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, 2010

OR

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

Commission file number 1-00267

ALLEGHENY ENERGY, INC.

(Name of Registrant)

Maryland	13-5531602
(State of Incorporation)	(IRS Employer Identification Number)
800 Cabin Hill Drive, Greensburg, Pennsylvania
	15601
(Address of Principal Executive Offices)	(Zip Code)

(724) 837-3000

(Telephone Number)

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

Title of each class	Name of each exchange on which registered
Common Stock, par value $1.25 per share	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    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 registrant’s 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.    ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a small reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one).

Large accelerated filer   x	Accelerated filer	¨
Non-accelerated filer     ¨	Smaller reporting company	¨
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the outstanding common stock, other than shares held by persons who may be deemed affiliates of the registrant, as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $3,440,110,307. As of December 31, 2010, 169,973,542 shares of the common stock, par value of $1.25 per share, of the registrant were outstanding.

GLOSSARY

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

AE	Allegheny Energy, Inc., a diversified utility holding company
AESC	Allegheny Energy Service Corporation, a subsidiary of AE
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC	Allegheny Generating Company, a generation subsidiary of AE Supply and Monongahela
Allegheny	Allegheny Energy, Inc., together with its consolidated subsidiaries
Distribution Companies	Monongahela, Potomac Edison and West Penn, which collectively do business as Allegheny Power
Monongahela	Monongahela Power Company, a regulated subsidiary of AE
PATH, LLC	Potomac-Appalachian Transmission Highline, LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc.
PATH-Allegheny	PATH Allegheny Transmission Company, LLC
PATH-WV	PATH West Virginia Transmission Company, LLC
Potomac Edison	The Potomac Edison Company, a regulated subsidiary of AE
TrAIL Company	Trans-Allegheny Interstate Line Company
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:

Clean Air Act	Clean Air Act of 1970
CO2	Carbon dioxide
EPA	United States Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FERC	Federal Energy Regulatory Commission, an independent commission within the United States Department of Energy
FirstEnergy	FirstEnergy Corp.
FPA	Federal Power Act
FTRs	Financial Transmission Rights
GAAP	Generally accepted accounting principles used in the United States of America
kW	Kilowatt, which is equal to 1,000 watts
kWh	Kilowatt-hour, a unit of electric energy equivalent to one kW operating for one hour
Maryland PSC	Maryland Public Service Commission
MW	Megawatt, which is equal to 1,000,000 watts
MWh	Megawatt-hour, a unit of electric energy equivalent to one MW operating for one hour
NERC	North American Electric Reliability Corporation
NOX	Nitrogen Oxide
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
PATH	Potomac-Appalachian Transmission Highline
Pennsylvania PUC	Pennsylvania Public Utility Commission
PJM	PJM Interconnection, L.L.C., a regional transmission organization
PLR	Provider-of-last-resort
PURPA	Public Utility Regulatory Policies Act of 1978
RPM	Reliability Pricing Model, which is PJM’s capacity market
RTEP	Regional Transmission Expansion Plan, the process by which PJM identifies transmission system upgrades and enhancements to provide for the operational, economic and reliability requirements of PJM customers.
RTO	Regional Transmission Organization
Scrubbers	Flue-gas desulfurization equipment
SEC	Securities and Exchange Commission
SO2	Sulfur dioxide
SOS	Standard Offer Service
T&D	Transmission and distribution
TrAIL	Trans-Allegheny Interstate Line
Virginia SCC	Virginia State Corporate Commission
West Virginia PSC	Public Service Commission of West Virginia

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CONTENTS

Item 1.	Business	1
	Overview	1
	Special Note Regarding Forward-Looking Statements	8
	Allegheny’s Sales And Revenues	10
	Capital Expenditures	11
	Electric Facilities	12
	Fuel, Power And Resource Supply	16
	Competition	18
	Regulatory Framework Affecting Allegheny	19
	Environmental Matters	32
	Employees	39
Item 1A.	Risk Factors	40
Item 1B.	Unresolved Staff Comments	52
Item 2.	Properties	53
Item 3.	Legal Proceedings	53
Item 4.	Reserved	56
Item 5.	Market For The Registrant’s Common Equity and Related Stockholder Matters	57
Item 6.	Selected Financial Data	59
Item 7.	Management’s Discussion And Analysis Of Financial Condition And Results Of Operations	60
Item 7A.	Quantitative And Qualitative Disclosures About Market Risk	96
Item 8.	Financial Statements And Supplementary Data	97
Item 9.	Changes In And Disagreements With Accountants On Accounting And Financial Disclosure	182
Item 9A.	Controls And Procedures	182
Item 9B.	Other Information	183
Item 10.	Directors And Executive Officers	188
Item 11.	Executive Compensation	193
Item 12.	Security Ownership Of Certain Beneficial Owners And Management And Related Stockholder Matters	222
Item 13.	Certain Relationships And Related Transactions	224
Item 14.	Principal Accountant Fees And Services	226
Item 15.	Exhibits And Financial Statement Schedules	227
Signatures		228

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PART I

ITEM 1.     BUSINESS

OVERVIEW

Allegheny is an integrated energy business. Allegheny owns and operates electric generation facilities primarily in Pennsylvania, West Virginia and Maryland. Additionally, Allegheny owns transmission assets in Pennsylvania, West Virginia, Maryland and Virginia and provides distribution services to customers in Pennsylvania, West Virginia and Maryland. 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’s operations are organized into two business segments:

• The Merchant Generation segment includes Allegheny’s merchant power generation operations, including the operations of AE Supply and AGC.

• The Regulated Operations segment includes all of Allegheny’s regulated operations, including its electric T&D operations and transmission expansion projects, as well as Monongahela’s power generation operations.

See consolidated financial statement Note 1, “Business, Basis of Presentation and Significant Accounting Policies,” and Note 13, “Segment Information,” to Allegheny’s consolidated financial statements.

Proposed Merger with FirstEnergy

On February 10, 2010, AE entered into an Agreement and Plan of Merger (as amended on June 4, 2010, the “Merger Agreement”) with FirstEnergy and Element Merger Sub, Inc. (“Merger Sub”), a wholly owned subsidiary of FirstEnergy, pursuant to which, and subject to certain conditions, Merger Sub will merge with and into AE (the “Merger”), with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FirstEnergy.

AE stockholders and FirstEnergy shareholders approved various proposals related to the Merger in separate shareholder meetings on September 14, 2010. The Virginia SCC approved the proposed Merger on September 9, 2010, the West Virginia PSC and FERC approved the Merger on December 16, 2010, and the Maryland PSC approved the Merger, subject to certain conditions, on January 18, 2011. Additionally, on January 7, 2011, the U.S. Department of Justice (the “DOJ”) notified AE and FirstEnergy that it had completed its review of the proposed Merger pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and closed its investigation.

Pursuant to the Merger Agreement, completion of the Merger remains subject to, among other customary closing conditions, approval by the Pennsylvania PUC. In October 2010, AE and FirstEnergy filed with the Pennsylvania PUC a comprehensive settlement that addresses the issues raised by a majority of the parties to the merger proceedings in Pennsylvania. AE and FirstEnergy currently anticipate completing the Merger in the first quarter of 2011. See “Regulatory Framework Affecting Allegheny,” “Risk Factors” and Note 2, “Merger Agreement,” to Allegheny’s consolidated financial statements.

The Merchant Generation Segment

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

• AE Supply was formed in Delaware in 1999. AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities. As of

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December 31, 2010, AE Supply owned or contractually controlled 7,015 MWs of generation capacity. See “Electric Facilities.”

