008. The unvested units held by Mr. Serkes vest in equal installments annually through 2006. The unvested units held by Mr. Park vest in equal installments annually through 2010.

Excludes the following vested but deferred stock units: Mr. Evanson—819,776; Mr. Baldwin—3,200; Mr. Freidheim—6,400; Ms. Johnson—3,200; Mr. Kleisner—3,200; Mr. Rice—6,400; Mr. Sarsten—6,400; Mr. Sutton—4,800; Mr. Serkes—428,875; and Mr. Richardson—43,970.

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Allegheny Equity Compensation Plan Information

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders (a)	6,182,957	(b)	$	16.94	3,755,816
Equity compensation plans not approved by security holders (c)	3,006,506	(d)		N/A	1,375,840
Total	9,189,463		$	11.40	5,131,656

(a) Includes the LTIP and the Non-Employee Director Stock Plan.

(b) Includes shares granted to directors under the Non-Employee Director Stock Plan which were deferred.

(c) Includes the Stock Unit Plan.

(d) Includes unvested units awarded under the Stock Unit Plan, as well as vested units that were deferred.

For more information regarding these equity compensation plans, see “Executive Compensation” and “Compensation of Directors” above.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

AE and its various subsidiaries, including AE Supply, Monongahela, Potomac Edison, West Penn and AGC and their respective subsidiaries, may enter into various operating transactions with each other. For more information regarding these intercompany transactions, see Note 1, “Summary of Significant Accounting Policies—Intercompany Transactions,” to the Consolidated Financial Statements.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit and Other Fees

Set forth below are fees paid to PwC in respect of audit and audit-related services, and for tax services and other services, rendered in 2005 and 2004. All services provided to Allegheny by PwC require the prior review and approval of the Audit Committee.

Audit Fees

Fees and expenses for the audit of the 2005 financial statements and quarterly reviews were $5,005,362, including $1,462,426 paid in 2006. Fees and expenses for the audit of the 2004 financial statements and quarterly reviews were $8,421,065, including $2,595,000 paid in 2005.

Audit-Related Fees

Fees and expenses for audit-related services were $358,346 for 2005, including $42,700 paid in 2006. Fees and expenses for audit-related services in 2005 includes $213,075 that was related to benefit plan audits, all of which was paid directly to the trust funds for those plans. Fees and expenses for audit-related services in 2005 also includes $20,000 paid for reproduction of certain audit workpapers, $116,271 for certain agreed upon procedures and $9,000 in software license fees. Fees and expenses for audit-related services were $230,163 for 2004, including $138,500 paid in 2005. Fees and expenses for audit-related services in 2004 includes $157,180 that was related to benefit plan audits, of which $96,000 was paid directly by the trust funds for those plans. Fees and expenses for audit-related services in 2004 also includes $54,275 paid for reproduction of certain audit workpapers, $10,600 for certain agreed upon procedures and $8,108 in software license fees. Audit-related services include assurance and other additional services related to the audit of Allegheny’s financial statements and quarterly reviews.

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Tax Fees

There were no fees and expenses for tax advisory, planning and compliance services for 2004 or 2005.

All Other Fees

There were no fees and expenses for other services for 2004 or 2005.

In February 2006, Allegheny received a refund from PwC in the amount of $626,626 related to a contingent fee agreement for certain tax advisory services, which Allegheny entered into with Coopers & Lybrand (“C&L”) in 1997, prior to the merger of C&L and Price Waterhouse in 1998. PwC has notified the Audit Committee of the Board that the existence of this contingent fee arrangement was a violation of the standards for auditor independence under applicable rules. However, PwC has advised the Audit Committee that PwC’s objectivity and audit independence were not impaired by the existence of the contingent fee arrangement. As part of its required communication with the Audit Committee pursuant to Independent Standards Board Standard No. 1, PwC has confirmed to the Audit Committee that it is an independent accounting firm with respect to Allegheny, as defined under applicable auditor independence rules. The Audit Committee has discussed PwC’s independence in light of these disclosures.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1)(2) The financial statements and financial statement schedules filed as part of this Report are set forth under Item 8. Reference is made to the index on page 124.

(b) Exhibits for AE, Monongahela, Potomac Edison and AGC are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO

SECTION 15(d) OF THE EXCHANGE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED

SECURITIES PURSUANT TO SECTION 12 OF THE EXCHANGE ACT

No annual report or proxy material has been sent to security holders for:

Monongahela

Potomac Edison

AGC

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SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ALLEGHENY ENERGY, INC.
By:	/s/    PAUL J. EVANSON
	(Paul J. Evanson, Chairman, President and Chief Executive Officer)

Date:  February 28, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated.