AE Supply markets its electric generation capacity to various customers and markets, including certain of its affiliates, and uses both derivative and nonderivative contracts to manage its portfolio of contracts. AE Supply’s portfolio management and trading activities involve the use of physical commodity inventories and a variety of instruments, such as forward contracts, futures contracts, swap agreements and similar instruments. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated financial statement Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to Allegheny’s consolidated financial statements.

AE Supply was contractually obligated to provide West Penn with most of the power necessary to meet its PLR obligations in Pennsylvania through December 31, 2010, when West Penn’s generation caps in Pennsylvania expired, and has contracts of varying length with West Penn to serve a portion of its load beyond January 1, 2011. In addition, AE Supply has contracts with Potomac Edison to supply portions of the power necessary to serve Potomac Edison’s Maryland customer load that range in length from three to 29 months. AE Supply had total operating revenues of $1.8 billion in 2010.

• AGC was incorporated in Virginia in 1981. As of December 31, 2010, AGC was owned approximately 59% by AE Supply and approximately 41% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC had total operating revenues of $64.2 million in 2010. See “Electric Facilities.”

All of Allegheny’s generation facilities are located within PJM’s competitive wholesale market. AE Supply and Monongahela sell into the PJM market the power that they generate and purchase from the PJM market the power necessary to meet their contractual obligations to supply power. See “Fuel, Power and Resource Supply” and “Regulatory Framework Affecting Allegheny.”

During 2010, the Merchant Generation segment had total operating revenues of $1.8 billion and net income of $163.1 million. As of December 31, 2010, the Merchant Generation segment held approximately $4.5 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated financial statement Note 13, “Segment Information,” to Allegheny’s consolidated financial statements.

The Regulated Operations Segment

The principal companies and operations in Allegheny’s Regulated Operations segment include the following:

• The Distribution Companies include Monongahela, 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. In April 2002, the Distribution Companies transferred functional control over their transmission systems to PJM. 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.

• Monongahela was incorporated in Ohio in 1924. It conducts an electric T&D business that serves approximately 385,500 customers in northern West Virginia in a service area of approximately 13,000 square miles with a population of approximately 784,900. Monongahela sold 10.7 million MWhs of electricity to retail customers in 2010.

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Monongahela also owns generation assets, which are included in the Regulated Operations segment. As of December 31, 2010, Monongahela owned or contractually controlled 2,737 MWs of generation capacity. Monongahela’s generation capacity supplies its electric T&D business. In addition, Monongahela is contractually obligated to provide Potomac Edison with the power that it needs to meet its load obligations in West Virginia. Monongahela had total operating revenues of $907.6 million in 2010. See “Electric Facilities.”

• 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 and Maryland. On June 1, 2010, Potomac Edison sold its electric distribution operations (while retaining its transmission operations) in Virginia (the “Virginia distribution business”) to Rappahannock Electric Cooperative (“Rappahannock”) and Shenandoah Valley Electric Cooperative (“Shenandoah” and, together with Rappahannock, the “Co-Ops”) for cash proceeds of approximately $317 million. Effective December 31, 2010, Potomac Edison purchased Shenandoah’s West Virginia distribution assets for approximately $14.5 million, subject to certain post-closing adjustments. Potomac Edison now serves approximately 383,700 customers in a service area of about 5,182 square miles with a population of approximately 850,600. Potomac Edison had total operating revenues of $914.9 million and sold 11.7 million MWhs of electricity to retail customers in 2010. See “Regulatory Framework Affecting Allegheny,” “Risk Factors” and Note 4, “Sale of Virginia Distribution Business,” to Allegheny’s consolidated financial statements.

• 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 716,100 customers in a service area of about 10,400 square miles with a population of approximately 1.5 million. West Penn had total operating revenues of $1.6 billion and sold 20 million MWhs of electricity to retail customers in 2010.

• TrAIL Company was incorporated in Maryland and Virginia in 2006. In June 2006, PJM, which manages a regional planning process for transmission expansion, approved an RTEP designed to maintain the reliability of the transmission grid in the mid-Atlantic region. The transmission expansion plan includes TrAIL, a new 500 kV transmission line that will extend from southwestern Pennsylvania through West Virginia to a point of interconnection with Virginia Electric and Power Company, a subsidiary of Dominion Resources, in northern Virginia. PJM designated Allegheny to construct the portion of the line that will be located in the Distribution Companies’ PJM zone. TrAIL Company was formed in connection with the management and financing of transmission expansion projects, including this project (the “TrAIL Project”), and will build, own and operate the new transmission line. TrAIL Company currently expects that the new line will be completed and placed in service no later than June 2011. TrAIL Company had total operating revenues of $137 million in 2010. See “Capital Expenditures” and “Regulatory Framework Affecting Allegheny.”

• PATH, LLC was formed in Delaware in 2007 following PJM authorization to construct PATH through its RTEP process. As currently proposed, PATH is a new, 765 kV transmission line that will extend from a substation owned by American Electric Power Company (“AEP”) near St. Albans, West Virginia, to a new substation near New Market, Maryland. PATH, LLC, which was formed in connection with the management and financing of this project (the “PATH Project”), is a series limited liability company. The “West Virginia Series” is owned equally by Allegheny and a subsidiary of AEP. The “Allegheny Series” is 100% owned by Allegheny. Each Series will, through one or more operating subsidiaries, build, own and operate a portion of the line. Construction of the line remains subject to siting approval by the relevant state utility commissions, among other matters. See “Capital Expenditures,” “Risk Factors” and “Regulatory Framework Affecting Allegheny.”

During 2010, the Regulated Operations segment had operating revenues of $3.4 billion and net income of $247.7 million. As of December 31, 2010, the Regulated Operations segment held approximately $7.5 billion of

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identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 13, “Segment Information,” to Allegheny’s consolidated financial statements.

Shared Services

AESC was incorporated in Maryland in 1963 and is a service company for Allegheny. AESC employs substantially all of the Allegheny personnel who provide services to AE and its subsidiaries, including among others, AE Supply, AGC, the Distribution Companies, TrAIL Company, PATH, LLC and their respective subsidiaries. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had 4,211 employees as of December 31, 2010.

Certain Recent Initiatives and Developments

During 2010, Allegheny’s strategy has been to focus on its core businesses, which management believes is enabling Allegheny to take advantage of its regional presence, operational expertise and knowledge of its markets to add shareholder value, while pursuing completion of its proposed Merger with FirstEnergy. Significant recent initiatives and developments include, among others:

• Proposed Merger with FirstEnergy. AE entered into its Merger Agreement with FirstEnergy and Merger Sub on February 10, 2010. Pursuant to the Merger Agreement, and subject to certain conditions, Merger Sub will merge with and into AE, with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FirstEnergy.

Throughout 2010, Allegheny and First Energy worked to obtain the approval of their respective shareholders and the federal and state regulatory approvals necessary for completion of the Merger. AE’s stockholders and FirstEnergy’s shareholders approved various proposals related to the Merger in separate shareholder meetings held on September 14, 2010. On December 16, 2010, FERC approved the proposed Merger, and on January 7, 2010, the DOJ notified AE and FirstEnergy that it had completed its review of the proposed Merger pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and closed its investigation. The Merger was approved by the Virginia SCC on September 9, 2010, by the West Virginia PSC on December 16, 2010 and by the Maryland PSC, subject to certain conditions, on January 18, 2011. Completion of the proposed Merger remains subject to approval by the Pennsylvania PUC, with which AE and FirstEnergy have filed a comprehensive settlement that addresses the issues raised by the majority of the parties to the merger proceedings. AE currently anticipates completing the Merger in the first quarter of 2011. See “Regulatory Framework Affecting Allegheny,” “Risk Factors” and Note 2, “Merger Agreement,” to Allegheny’s consolidated financial statements.

• Transmission Expansion. During 2010, Allegheny completed construction of its new transmission operations center in West Virginia while continuing construction of TrAIL, which is nearing completion and is expected to be placed into service no later than June 2011. Primary jurisdiction for authorization to construct the PATH Project lies with the state public utility commission in the states in which the lines are proposed to be located. Applications for authorization to construct the PATH Project are pending in Maryland and Virginia, where decisions are expected in the third quarter of 2011, and in West Virginia, where a decision is expected in February 2012. See “Capital Expenditures,” “Regulatory Framework Affecting Allegheny,” “Risk Factors,” and Note 6, “Transmission Expansion,” to Allegheny’s consolidated financial statements.

• Sale of Virginia Distribution Business. On June 1, 2010, Potomac Edison completed the sale of its electric distribution business in Virginia to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative for cash proceeds of approximately $317 million. See “Regulatory Matters Affecting Allegheny” and Note 4, “Sale of Virginia Distribution Business,” to Allegheny’s consolidated financial statements.

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• West Virginia Base Rate Increase.  In June 2010, the West Virginia PSC approved a $40 million annualized base rate increase effective June 29, 2010 for Monongahela and Potomac Edison, with an additional $20 million annualized base rate increase effective in January 2011. The approved settlement also provides for: a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period; a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.

• Liquidity Enhancement.  During 2010, Allegheny refinanced or repaid certain existing debt, while working to enhance the liquidity of certain of it operating subsidiaries.

Specifically, in January 2010, TrAIL Company refinanced its existing construction loan through the issuance of $450 million aggregate principal amount of 4.0% senior unsecured notes due 2015 and obtained a new, $350 million unsecured revolving credit facility that matures in 2013.

Also in January 2010, Monongahela repaid its $110 million in outstanding 7.36% medium-term notes, and in July 2010, AE Supply redeemed all $150.5 million of its outstanding 7.80% medium term notes due in 2011. In May 2010, AE entered into a new $250 million senior unsecured revolving credit facility that replaced its previous $376 million revolving credit facility, which was scheduled to mature in May 2011. Also in 2010, West Penn, Potomac Edison and AGC obtained new three-year senior unsecured revolving credit facilities for $200 million, $150 million and $50 million, respectively, in addition to the $1 billion three-year senior unsecured revolving credit facility and $110 million three-year, senior unsecured revolving credit facility that AE Supply and Monongahela obtained, respectively in 2009.

In addition to these transactions, Allegheny continues to take other steps, such as managing and controlling operations and maintenance expense and otherwise prudently managing cash, to maintain and improve its liquidity position. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and Note 9, “Capitalization and Debt,” to Allegheny’s consolidated financial statements.

• Environmental Compliance and Risk Management.  Allegheny continues its work 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.

During the latter part of 2009, Allegheny completed a significant, multi-year effort to install Scrubbers at its Fort Martin and Hatfield’s Ferry generating facilities. Now in-service, the Scrubbers will reduce overall SO₂ emissions at these two facilities by more than 95%. In addition to this initiative, Allegheny completed the elimination of a partial Scrubber bypass at its Pleasants generating facility in 2007 and is currently evaluating pollution control projects at other facilities. Although applicable environmental regulations and initiatives, including but not limited to air and water quality issues and climate change concerns, continue to present Allegheny with significant challenges, all of Allegheny’s supercritical coal generating units are scrubbed and a significant amount of SO₂ and mercury emissions have been eliminated. See “Risk Factors,” “Capital Expenditures” and “Environmental Matters.”

• Energy Efficiency and Conservation.  Through its Watt Watchers program, Allegheny has implemented a number of initiatives to encourage energy efficiency and conservation among its customers, in addition to its long-standing portfolio of existing energy conservation initiatives.

During 2010, Allegheny continued to pursue initiatives in response to Pennsylvania’s Act 129 and Maryland’s EmPOWER Maryland program, both of which establish demand-side reduction goals and have required, among other things, that affected utilities file with the relevant state utility commissions specific plans describing the demand-side management programs that they propose to implement in order to reach those goals, as well as separate plans for the implementation of advanced, or “smart,” metering. During 2009, the Maryland PSC approved and provided for cost recovery with respect to Potomac Edison’s proposed demand-side management programs in Maryland, and the Pennsylvania

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PUC largely approved West Penn’s proposed portfolio of energy efficiency and conservation programs. In both Maryland and Pennsylvania, Allegheny’s proposed advanced infrastructure and metering proposals remain subject to regulatory review. See “Regulatory Matters Affecting Allegheny.”

• Transition to Market-Based Rates.  Each of the states in Allegheny’s service territory, other than West Virginia, has, to some extent, taken steps to deregulate its electric utility industry, although Virginia has essentially reversed deregulation plans. Pennsylvania and Maryland instituted customer choice. Generation rate caps for West Penn’s retail customers in Pennsylvania expired at the end of 2010, and in 2009, West Penn began to conduct auctions to procure a portion of its generation needs to serve its Pennsylvania customers beginning January 1, 2011 pursuant to its default service plan as approved by the Pennsylvania PUC. West Penn has procured 80% of the generation supply needed to serve its residential customers in 2011, over 90% of the generation supply needed to serve its small and medium non-residential customers in 2011 and 100% of the generation supply needed to serve its largest non-residential customers who select the fixed price default service provider option in 2011.

In Maryland, residential customers who did not opt out of Potomac Edison’s Maryland PSC-approved transition plan began paying a surcharge in June 2007 that, with the expiration of residential rate caps and the move to market-based rates on January 1, 2009, converted to a credit on customers’ bills, such that funds collected via the surcharge in 2007 and 2008 were returned to customers to mitigate the effect of the rate cap expiration until December 2010. Potomac Edison conducts rolling auctions to procure its power supply for its Maryland customers, and AE Supply is serving a portion of Potomac Edison’s Maryland customers pursuant to contracts that range in length from three to 29 months that were awarded to AE Supply as a result of the auction process. Suppliers that are not affiliated with Potomac Edison also were awarded contracts for portions of Potomac Edison’s Maryland load. See “Competition,” “Regulatory Matters Affecting Allegheny,” “Risk Factors” and “Rates and Regulation,” to Allegheny’s consolidated financial statements.

• Customer Satisfaction.  Allegheny considers customer satisfaction to be a high performance metric and strives to maintain and improve customer satisfaction. Allegheny continues to see high levels of satisfaction among its customers. For example, a leading independent survey firm has ranked Allegheny first in commercial and industrial satisfaction in the northeastern United States for the last six consecutive years, and another firm ranked Allegheny in the top third nationally for residential customer satisfaction.

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Where You Can Find More Information

AE files or furnishes Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and other information with or to the SEC. You may read and copy any document that AE files with the SEC at the SEC’s public reference room at 100 F Street, N.E., Room 1580, 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 files with or furnishes 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. 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. Forward-looking statements involve estimates, expectations and projections and, as a result, are subject to risks and uncertainties. Forward-looking statements often may be identified by the use of 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. However, the absence of these or similar words does not mean that any particular statement is not forward-looking. Forward-looking statements herein may relate to, among other matters:

• regulatory issues, including but not limited to environmental regulation and state rate regulation;

• financing plans;

• market demand and prices for energy, capacity, coal and natural gas;

• the cost and availability of raw materials, including coal, and Allegheny’s ability to enter into, modify and enforce long-term fuel purchase agreements;

• power supply contracts;

• results of litigation;

• results of operations;

• internal controls and procedures;

• capital expenditures;

• status and condition of plants and equipment;

• changes in technology and their effects on the competitiveness of Allegheny’s generation facilities;

• work stoppages by Allegheny’s unionized employees;

• capacity purchase commitments; and

• Allegheny’s proposed Merger with FirstEnergy.