	Signature	Title	Date
(i)	Principal Executive Officer:
	/s/    PAUL J. EVANSON         (Paul J. Evanson)	Chairman and President, Chief Executive Officer	February 28, 2006
(ii)	Principal Financial Officer:
	/s/    JEFFREY D. SERKES         (Jeffrey D. Serkes)	Senior Vice President and Chief Financial Officer	February 28, 2006
(iii)	Principal Accounting Officer:
	/s/    THOMAS R. GARDNER         (Thomas R. Gardner)	Vice President and Controller	February 28, 2006
(iv)	Directors:
	/s/    H. FURLONG BALDWIN         (H. Furlong Baldwin)	/s/    TED J. KLEISNER         (Ted J. Kleisner)
	/s/    ELEANOR BAUM         (Eleanor Baum)	/s/    STEVEN H. RICE         (Steven H. Rice)
	/s/    PAUL J. EVANSON         (Paul J. Evanson)	/s/    GUNNAR E. SARSTEN         (Gunnar E. Sarsten)	February 28, 2006
	/s/    CYRUS F. FREIDHEIM, JR.         (Cyrus F. Freidheim, Jr.)	/s/    MICHAEL H. SUTTON         (Michael H. Sutton)
	/s/    JULIA L. JOHNSON         (Julia L. Johnson)

290

SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

MONONGAHELA POWER COMPANY
By:	/s/    JOSEPH H. RICHARDSON
	(Joseph H. Richardson, President)

Date:  February 28, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

	Signature	Title	Date
(i)	Principal Executive Officer:
	/s/    PAUL J. EVANSON         (Paul J. Evanson)	Chairman and Chief Executive Officer	February 28, 2006
(ii)	Principal Financial Officer:
	/s/    JEFFREY D. SERKES         (Jeffrey D. Serkes)	Vice President and Director	February 28, 2006
(iii)	Principal Accounting Officer:
	/s/    THOMAS R. GARDNER         (Thomas R. Gardner)	Controller	February 28, 2006
(iv)	Directors:
	/s/    PAUL J. EVANSON         (Paul J. Evanson)
	/s/    JEFFREY D. SERKES         (Jeffrey D. Serkes)	/s/    JOSEPH H. RICHARDSON         (Joseph H. Richardson)	February 28, 2006

291

SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

THE POTOMAC EDISON COMPANY
By:	/s/    JOSEPH H. RICHARDSON
	(Joseph H. Richardson, President)

Date:  February 28, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

	Signature	Title	Date
(i)	Principal Executive Officer:
	/s/    PAUL J. EVANSON         (Paul J. Evanson)	Chairman and Chief Executive Officer	February 28, 2006
(ii)	Principal Financial Officer:
	/s/    JEFFREY D. SERKES         (Jeffrey D. Serkes)	Vice President and Director	February 28, 2006
(iii)	Principal Accounting Officer:
	/s/    THOMAS R. GARDNER         (Thomas R. Gardner)	Controller	February 28, 2006
(iv)	Directors:
	/s/    PAUL J. EVANSON         (Paul J. Evanson)		February 28, 2006
	/s/    JEFFREY D. SERKES         (Jeffrey D. Serkes)	/s/    JOSEPH H. RICHARDSON         (Joseph H. Richardson)	February 28, 2006

292

SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ALLEGHENY GENERATING COMPANY
By:	/s/    PAUL J. EVANSON
	(Paul J. Evanson, Chairman and Chief Executive Officer)

Date:  February 28, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

	Signature	Title	Date
(i)	Principal Executive Officer:
	/s/    PAUL J. EVANSON         (Paul J. Evanson)	Chairman and Chief Executive Officer	February 28, 2006
(ii)	Principal Financial Officer:
	/s/    JEFFREY D. SERKES         (Jeffrey D. Serkes)	Vice President and Director	February 28, 2006
(iii)	Principal Accounting Officer:
	/s/    THOMAS R. GARDNER         (Thomas R. Gardner)	Vice President and Controller	February 28, 2006
(iv)	Directors:
	/s/    PAUL J. EVANSON         (Paul J. Evanson)	/s/    JOHN P. CAMPBELL         (John P. Campbell)
	/s/    JEFFREY D. SERKES         (Jeffrey D. Serkes)		February 28, 2006