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:

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

• plant performance and unplanned outages;

• volatility and changes in the price and demand for energy and capacity and changes in the value of FTRs;

• volatility and changes in the price of coal, natural gas and other energy-related commodities, as well as transportation costs;

• Allegheny’s ability to enter into, modify and enforce long term fuel purchase agreements;

• the effectiveness of Allegheny’s risk management policies and procedures;

• the ability and willingness of counterparties to satisfy their financial and performance obligations;

• changes in the weather and other natural phenomena;

• changes in Allegheny’s requirements for, and the availability and price of, emission allowances;

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

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• changes in market rules, including changes to PJM’s participant rules and tariffs, and defaults by other market participants;

• the loss of any significant customers or suppliers;

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

• the impact of government-mandated energy consumption initiatives, as well as general trends in resource conservation;

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

• the reliability of Allegheny’s own system and its ongoing compliance with NERC reliability standards;

• environmental regulations;

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

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

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

• the likelihood and timing of the completion of the proposed Merger with FirstEnergy, the terms and conditions of remaining required regulatory approvals of the proposed Merger, the impact of the proposed Merger on Allegheny’s employees and potential diversion of management’s time and attention from ongoing business during this time period;

• difficulties in obtaining regulatory authorizations on a timely basis;

• disruptions in the financial markets and changes in access to capital markets;

• the availability of credit;

• actions of rating agencies;

• inflationary or deflationary trends and interest rate trends;

• general economic and business conditions, including the effects of the current recession; and

• other risks, including the effects of global instability, terrorism and war.

For a more detailed discussion of certain risk factors affecting Allegheny’s risk profile, see “Risk Factors.”

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ALLEGHENY’S SALES AND REVENUES

Merchant Generation

The Merchant Generation segment generated 32,051 million kWhs and 26,004 million kWhs of electricity in 2010 and 2009, respectively. The segment’s revenues were composed of the following:

Revenues (in millions)	2010		2009
PJM energy revenue	$	1,240.2	$	936.5
PJM capacity revenue		403.6		356.2
Power hedge revenues		80.4		213.5
Other		34.4		102.4
Total operating revenues	$	1,758.6	$	1,608.6

Regulated Operations

The Regulated Operations segment sold 42,389 million kWhs and 42,040 million kWhs of electricity to retail customers in 2010 and 2009, respectively. The segment’s operating revenues were composed of the following:

Revenues (in millions)	2010			2009
Retail electric:
Generation and ancillary	$	2,500.3		$	2,280.0
Transmission		118.4			118.6
Distribution		698.9			661.7
Total retail electric		3,317.6			3,060.3
Transmission services and bulk power:
PJM revenue, net		(151.6	)		(198.8	)
Warrior Run generation revenue		64.5			52.7
Transmission and other		171.7			100.1
Total transmission Services and bulk power		84.6			(46.0	)
Other		38.1			36.9
Total operating revenues	$	3,440.3		$	3,051.2

For more information regarding each segment’s revenues and operating results, as well as intersegment revenues and costs eliminated in Allegheny’s consolidated financial statements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 13, “Segment Information,” to Allegheny’s consolidated financial statements.

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CAPITAL EXPENDITURES

Actual capital expenditures for 2010 and estimated capital expenditures for 2011 and 2012 are shown on a cash basis in the following table. The scope, amounts and timing of capital projects and related expenditures are subject to continuing review and adjustment, and actual capital expenditures may vary from these estimates.

	Actual		Projected
(in millions)	2010		2011		2012
Transmission and distribution:
TrAIL and TrAIL Company projects (a)	$	510.7	$	123.5	$	46.9
PATH (b)		23.9		33.6		456.9
Smart meter procurement and installation (c)		16.4		12.0		4.9
Other transmission and distribution		218.0		315.7		377.6
Total transmission and distribution		769.0		484.8		886.3
Environmental:
Fort Martin Scrubbers		16.1		—		—
Hatfield Scrubbers		16.1		—		—
Other environmental		71.8		115.4		217.0
Total environmental		104.0		115.4		217.0
Generation projects, excluding environmental projects included above		81.7		121.6		72.7
Other		4.3		—		—
Total capital expenditures	$	959.0	$	721.8	$	1,176.0

(a) TrAIL has a target completion date of June 2011 and an estimated cost, excluding AFUDC, of approximately $990 million. TrAIL Company is also engaged in other transmission projects.

(b) Allegheny’s share of the estimated cost of the PATH Project is approximately $1.4 billion. Actual 2010 includes approximately $8 million in capital expenditures related to Allegheny’s portion of the West Virginia Series of PATH, LLC and approximately $16 million in capital expenditures related to PATH-Allegheny.

(c) Consists of expenditures related to Allegheny’s procurement and installation of smart meters to comply with Pennsylvania’s Act 129. See “Regulatory Framework Affecting Allegheny” for additional information, including West Penn’s current plans to decelerate its previous smart meter deployment schedule.

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ELECTRIC FACILITIES

Generation Capacity

Allegheny’s owned or controlled generation capacity, other than the capacity owned and controlled by Monongahela, is included in the Merchant Generation segment. Monongahela’s generation is included in the Regulated Operations segment.

Nominal Maximum Operational Generation Capacity

Stations	Units		Total MW		Merchant Generation Segment (MW)		Regulated Operations Segment (MW)		Commencement Dates (a)
Supercritical Coal Fired (Steam):
Harrison (Haywood, WV)		3		1,983		1,576		407		1972-74
Hatfield’s Ferry (Masontown, PA)		3		1,710		1,710				1969-71
Pleasants (Willow Island, WV)		2		1,300		1,200		100		1979-80
Fort Martin (Maidsville, WV)		2		1,107				1,107		1967-68
Other Coal Fired (Steam):
Armstrong (Adrian, PA)		2		356		356				1958-59
Albright (Albright, WV)		3		292				292		1952-54
Mitchell (Courtney, PA)		1		288		288				1963
Willow Island (Willow Island, WV)		2		243				243		1949-60
Rivesville (Rivesville, WV)		2		126				126		1943-51
R. Paul Smith (Williamsport, MD)		2		116		116				1947-58
OVEC (Cheshire, OH) (Madison, IN) (b)		11		78		67		11
Pumped-Storage and Hydro:
Bath County (Warm Springs, VA) (c)		6		1,109		658		451		1985; 2001
Lake Lynn (Lake Lynn, PA) (d)		4		52		52				1926
Allegheny Lock & Dam 5 (Freeport, PA) (e)		2		6		6				1987
Allegheny Lock & Dam 6 (Freeport, PA) (e)		2		7		7				1989
AE Supply/Green Valley Hydro (f)		21		6		6				Various
Gas Fired:
AE Nos. 3, 4 & 5 (Springdale, PA)		3		540		540				2003
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)		1		44		44				2000
Oil-Fired (Steam):
Mitchell (Courtney, PA)		1		82		82				1949
Total Capacity				9,752		7,015		2,737

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

(b) The amount attributed to OVEC represents capacity entitlement through AE’s ownership of OVEC shares. AE holds a 3.5% equity stake in, and is a sponsoring company of, OVEC. OVEC supplies power to its sponsoring companies under an intercompany power agreement.

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

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

(e) AE Supply purchased hydroelectric generation facilities at Allegheny Lock and Dam Nos. 5 & 6 in December 2009. See Note 15, “Purchase of Hydroelectric Generation Facilities,” to Allegheny’s consolidated financial statements.