293

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in Allegheny Energy, Inc.’s Registration Statements on Form S-3 (Nos. 33-36716, 33-57027, 33-49791, 333-41638, 333-49086, 333-56786, 333-82176, 333-121083 and 333-123697) and Allegheny Energy, Inc.’s Registration Statements on Form S-8 (Nos. 333-65657, 333-31610, 33-40432, 333-113660, 333-117117 and 333-119397) of our report dated February 28, 2006 relating to the financial statements, financial statement schedules, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of control over financial reporting, which appears in this Form 10-K. We also hereby consent to the incorporation by reference in Monongahela Power Company’s Registration Statements on Form S-3 (Nos. 333-31493, 33-51301, 33-56262, 033-59131, 333-31493 and 333-38484) and The Potomac Edison Company’s Registration Statements on Form S-3 (Nos. 333-33413, 33-51305 and 33-59493) of our reports dated February 28, 2006 relating to the financial statements and financial statement schedules, which appear in this Form 10-K.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 28, 2006

294

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Energy, Inc., a Maryland corporation, do hereby constitute and appoint PAUL J. EVANSON and JEFFREY D. SERKES, and each of them, a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2005, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratifies and confirms all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

Dated:  February 28, 2006

/s/    H. FURLONG BALDWIN         (H. Furlong Baldwin)	/s/    TED J. KLEISNER         (Ted J. Kleisner)
/s/    ELEANOR BAUM         (Eleanor Baum)	/s/    STEVEN H. RICE         (Steven H. Rice)
/s/    PAUL J. EVANSON         (Paul J. Evanson)	/s/    GUNNAR E. SARSTEN         (Gunnar E. Sarsten)
/s/    CYRUS F. FREIDHEIM, JR.         (Cyrus F. Freidheim, Jr.)	/s/    MICHAEL H. SUTTON         (Michael H. Sutton)
/s/    JULIA L. JOHNSON         (Julia L. Johnson)

295

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Monongahela Power Company, an Ohio corporation, and The Potomac Edison Company, a Maryland and Virginia corporation, do hereby constitute and appoint PAUL J. EVANSON and JEFFREY D. SERKES, and each of them, a true and lawful attorney in his name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2005, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said companies, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

Dated:  February 28, 2006

/s/    PAUL J. EVANSON        

(Paul J. Evanson)

/s/    JEFFREY D. SERKES        

(Jeffrey D. Serkes)

/s/    JOSEPH H. RICHARDSON        

(Joseph H. Richardson)

296

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Generating Company, a Virginia corporation, do hereby constitute and appoint PAUL J. EVANSON and JEFFREY D. SERKES, and each of them, a true and lawful attorney in his name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2005, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

Dated:  February 28, 2006

/s/    PAUL J. EVANSON        

(Paul J. Evanson)

/s/    JEFFREY D. SERKES        

(Jeffrey D. Serkes)

/s/    JOHN P. CAMPBELL        

(John P. Campbell)

297

E-1

EXHIBIT INDEX

(Rule 601(a))

Allegheny Energy, Inc.