(f) The licenses for AE Supply hydroelectric facilities Dam No. 4 and Dam No. 5, located in West Virginia and Maryland, will expire in November 2024. The licenses for the Green Valley, Shenandoah, Warren, Luray and Newport facilities located in Virginia run through 2024.

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

PURPA Capacity

The following table shows generation capacity, in addition to that reflected in the table above, that is 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, although 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. The capacity purchases reflected in this table are reflected in the results of the Regulated Operations segment.

	PURPA Capacity (MW)
PURPA Stations (a)	Project Total		Monongahela		Potomac Edison		West Penn		Contract Termination Date
Coal Fired (Steam)
AES Warrior Run (Cumberland, MD) (b)		180				180				2030
AES Beaver Valley (Monaca, PA)		125						125		2016
Grant Town (Grant Town, WV)		80		80						2036
West Virginia University (Morgantown, WV)		50		50						2027
Hydro:
Hannibal Lock and Dam (New Martinsville, WV)		31		31						2034
Total PURPA Capacity		466		161		180		125

(a) AE Supply purchased hydroelectric generating facilities at Allegheny Lock and Dam Nos. 5 & 6, previously PURPA stations with generating capacity of 13 MW, in December 2009.

(b) As required under the terms of a Maryland restructuring settlement, Potomac Edison offers the 180 MW output of the AES Warrior Run project to the wholesale market 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.

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Transmission and Distribution Facilities

The following table sets forth the existing miles of T&D lines and the number of substations of the Distribution Companies and AGC as of December 31, 2010:

	Underground		Above- Ground		Total Miles		Total Miles Consisting of 500-Kilovolt (kV) Lines		Number of Transmission and Distribution Substations
Monongahela		950		22,397		23,347		251		241
Potomac Edison (a)		4,625		13,607		18,232		174		200
West Penn		3,100		24,257		27,357		276		505
AGC (b)		—		87		87		87		1
Total		8,675		60,348		69,023		788		947

(a) Reflects the June 2010 sale of Potomac Edison’s Virginia distribution business.

(b) 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 36 lower-voltage interconnections with neighboring utility systems.

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15

FUEL, POWER AND RESOURCE SUPPLY

Coal Supply

Allegheny primarily uses Northern Appalachian coal at its coal-fired generating facilities. Most of Allegheny’s coal purchase agreements contain specified prices and include price adjustment provisions related to changes in specified cost indices, as well as to specific events, such as changes in regulations that affect the coal industry.

Developments and operational factors affecting Allegheny’s coal suppliers, including increased costs, transportation constraints, safety issues and operational difficulties, may have negative effects on coal supplier performance. See “Risk Factors.”

Merchant Generation.  AE Supply consumed approximately 12.4 million tons of coal in 2010 at an average price of approximately $57.56 per ton delivered. Allegheny purchased these fuels primarily from mines in Pennsylvania, West Virginia and Ohio. However, Allegheny also purchases coal from other regions, and blends coal from the Powder River Basin with eastern bituminous coal at one of its generating facilities.

Historically, AE Supply has purchased a majority of its coal from a limited number of suppliers. Of AE Supply’s coal purchases in 2010, 60% came from subsidiaries of three companies, the largest of which represented 25% of the total tons purchased.

As of February 1, 2011, AE Supply had commitments for the delivery of more than 97% of the coal that AE Supply expects to consume in 2011. Excluding volumes that are priced annually based on market conditions, AE Supply also had commitments for the delivery of approximately 67% of its anticipated coal needs for 2012 and for approximately 58%, 56% and 40% of its anticipated coal needs for 2013, 2014 and 2015, respectively.

Regulated Operations.  Monongahela consumed approximately 4.5 million tons of coal in 2010 at an average price of approximately $63.23 per ton delivered. Monongahela purchased these fuels primarily from mines in Pennsylvania, West Virginia and Ohio. However, Monongahela also purchases coal from other regions, and blends coal from the Powder River Basin with eastern bituminous coal at certain of its generating facilities.

Historically, Monongahela has purchased a majority of its coal from a limited number of suppliers. Of Monongahela’s coal purchases in 2010, 62% came from subsidiaries of three companies, the largest of which represented 27% of the total tons purchased.

As of February 1, 2011, Monongahela had commitments for the delivery of more than 98% of the coal that Monongahela expects to consume in 2011. Excluding volumes that are priced annually based on market conditions, Monongahela also had commitments for the delivery of approximately 66% of its anticipated coal needs for 2012 and for approximately 49%, 51% and 21% of its anticipated coal needs for 2013, 2014 and 2015, respectively.

Natural Gas Supply

AE Supply purchases natural gas to supply its natural gas-fired generation facilities. In 2010, AE Supply purchased its natural gas requirements principally in the spot market.

AE Supply has an agreement under a FERC-approved tariff with Kern River Gas Transmission Company for the firm transportation of 45,122 decatherms of natural gas per day from Opal, Wyoming to southern California. The transportation agreement runs through April 30, 2018. AE Supply continues to manage this obligation by monitoring market conditions and pursuing commercial transactions that will enable it to maximize the value of the agreement.

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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, do not produce their own power. 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. Monongahela transferred the portion of its generation assets dedicated to its previously-owned Ohio service territory to AE Supply in 2001. Effective as of January 1, 2007, Monongahela and AE Supply completed an intra-company transfer of assets that realigned generation ownership and contractual obligations within the Allegheny system (the “Asset Swap”). See “Regulatory Framework Affecting Allegheny.”

Pennsylvania instituted retail customer choice in 1996 and transitioned to market-based, rather than cost-based pricing for generation. West Penn is the PLR for those Pennsylvania customers who do not choose an alternate supplier or whose alternate supplier does not deliver or who choose to return to West Penn service. West Penn’s generation rates were capped at various levels through the end of its transition period on December 31, 2010. Prior to the end of the transition period, AE Supply was contractually obligated to provide West Penn with most of the power necessary to meet its PLR obligations in Pennsylvania. In July 2008, the Pennsylvania PUC approved West Penn’s proposed power procurement plan, pursuant to which West Penn has begun to procure its post-transition period power requirements through a combination of competitively bid contracts and spot market purchases. West Penn has procured 80% of the generation supply needed to serve its residential customers in 2011, over 90% of the generation supply needed to serve its small and medium non-residential customers in 2011, and 100% of the generation supply needed to serve its largest non-residential customers who select the fixed-price default service provider option in 2011.

Prior to January 1, 2007, AE Supply sold power to Potomac Edison to serve customers in Potomac Edison’s West Virginia service territory. In connection with the Asset Swap, Monongahela assumed the obligation to supply power to Potomac Edison to meet its West Virginia load obligations through 2027. Monongahela sells the power that it generates from its West Virginia jurisdictional assets into the PJM market and purchases from the PJM market the power necessary to meet its West Virginia jurisdictional customer load and contractual obligations to provide power, including its obligations to supply power to Potomac Edison.

AE Supply serves a portion of Potomac Edison’s Maryland customers pursuant to contracts that range in length from three to 29 months. These contracts were awarded to AE Supply as a result of a competitive bidding process in Maryland. Suppliers that are not affiliated with Potomac Edison also were awarded contracts for portions of Potomac Edison’s Maryland load pursuant to the competitive bidding process. In Maryland, Potomac Edison conducts rolling auctions to procure its power supply.

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COMPETITION

Each of the states in Allegheny’s service territory, other than West Virginia has, to some extent, taken steps to deregulate its electric utility industry. Pennsylvania and Maryland instituted customer choice and have transitioned to market-based, rather than cost-based pricing for generation. Virginia undertook to deregulate the provision of generation services beginning in 1999, but subsequent legislation resulted in the re-regulation of these services in January 2009 for most customers. Potomac Edison sold its Virginia distribution business in June 2010, as a result of which, Allegheny no longer has retail customers in Virginia.

In April 2009, West Penn began to conduct auctions to procure a portion of its generation needs to serve its Pennsylvania customers beginning January 1, 2011 pursuant to its default service plan as approved by the Pennsylvania PUC. West Penn has procured 80% of the generation supply needed to serve its residential customers in 2011, over 90% of the generation supply needed to serve its small and medium non-residential customers in 2011 and 100% of the generation supply needed to serve its largest non-residential customers who select the fixed price default service provider option in 2011.

AE Supply is serving a portion of Potomac Edison’s Maryland customers pursuant to contracts that range in length from three to 29 months. These contracts were awarded to AE Supply as a result of competitive bidding processes in Maryland. Suppliers that are not affiliated with Potomac Edison also were awarded contracts for portions of Potomac Edison’s Maryland load pursuant to the competitive bidding process. In Maryland, Potomac Edison conducts rolling auctions to procure its power supply. In Virginia, AE Supply had contracts to serve a majority of the customer load in Potomac Edison’s former distribution service territory for the term June 1, 2009 through June 30, 2011 that it acquired as a result of a competitive solicitation. With Potomac Edison’s sale of its Virginia distribution business, these contracts were assigned to Old Dominion Electric Cooperative, a Virginia utility aggregation cooperative, on behalf of the new jurisdictional owners. See “Regulatory Framework Affecting Allegheny,” “Risk Factors” and Note 5, “Rates and Regulation,” to Allegheny’s consolidated financial statements.

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REGULATORY FRAMEWORK AFFECTING ALLEGHENY

The interstate transmission services and wholesale power sales of the Distribution Companies, TrAIL Company, PATH, LLC, AE Supply and AGC are regulated by FERC under the FPA. The Distribution Companies’ local distribution service and sales at the retail level are subject to state regulation. In addition, Allegheny is subject to numerous other local, state and federal laws, regulations and rules. See “Risk Factors.”

Federal Regulation and Rate Matters

FERC, Competition and RTOs

Allegheny’s generation and transmission businesses are significantly influenced by the actions of FERC through policies, regulations and orders issued pursuant to the FPA. The FPA gives FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales and transmission of electricity in interstate commerce. Entities, such as the Distribution Companies, TrAIL Company, the operating subsidiaries of PATH, LLC, AE Supply and AGC, that sell electricity at wholesale or own or operate transmission facilities are subject to FERC jurisdiction and must file their rates, terms and conditions for such sales or services with FERC. Rates for wholesale sales of electricity may be either cost-based or market-based. Rates for use of transmission facilities are determined on a cost basis.

FERC’s authority under the FPA, as it pertains to Allegheny’s generation and transmission businesses, also includes, but is not limited to: licensing of hydroelectric projects; transmission interconnections with other electric facilities; transfers of public utility property; mergers, acquisitions and consolidation of public utility systems and companies; issuance of certain securities and assumption of certain liabilities; accounting and methods of depreciation; transmission reliability; siting of certain transmission facilities; allocation of transmission rights; relationships between holding companies and their public utility affiliates; availability of books and records; and holding of a director or officer position at more than one public utility or specified company.

FERC’s policies, regulations and orders encourage competition among wholesale sellers of electricity. To support competition, FERC requires public utilities that own transmission facilities to make such facilities available on a non-discriminatory, open-access basis and to comply with standards of conduct that prevent transmission-owning utilities from giving their affiliated sellers of electricity preferential access to the transmission system and transmission information. To further competition, FERC encourages transmission-owning utilities to participate in regional transmission organizations (“RTOs”) such as PJM, by transferring functional control over their transmission facilities to RTOs.

All of Allegheny’s generation assets and power supply obligations are located within the PJM market, and PJM maintains functional control over the transmission facilities owned by the Distribution Companies and TrAIL Company. PJM operates a competitive wholesale electricity market and coordinates the movement of wholesale electricity 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. PJM is also responsible for developing and implementing the RTEP for the PJM region to ensure reliability of the electric grid and promote market efficiency. In addition, PJM determines the requirements for, and manages the process of, interconnecting new and expanded generation facilities to the grid. Changes in the PJM tariff, operating agreement, policies and/or market rules could adversely affect Allegheny’s financial results. See “Risk Factors.”

Transmission Rate Design.  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 (“Midwest ISO”) 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

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regional rate proposals, concluding that neither the rate design proposals nor the existing PJM rate design had been shown to be just and reasonable. FERC ordered the continuation of the existing PJM zonal “license plate” rate design and the implementation of a transition charge for these regions during a 16-month transition period commencing on December 1, 2004 and ending on March 31, 2006. On May 21, 2010, FERC denied all requests for rehearing with regard to transmission rate design within the PJM region. A petition for review of this order and the underlying orders has been filed with the United States Court of Appeals for the District of Columbia Circuit. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

During the now-expired transition period, the Distribution Companies were both payers and payees of transition charges. Following an evidentiary hearing, an administrative law judge issued an initial decision finding the methodologies used to develop the transition charges to be deficient. On May 21, 2010, FERC issued an order on the initial decision, which reversed in part and affirmed in part the initial decision. On August 19, 2010, the Distribution Companies and other PJM transmission owners filed tariff sheets with FERC to reflect certain adjustments in the transition charges directed by the May 21, 2010 order. Several parties have requested rehearing of the May 21, 2010 order on the initial decision and have protested the August 19, 2010 filing. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

In April 2007, FERC issued an order addressing transmission rate design within the PJM region. In the order, FERC directed the continuation of the zonal “license plate” rate design for all existing transmission facilities within the PJM region, the allocation of costs of new, centrally-planned transmission facilities operating at or above 500 kV on a region-wide “postage stamp” or “socialized” basis, and the development of a detailed “beneficiary pays” methodology for the allocation of costs of new transmission facilities below 500 kV. Subsequently, FERC approved a detailed “beneficiary pays” methodology developed through settlement discussions among several parties to the underlying FERC proceedings. On August 6, 2009, the U. S. Court of Appeals for the Seventh Circuit remanded this decision to FERC for further justification with regard to the allocation of costs for new 500 kV and above transmission facilities but denied petitions for review relating to FERC’s decision with regard to the pricing of existing transmission facilities. On January 21, 2010, FERC issued an order establishing a paper hearing in response to the Seventh Circuit’s remand. On April 13, 2010, PJM submitted to FERC information required by the order. The Distribution Companies submitted comments in response to the information provided by PJM on May 28, 2010. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

Under the zonal “license plate” rate design for existing transmission facilities, costs associated with such facilities are allocated on a load ratio share basis to load serving entities, such as local distribution utilities, located within the transmission owner’s PJM transmission zone. As a result of this rate design, the load serving entity does not pay for the cost of transmission facilities located in other PJM transmission zones even if the load serving entity engages in transactions that rely on transmission facilities located in other zones. The region-wide “postage stamp” or “socialized” rate design for new, centrally-planned transmission facilities operating at or above 500 kV results in charging all load serving entities within the PJM region a uniform rate based on the aggregated costs of such transmission facilities within the PJM region irrespective of whether the transmission service provided to the load serving entity requires the actual use of such facilities. For the “beneficiary pays” methodology, the costs of new facilities under 500 kV are allocated to load serving entities based on a methodology that considers several factors but is not premised upon the proximity of the load serving entity to the new facilities or the zone in which the new facilities are located.