		Documents	Incorporation by Reference
3.1		Charter of the Company, as amended, September 16, 1997	Form 10-K of the Company (1-267), December 31, 1997, exh. 3.1
3.1a		Articles Supplementary, dated July 15, 1999 and filed July 20, 1999	Form 8-K of the Company (1-267), July 20, 1999, exh. 3.1
3.1b		Articles of Amendment, dated March 18, 2003	Form 10-K of the Company (1-267), December 31, 2002, exh. 3.1c
3.1c		Articles Supplementary to Articles of Incorporation, dated July 19, 2004	Form 10-Q of the Company (1-267), June 30, 2004, exh. 3.1
3.2		By-laws of the Company, as amended November 14, 2003 and May 13, 2004	Form S-8 of the Company (1-267), filed July 2, 2004, exh. 4
10.1		Directors’ Deferred Compensation Plan	Form 10-K of the Company (1-267), December 31, 1994, exh. 10.1
10.1	(a)	Amendment 2005-1 to Revised Plan for Deferral of Compensation of Directors, effective December 30, 2005	Form 8-K of the Company (1-267), filed January 6, 2006, exh. 10.1
10.2		Executive Compensation Plan	Form 10-K of the Company (1-267), December 31, 1996, exh. 10.2
10.4		Allegheny Energy Amended and Restated Supplemental Executive Retirement Plan	Filed herewith.
10.5		Executive Life Insurance Program and Collateral Assignment Agreement	Form 10-K of the Company (1-267), December 31, 1994, exh. 10.5
10.6		Restricted Stock Plan for Outside Directors	Form 10-K of the Company (1-267), December 31, 1998, exh. 10.7
10.7		Deferred Stock Unit Plan for Outside Directors	Form 10-K of the Company (1-267), December 31, 1997, exh. 10.8
10.8		Allegheny Energy, Inc. 2004 Non-Employee Director Stock Plan	Schedule 14A Definitive Proxy Statement of the Company (1-267), filed April 4, 2004, Annex A
10.9		Allegheny Energy, Inc. Annual Incentive Plan	Schedule 14A Definitive Proxy Statement of the Company (1-267), filed April 4, 2004, Annex B
10.10		Form of Stock Option Agreement	Form 10-K of the Company (1-267), December 31, 2004 exh. 10.12
10.11		Stock Unit Plan	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.13
10.12		Form of Stock Unit Agreement	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.14
10.13		Allegheny Energy, Inc. 1998 Long-Term Incentive Plan revised as of January 1, 2004	Form 10-Q of the Company (1-267), March 31, 2004, exh. 10.1
10.14		Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-267), December 31, 2002, exh. 10.13
10.15		Employment Contract of Chief Financial Officer	Form 10-K of the Company (1-267), December 31, 2002, exh. 10.14
10.16		Employment Contract of Vice President	Form 10-K of the Company (1-267), December 31, 2002, exh. 10.16
10.17		Employment Contract of Vice President	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.15

E-1 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Allegheny Energy, Inc.

	Documents	Incorporation by Reference
10.18	Amendment to Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.17
10.19	Amendment to Employment Contract of Chief Financial Officer	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.18
10.20	Amendment to Employment Contract of Vice President	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.20
10.21	Employment Agreement of Vice President and Controller	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.25
10.22	Employment Agreement of Vice President	Form 10-K of the Cmpany (1-267), December 31, 2004, exh. 10.26
10.23	Employment Agreement of Vice President	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.27
10.24	Indenture, dated as of July 26, 2000, between Allegheny Energy, Inc. and Banc One Trust Company, N.A., as Trustee	Form 8-K of the Company (1-267), filed August 17, 2000, exh. 4.1
10.25	Registration Rights Agreement, dated July 24, 2003, by and among Allegheny Energy, Inc., Allegheny Capital Trust I, Perry Principals, LLC, and additional Purchasers	Form 8-K of the Company (1-267), filed August 1, 2003, exh. 4.1
10.26	Indenture, dated as of July 24, 2003, between Allegheny Energy, Inc. and Wilmington Trust Company, as Trustee	Form 8-K of the Company (1-267), filed August 1, 2003, exh. 4.2
10.27	Amended and Restated Declaration of Trust of Allegheny Capital Trust I among Allegheny Energy, Inc., Wilmington Trust Company, and The Regular Trustees Named Herein	Form 8-K of the Company (1-267), filed August 1, 2003, exh. 4.3
10.28	$300,000,000 Credit Agreement, dated as of March 8, 2004, among Allegheny Energy, Inc., The Initial Lenders and Initial Issuing Bank Named Herein and CitiCorp North America, Inc.	Form 10-Q of the Company (1-267), March 31, 2004, exh. 10.1
10.29	Acquisition Agreement, dated as of August 4, 2004, by and between Monongahela Power Company and Mountaineer Gas Holdings Limited Partnership	Form 10-Q of the Company (1-267), June 30, 2004, exh. 10.1
10.30	Purchase Agreement, dated September 27, 2004, between Allegheny Energy Supply Company, LLC, Grant Peaking Power, LLC and ArcLight Energy Partners Fund II, L.P.	Form 10-Q of the Company (1-267), June 30, 2004, exh. 10.2
10.31	Stock Purchase and ICPA Assignment Agreement, dated as of May 17, 2004, between Allegheny Energy Inc., Allegheny Energy Supply Company, LLC and Buckeye Power Generating, LLC	Form 10-Q of the Company (1-267), June 30, 2004, exh. 10.3
10.32	Registration Rights Agreement, dated as of October 5, 2004	Form 8-K of the Company (1-267), filed October 8, 2004, exh. 10.1
10.33	Amendment No. 3, dated as of March 18, 2005, to Credit Agreement dated as of March 3, 2004, among Allegheny Energy, Inc., the Lenders, the Issuing Banks and Citicorp North America, Inc., as Administrative Agent.	Form 10-Q of the Company (1-267), March 31, 2005, exh. 10.1

E-1 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Allegheny Energy, Inc.

		Documents	Incorporation by Reference
10.34	*	Professional Services Agreement, dated September 19, 2005, among Allegheny Energy, Inc., EDS Information Systems, LLC and Electronic Data Systems Corporation	Form 10-Q of the Company (1-267), September 30, 2005, exh. 10.1
10.35		Supplemental Indenture, dated as of April 22, 2005, between Allegheny Energy, Inc. and Wilmington Trust Company.	Form 8-K of the Company (1-267), filed April 26, 2005, exh. 4.1
10.36		Amendment No. 4, dated as of May 17, 2005 to Credit Agreement dated as of March 3, 2004, among Allegheny Energy, Inc., the Lenders, the Issuing Banks and Citicorp North America, Inc., as Administrative Agent.	Form 8-K of the Company (1-267), filed May 31, 2005, exh. 10.1
10.37		$700,000,000 Credit Agreement, dated as of June 16, 2005, by and among Allegheny Energy, Inc., Allegheny Energy Supply Company, LLC, borrowers, and the Initial Lenders, Initial Issuing Bank and Citicorp North America, Inc., as Administrative Agent.	Form 8-K of the Company (1-267), filed June 22, 2005, exh. 10.1
10.38		$1.069 billion Credit Agreement, dated as of July 21, 2005, by and among Allegheny Energy Supply Company, LLC and certain of its subsidiaries, borrowers, and the Lenders, Citicorp North America, Inc., as Administrative Agent, and Citibank, N.A., as Collateral Agent and Intercreditor Agent.	Form 8-K of the Company (1-267), filed July 27, 2005, exh. 10-1
10.39		Amendment Agreement No. 3 and Consent, dated as of July 21, 2005, by and among Allegheny Energy Supply Company, LLC and certain of its subsidiaries as Grantors, Citicorp North America, Inc., as Administrative Agent and Citibank, NA, as Collateral Agent and Depository Bank	Form 8-K of the Company (1-267), filed July 27, 2005, exh. 10.2
10.40		Employment Agreement of Vice President and General Counsel	Form 8-K of the Company (1-267), filed April 8, 2005, exh. 10.1
10.41		Employment Agreement of Vice President, Human Resources	Form 8-K of the Company (1-267), filed January 6, 2006, exh. 10.1
10.42		Employment Agreement of Vice President	Form 8-K of the Company (1-267), filed January 6, 2006, exh. 10.2
10.43		Employment Agreement of Vice President	Form 8-K of the Company (1-267), filed January 6, 2006, exh. 10.3
10.44		Subsidiaries’ Indentures described below
12		Computation of ratio of earnings to fixed charges	Filed herewith
14		Code of Business Conduct and Ethics	Form 10-K of the Company (1-267), December 31, 2004, exh. 14

* Confidential treatment has been requested from the commission for portions of this document.

E-1 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Allegheny Energy, Inc.

	Documents	Incorporation by Reference
21	Subsidiaries of AE:
	Name of Company	State of Organization
	Allegheny Energy Service Corporation—100%	Maryland
	Allegheny Ventures, Inc.—100%	Delaware
	Monongahela Power Company—100%	Ohio
	The Potomac Edison Company—100%	Maryland and Virginia
	West Penn Power Company—100%	Pennsylvania
	Allegheny Energy Supply Company, LLC—98.025%	Delaware
	Allegheny Energy Supply Hunlock Creek, LLC—100%	Delaware
	Green Valley Hydro, LLC—100%	Virginia
	Ohio Valley Electric Corporation—3.50%	Ohio
23	Consent of Independent Registered Public Accounting Firm	See page 294 herein.
24	Powers of Attorney	See page 295 herein.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Committee of Chief Risk Officers Organizational Independence and Governance Working Group White Paper, dated November 19, 2002	Form 10-K of the Company (1-267), December 31, 2002, exh. 99.1

E-2

EXHIBIT INDEX

(Rule 601(a))