In January 2008, FERC accepted a compliance filing submitted by certain PJM and Midwest ISO transmission owners establishing the transmission pricing methodology for transactions involving transmission service originating in the PJM region or the Midwest ISO region and terminating in the other region. The methodology maintains the existing rate design for such transactions under which PJM and Midwest ISO treat transactions that source in one region and sink in the other region the same as transactions that source and sink entirely in one of the regions. These inter-regional transactions are assessed only the applicable zonal charge of

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the zone in which the transaction sinks and no charge is assessed in the zone of the region where the transaction originates. Judicial review of FERC’s order in this matter is pending. Allegheny cannot predict the outcome of these proceedings or whether they will have a material impact on its business or financial position.

Wholesale Markets.  In August 2005, PJM filed at FERC to replace its capacity market with a new Reliability Pricing Model, or “RPM,” to address reliability concerns. On April 20, 2006, FERC issued an initial order that found PJM’s capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that needed to be analyzed further before it could determine whether the RPM is a just and reasonable capacity market process. FERC ordered the implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies joined in a settlement agreement that was filed with FERC on September 29, 2006. The settlement agreement created a locational capacity market in PJM, in which PJM procures needed capacity resources through auctions held three years in advance at prices and in quantities determined by an administratively established demand curve. Under the settlement agreement, capacity needs in PJM are met either through purchases made in the proposed auctions or through commitments by load serving entities (“LSEs”) to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which began with the 2007-2008 PJM planning year. Base year capacity auctions were held in April, July and October of 2007, in January and May of 2008 and May of 2009. On June 25, 2007 and again on November 11, 2007, FERC issued orders denying pending requests for rehearing of the December 22, 2006 order and affirming its acceptance of the RPM settlement agreement. Several parties have appealed FERC’s orders approving the RPM settlement, and those appeals are currently pending at the United States Court of Appeals for the District of Columbia Circuit. On May 30, 2008, several parties naming themselves the “RPM Buyers” filed a complaint at FERC seeking a retroactive reduction in the RPM clearing prices for several RPM auctions that have already been conducted. On September 19, 2008, FERC issued an order denying the RPM Buyers’ complaint. In June 2009, FERC denied requests for rehearing of the September 19, 2008 order. The Maryland PSC and New Jersey Board of Public Utilities appealed FERC’s order denying the RPM Buyers’ complaint to the United States Court of Appeals for the District of Columbia Circuit, which denied the petition for review on February 8, 2011.

PJM Calculation Error.  In March 2010, the Midwest ISO filed two complaints at FERC against PJM relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and the Midwest ISO since April 2005. The Midwest ISO claimed that this error resulted in PJM underpaying the Midwest ISO by approximately $130 million over the time period in question. Additionally, the Midwest ISO alleged that PJM did not properly trigger market-to-market settlements between PJM and the Midwest ISO during times when it was required to do so, which the Midwest ISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and Monongahela may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to the Midwest ISO complaints and PJM filed a related complaint at FERC against the Midwest ISO claiming that the Midwest ISO improperly called for market-to-market settlements several times during the same time period covered by the two Midwest ISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues in the dispute. The Offer of Settlement calls for the withdrawal of all pending complaints with no payments being made by any parties. Initial comments on the Offer of Settlement were filed at FERC on January 24, 2011.

Reliability Standards.  FERC has the authority to oversee the establishment and enforcement of mandatory reliability standards designed to assure the reliable operation of the bulk power system. FERC certified NERC as the Electric Reliability Organization responsible for developing and enforcing continent-wide reliability standards. NERC has established, and FERC has approved, reliability standards that impose certain operating, record-keeping and reporting requirements on the Distribution Companies, TrAIL Company, PATH, LLC, AE Supply and AGC.

While NERC is charged with establishing and enforcing appropriate reliability standards, it has delegated their day-to-day implementation and enforcement to eight regional oversight entities, including ReliabilityFirst Corporation (“ReliabilityFirst”). These regional oversight entities are responsible for developing regional reliability

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standards that are consistent with NERC’s standards. Each regional entity has its own compliance program designed to monitor, assess and enforce compliance with the applicable reliability standards through compliance audits, self-reporting and exception reporting mechanisms, self certifications, compliance violation investigations, periodic data submissions and complaint processes. Allegheny is a member of ReliabilityFirst, participates in the NERC and ReliabilityFirst stakeholder processes and monitors and manages its operations in response to the ongoing development, implementation and enforcement of relevant reliability standards. Allegheny has been, and will continue to be, subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirst is currently conducting certain violation investigations with regard to matters of compliance by Allegheny. The results of these investigations have not had, and are not expected to have, any material impact on Allegheny’s operations or the results thereof. See “Risk Factors.”

Transmission Expansion

TrAIL Project.  TrAIL is a new, 500kV transmission line currently under construction that will extend from southwest Pennsylvania through West Virginia and into northern Virginia. TrAIL is scheduled to be completed and placed in service no later than June 2011.

PATH Project.  The PATH Project is comprised of a 765 kV transmission line that is proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of PATH in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. If after further analysis PJM determines that the PATH Project is not required by June 2015 to address potential NERC reliability violations, it may delay the required in-service date for PATH to a later date or indefinitely, or it may suspend or cancel the project. Construction of the PATH Project remains subject to permitting and various state regulatory approvals.

Allegheny and a subsidiary of AEP formed PATH, LLC to facilitate the construction of the PATH Project. PATH, LLC submitted a filing to FERC under Section 205 of the FPA in December 2007 to implement a formula rate tariff effective March 1, 2008. The filing also included a request for certain incentive rate treatments. In February 2008, FERC issued an order setting the cost of service formula rate to calculate annual revenue requirements for the project and granting the following incentives:

• a return on equity of 14.3%;

• a return on CWIP;

• recovery of prudently incurred start-up business and administrative costs incurred prior to the time the rates go into effect; and

• recovery of prudently incurred development and construction costs if the PATH Project is abandoned as a result of factors beyond the control of PATH, LLC.

In December 2008, PATH, LLC submitted to FERC a settlement of the formula rate and protocols with the active parties that resolves all issues set for hearing. The return on equity was not included in the settlement because it was authorized by the February 2008 order and not set for hearing. On November 19, 2010, FERC approved the settlement, set the base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its operating results. See “Risk Factors.”

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PURPA

The Public Utility Regulatory Policies Act of 1978 (“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, although, as a result of changes in the FPA arising out of the Energy Policy Act, 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.

For 2010, the Distribution Companies committed to purchase 466 MWs of qualifying PURPA capacity, and PURPA expense pursuant to these contracts totaled approximately $240.8 million. The average cost to the Distribution Companies of these power purchases was 7.15 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.

State Rate Regulation

Pennsylvania

Pennsylvania’s Electricity Generation Customer Choice and Competition Act (the “Customer Choice Act”), which was enacted in 1996, 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 (the “1998 Restructuring Settlement”) approved by the Pennsylvania PUC, West Penn transferred its generation assets to AE Supply. West Penn retained its T&D assets. Under the 1998 Restructuring Settlement, West Penn is the default provider for those customers who do not choose an alternate supplier, whose alternate supplier does not deliver, or who have chosen to return to West Penn service. West Penn’s generation rates were capped at various levels through the end of its transition period on December 31, 2010. West Penn’s T&D assets are subject to traditional regulated utility ratemaking (i.e., cost-based rates).

Merger.  On May 14, 2010, West Penn and TrAIL Company filed a joint application with FirstEnergy requesting authorization for a change in control of West Penn and TrAIL Company as a result of the proposed Merger. Pennsylvania laws impose no statutory timeframe for the Pennsylvania PUC’s consideration of the merger application, but the Pennsylvania PUC is expected to complete its review in sufficient time to meet the anticipated Merger closing schedule in the first quarter of 2011.