Monongahela Power Company

	Documents	Incorporation by Reference
3.1	Charter of the Company, as amended	Form 10-Q of the Company (1-5164), September 1995, exh. (a)(3)(i)
3.1(a)	Certificate of Amendment to Charter, effective November 16, 2005	Filed herewith
3.2	Code of Regulations, as amended April 14, 2003	Form 10-K of the Company (1-5164), December 31, 2002, exh. 3.2
4.1	Indenture, dated as of August 1, 1945, and certain Supplemental Indentures of the Company defining rights of security holders*	S 2-5819, exh. 7(f) S 2-8881, exh. 7(b) S 2-10548, exh. 4(b) S 2-14763, exh. 2(b)(i); Forms 8-K of the Company (1-268-2), dated May 23, 1995, November 14, 1997 and October 2, 2001; Amendment No. 1 to Form S-4, dated January 19, 2005, exh. 4.3; Form 8-K of the Company (1-268-2), filed October 20, 2005, exh. 99.1
4.2	Indenture, dated as of May 15, 1995, between Monongahela Power Company and The Bank of New York, as Trustee	Form 8-K of the Company, filed June 21, 1995, exh. 4(a)
10.1	Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-5164), December 31, 2002, exh. 10.3
10.2	Employment Contract of Chief Financial Officer	Form 10-K of the Company (1-5164), December 31, 2002, exh. 10.4
10.3	Employment Contract of President	Form 10-K of the Company (1-5164), December 31, 2002, exh. 10.5
10.4	Amendment to Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-5164), December 31, 2003, exh. 10.8
10.5	Amendment to Employment Contract of Chief Financial Officer	Form 10-K of the Company (1-5164), December 31, 2003, exh. 10.9
10.6	Amendment to Employment Contract of President	Form 10-K of the Company (1-5164), December 31, 2003, exh. 10.10
10.7	Amendment to Employment Contract of President	Form 10-K of the Company (1-5164), December 31, 2003, exh. 10.11
10.8	Employment Agreement of Vice President and Controller	Form 10-K of the Company (1-5164), December 31, 2004, exh. 10.13
10.9	Employment Agreement of Vice President	Form 10-K of the Company (1-5164), December 31, 2004, exh. 10.14
10.10	Employment Agreement of Vice President	Form 10-K of the Company (1-5164), December 31, 2004, exh. 10.15
10.11	Registration Rights Agreement, made and entered into as of June 9, 2004, by Monongahela Power Company, and Citigroup Global Markets Inc. and Scotia Capital (USA) Inc., as representatives of the Initial Purchasers	Form S-4, dated January 19, 2005, exh. 4.3
10.12	Acquisition Agreement, dated as of August 4, 2004, by and between Monongahela Power Company and Mountaineer Gas Holdings Limited Partnership	Form 10-Q of the Company (1-5164), September 30, 2004, exh. 10.1
10.13	Employment Agreement of Vice President and General Counsel	Form 8-K of AE, filed April 8, 2005, exh. 10.1

E-2 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Monongahela Power Company

	Documents	Incorporation by Reference
10.14	Employment Agreement of Vice President, Human Resources	Form 8-K of AE, filed January 6, 2006, exh. 10.1
10.15	Employment Agreement of Vice President	Form 8-K of AE, filed January 6, 2006, exh. 10.2
10.16	Employment Agreement of Vice President	Form 8-K of AE, filed January 6, 2006, exh. 10.3
12	Computation of ratio of earnings to fixed charges	Filed herewith
21	Subsidiaries of Monongahela
	Name of Company	State of Organization
	Allegheny Generating Company—22.9716%	Virginia
	Allegheny Pittsburgh Coal Company—25%	Pennsylvania
23	Consent of Independent Registered Public Accounting Firm	See page 294 herein.
24	Powers of Attorney	See page 296 herein.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Committee of Chief Risk Officers Organizational Independence and Governance Working Group White Paper, dated November 19, 2002	Form 10-K of the Company (1-5164), December 31, 2002, exh. 99.1

* There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the SEC on its request with copies of such Supplemental Indentures.

E-3

EXHIBIT INDEX

(Rule 601(a))

The Potomac Edison Company

	Documents	Incorporation by Reference
3.1	Charter of the Company, as amended	Form 8-K of the Company (1-3376-2), April 27, 2000
3.2	By-laws of the Company, as amended February 7, 2005	Form 10-Q of the Company (1-3376-2), March 31, 2005, exh. 3.1
4.1	Indenture, dated as of October 1, 1944, and certain Supplemental Indentures of the Company defining rights of security holders*	S 2-5473, exh. 7(b); Form S-3, 33-51305, exh. 4(d) Forms 8-K of the Company (1-3376-2), dated May 12, 1995, May 17, 1995, November 14, 1997, November 24, 2004 and August 17, 2005 exh. 99.1
4.2	Indenture, dated as of May 31, 1995, between The Potomac Edison Company and The Bank of New York, as Trustee	Form 8-K of the Company, filed June 30, 1995, exh. 4(a)
10.1	Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-3376-2), December 31, 2002, exh. 10.3
10.2	Employment Contract of Chief Financial Officer	Form 10-K of the Company (1-3376-2), December 31, 2002, exh. 10.4
10.3	Employment Contract of President	Form 10-K of the Company (1-3376-2), December 31, 2002, exh. 10.5
10.4	Amendment to Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-3376-2), December 31, 2003, exh. 10.8
10.5	Amendment to Employment Contract of Chief Financial Officer	Form 10-K of the Company (1-3376-2), December 31, 2003, exh. 10.9
10.6	Amendment to Employment Contract of President	Form 10-K of the Company (1-3376-2), December 31, 2003, exh. 10.10
10.7	Amendment to Employment Contract of President	Form 10-K of the Company (1-3376-2), December 31, 2003, exh. 10.11
10.8	Employment Agreement of Vice President and Controller	Form 10-K of the Company (1-3376-2), December 31, 2004, exh. 10.13
10.9	Employment Agreement of Vice President	Form 10-K of the Company (1-3376-2), December 31, 2004, exh. 10.14
10.10	Employment Agreement of Vice President	Form 10-K of the Company (1-3376-2), December 31, 2004, exh. 10.15
10.11	Registration Rights Agreement, dated as of November 22, 2004.	Form 8-K of the Company (1-3376-2) filed November 24, 2004, exh. 99.2
10.12	Registration Rights Agreement, dated as of August 15, 2005, between The Potomac Edison Company and Credit Suisse First Boston LLC	Form 8-K of the Company (1-3376-2) filed August 17, 2005, exh. 99.2
10.13	Employment Agreement of Vice President and General Counsel	Form 8-K of AE, filed April 8, 2005, exh. 10.1
10.14	Employment Agreement of Vice President, Human Resources	Form 8-K of AE, filed January 6, 2006, exh. 10.1
10.15	Employment Agreement of Vice President	Form 8-K of AE, filed January 6, 2006, exh. 10.2
10.16	Employment Agreement of Vice President	Form 8-K of AE, filed January 6, 2006, exh. 10.3
12	Computation of ratio of earnings to fixed charges	Filed herewith

E-3 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

The Potomac Edison Company

	Documents	Incorporation by Reference
21	Subsidiaries of Potomac Edison
	Name of Company	State of Organization
	Allegheny Pittsburgh Coal Company—25%	Pennsylvania
	PE Transferring Agent, LLC—100%	Delaware
23	Consent of Independent Registered Public Accounting Firm	See page 294 herein.
24	Powers of Attorney	See page 296 herein.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Committee of Chief Risk Officers Organizational Independence and Governance Working Group White Paper, dated November 19, 2002	Form 10-K of the Company (1-3376-2), December 31, 2002 exh. 99.1

* There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the SEC on its request with copies of such Supplemental Indentures.

E-4

EXHIBIT INDEX

(Rule 601(a))

Allegheny Generating Company

	Documents	Incorporation by Reference
3.1(a)	Charter of the Company, as amended*
3.1(b)	Certificate of Amendment to Charter, effective July 14, 1989**
3.2	By-laws of the Company, as amended February 7, 2005	Form 10-Q of the Company (0-14688), March 31, 2005, exh. 3.1
4	Indenture, dated as of December 1, 1986, and Supplemental Indenture, dated as of December 15, 1988, of the Company defining rights of security holders***
10.1	APS Power Agreement-Bath County Pumped Storage Project, as amended, dated as of August 14, 1981, among Monongahela Power Company, Allegheny Energy Supply Company, LLC, The Potomac Edison Company and Allegheny Generating Company****
10.2	Amendment No. 8, effective date January 1, 1999, to the APS Power Agreement-Bath County Pumped Storage Project	Form 10-K of the Company (0-14688), December 31, 1998
10.3	Operating Agreement, dated as of June 17, 1981, among Virginia Electric and Power Company, Allegheny Generating Company, Monongahela Power Company, Allegheny Energy Supply Company, LLC and The Potomac Edison Company****
10.4	Equity Agreement, dated June 17, 1981, between and among Allegheny Generating Company, Monongahela Power Company, Allegheny Energy Supply Company, LLC, and The Potomac Edison Company****
10.5	United States of America Before The Federal Energy Regulatory Commission, Allegheny Generating Company, Docket No. ER84-504-000, Settlement Agreement effective October 1, 1985****
10.6	Employment Contract of Chief Executive Officer	Form 10-K of AE (333-72498), December 31, 2002, exh. 10.13
10.7	Employment Contract of Chief Financial Officer	Form 10-K of AE (333-72498), December 31, 2002, exh. 10.14
10.8	Employment Contract of Vice President	Form 10-K of AE (333-72498), December 31, 2002, exh. 10.16
10.9	Amendment to Employment Contract of Chief Executive Officer	Form 10-K of the Company, December 31, 2003, exh. 10.10
10.10	Amendment to Employment Contract of Chief Financial Officer	Form 10-K of the Company, December 31, 2003, exh. 10.11
10.11	Employment Agreement of Vice President and Controller	Form 10-K of the Company (0-14688), December 31, 2004, exh. 10.13
10.12	Employment Agreement of Vice President	Form 10-K of the Company (0-14688), December 31, 2004, exh. 10.14
10.13	Employment Agreement of Vice President	Form 10-K of the Company (0-14688), December 31, 2004, exh. 10.15
10.14	Employment Agreement of Vice President and General Counsel	Form 8-K of AE filed April 8, 2005, exh. 10.1
10.15	Employment Agreement of Vice President, Human Resources	Form 8-K of AE filed January 6, 2006, exh. 10.1

E-4 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Allegheny Generating Company

	Documents	Incorporation by Reference
10.16	Employment Agreement of Vice President	Form 8-K of AE, filed January 6, 2006, exh. 10.2
10.17	Employment Agreement of Vice President	Form 8-K of AE, filed January 6, 2006, exh. 10.3
12	Computation of ratio of earnings to fixed charges	Filed herewith
24	Powers of Attorney	See page 297 herein.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Committee of Chief Risk Officers Organizational Independence and Governance Working Group White Paper, dated November 19, 2002	Form 10-K of the Company (0-14688), December 31, 2002 exh. 99.1

* Incorporated by reference to the designated exhibit to AGC’s registration statement on Form 10, File No. 0-14688.

** Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a).

*** Incorporated by reference to Forms 8-K of the Company (0-14688) for December 1986, exh. 4(A), and December 1988, exh. 4.1.

**** Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a).

EX-12

EXHIBIT 12

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES

	For Years Ended December 31,
	2005		2004		2003			2002		2001
($ in thousands)
Earnings:
Income from continuing operations	$	66,354	$	37,981	$	40,558		$	32,678	$	48,035
Exclude amounts reflected in line above:
Income tax expense		33,428		34,835		20,652			15,679		27,351
Income from unconsolidated equity investee		—		—		(62	)		—		—
Add fixed charges (see below)		28,777		33,336		32,155			34,522		37,754
Total Earnings (as defined)	$	128,559	$	106,152	$	93,303		$	82,879	$	113,140
Fixed charges:
Interest expensed and capitalized	$	27,926	$	32,654	$	31,391		$	33,157	$	35,372
Estimated interest component of rental expense		851		682		764			1,365		2,382
Total Fixed Charges (as defined)	$	28,777	$	33,336	$	32,155		$	34,522	$	37,754
Ratio of Earnings to Fixed Charges		4.47x		3.18x		2.90x			2.40x		3.00x

EX-31.1

Exhibit 31.1

CERTIFICATION

I, PAUL J. EVANSON, certify that:

1. I have reviewed this annual report on Form 10-K of THE POTOMAC EDISON COMPANY.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/    PAUL J. EVANSON
Date: February 28, 2006	Paul J. Evanson Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, JEFFREY D. SERKES, certify that:

1. I have reviewed this annual report on Form 10-K of THE POTOMAC EDISON COMPANY.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/    JEFFREY D. SERKES
Date: February 28, 2006	Jeffrey D. Serkes Principal Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION

Pursuant to 18 U.S.C. § 1350, the undersigned officer of THE POTOMAC EDISON COMPANY (the “Company”), hereby certifies, to such officer’s knowledge, that the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/    PAUL J. EVANSON
February 28, 2006	Paul J. Evanson Principal Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

Pursuant to 18 U.S.C. § 1350, the undersigned officer of THE POTOMAC EDISON COMPANY (the “Company”), hereby certifies, to such officer’s knowledge, that the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/    JEFFREY D. SERKES
February 28, 2006	Jeffrey D. Serkes Principal Financial Officer