On October 22, 2010, AE and FirstEnergy filed a comprehensive settlement with the Pennsylvania PUC that addresses the issues raised by 18 parties to the merger proceedings in Pennsylvania. The settlement includes certain commitments that will apply if the proposed Merger is completed, including additional commitments related to employment levels, including a five-year commitment to maintain at least 800 jobs in Greensburg and Westmoreland County, Pennsylvania for the first year after the Merger closes, 675 jobs for the following 12 months, 650 jobs for the next year, and an average of 600 jobs over the next two years, as well as nearly $11 million in distribution rate credits for West Penn customers, a distribution rate freeze for FirstEnergy’s current Pennsylvania utility customers and support for renewable and sustainable energy and customer choice. On December 14, 2010, the Administrative Law Judges who heard the case issued an Initial Decision approving the settlement and authorizing the Merger. The Initial Decision is subject to review and approval or modification by the Pennsylvania PUC.

Default Service Regulations.  In May 2007, the Pennsylvania PUC entered a Final Rulemaking Order (the “May 2007 Order”) promulgating regulations defining the obligations of electric distribution companies (“EDCs”), such as West Penn, to provide generation default service to retail electric customers who do not or cannot choose service from a licensed electric generation supplier (“EGS”) at the conclusion of the EDCs’ restructuring transition periods. West Penn’s transition period ended for the majority of its customers on December 31, 2010, when its generation rate caps expired.

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The regulations promulgated by the May 2007 Order provide that the incumbent EDC will be the default service provider (“DSP”) in its service territory, although the Pennsylvania PUC may reassign the default service obligation to one or more alternative DSPs when necessary for the accommodation, safety and convenience of the public. The DSP was required to file a default service plan not later than 12 months prior to the end of the applicable generation rate cap. The default service plan must identify the DSP’s generation supply acquisition strategy and include a rate design plan to recover all reasonable costs of default service. The default service plan must be designed to acquire generation supply at prevailing market prices to meet the DSP’s anticipated default service obligation at reasonable costs. A DSP’s affiliate generation supplier may participate in the DSP’s competitive bid solicitations for generation service. DSPs will use an automatic energy adjustment clause to recover all reasonable costs of obtaining alternative energy pursuant to the Alternative Energy Portfolio Standards Act, and the DSP may use an automatic adjustment clause to recover non-alternative energy default service costs. Automatic adjustment clauses will be subject to annual review and audit by the Pennsylvania PUC. Default service rates will be adjusted on a quarterly basis, or more frequently, for customer classes with a peak load up to 500 kW, and on a monthly basis, or more frequently, for customer classes with peak loads greater than 500 kW.

In October 2007, West Penn filed a default service plan with the Pennsylvania PUC. The Pennsylvania PUC administrative law judge entered a final order on July 25, 2008 that largely approved West Penn’s proposed default service plan, including its full requirements procurement approach and rate mitigation plan. West Penn filed tariff supplements implementing the default service plan in September 2008 and January 2009. On February 6, 2009, West Penn filed a petition with the Pennsylvania PUC requesting approval to advance the first series of default service procurements for residential customers from June 2009 to April 2009 to take advantage of a downturn in market prices for power. West Penn’s petition was approved by the Pennsylvania PUC in March 2009, and it began to conduct advanced procurements in April 2009. West Penn has procured 80% of the generation supply needed to serve its residential customers in 2011, over 90% of the generation supply needed to serve its small and medium non-residential customers in 2011, and 100% of the generation supply needed to serve its largest non-residential customers who select the fixed-price DSP option in 2011.

Advanced Metering and Demand-Side Management Initiatives.  In October 2008, Pennsylvania adopted Act 129, which includes a number of measures relating to conservation, demand-side management and power procurement processes. Act 129 requires each EDC with more than 100,000 customers to adopt a plan, approved by the Pennsylvania PUC, to reduce, by May 31, 2011, electric consumption by at least one percent of its expected consumption for June 1, 2009 through May 31, 2010. By May 31, 2013, the total annual weather-normalized consumption is to be reduced by a minimum of three percent, and peak demand is to be reduced by a minimum of four and one-half percent of the EDC’s annual system peak demand. Act 129 also:

• directed the Pennsylvania PUC to adopt an energy conservation and efficiency program to require EDCs to develop and file, by July 1, 2009, plans to reduce energy demand and consumption; and

• required EDCs to file a plan for “smart meter” technology procurement and installation in August 2009.

West Penn expects to incur significant capital expenditures to comply with these requirements.

Act 129 also requires EDCs to obtain energy through a prudent mix of contracts, with an emphasis on competitive procurement. The Act includes a “grandfather” provision for West Penn’s procurement and rate mitigation plan, which was previously approved by the Pennsylvania PUC.

In June 2009, West Penn filed its Energy Efficiency and Conservation (“EE&C”) Plan containing 22 programs to meet its Act 129 demand and consumption reduction obligations. The proposed programs cover most energy-consuming devices of residential, commercial and industrial customers. The EE&C Plan also proposed a reconcilable surcharge mechanism to obtain full and current cost recovery of the EE&C Plan costs as provided in Act 129. The EE&C Plan projected an aggregated cost of the energy efficiency measures in the amount of approximately $94.3 million through mid 2013. A hearing concerning West Penn’s EE&C Plan was held August 19, 2009.

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The Pennsylvania PUC approved West Penn’s EE&C Plan, in large part, by Opinion and Order entered October 23, 2009. The new programs approved by the Pennsylvania PUC include: rebates for customers who purchase high efficiency appliances, lighting and heating and cooling systems; residential home audits and rebates toward implementing audit recommendations; home audit, weatherization and air conditioner replacement programs for low-income customers; new rate options that will provide financial incentives for customers to lower their demand for electricity or shift their usage to lower-priced times; incentives for customers who install in-home devices that reduce electric usage when demand is highest; and various programs for commercial, industrial, government and non-profit customers to increase energy efficiency and conservation. The Pennsylvania PUC also approved West Penn’s proposal to recover its EE&C Plan costs on a full and current basis via an automatic surcharge to customers’ bills, subject to an annual reconciliation mechanism.

The Pennsylvania PUC declined to approve West Penn’s proposed distributed generation program and West Penn’s proposed contract demand response program and encouraged West Penn to submit revisions to both programs. On December 21, 2009, West Penn filed an Amended EE&C Plan as directed by the Pennsylvania PUC, in which it added a new customer resources demand response program intended to replace the previously proposed distributed generation and contract demand programs. The Pennsylvania PUC reviewed West Penn’s amended Plan at its public meeting on February 11, 2010 and ordered West Penn to file an amended plan within 60 days to include additional detail on the costs associated with the previously approved customer load response program and the new customer resources demand response program.

On August 14, 2009, West Penn filed its Smart Meter Technology Procurement and Installation Plan. The Plan provides for extensive deployment of smart meter infrastructure with replacement of all of West Penn’s approximately 725,000 meters by the end of 2014. A hearing on West Penn’s smart meter Plan was held on November 8, 2009. On December 18, 2009, West Penn filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less rapid deployment of smart meters. On January 13, 2010, the Pennsylvania PUC granted the motion to reopen the record and remanded the proceeding to the ALJ. The Pennsylvania PUC also waived the late January 2010 deadline by which the ALJ’s recommended decision would have been required. The hearing was held on March 16, 2010, and on May 6, 2010, the ALJ issued a decision finding that West Penn’s alternative smart meter deployment plan, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including West Penn’s proposed cost recovery mechanism, by the Pennsylvania PUC.

However, in light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades as previously proposed, as well as its evaluation of recent Pennsylvania PUC decisions approving less rapid deployment proposals by other EDCs, West Penn undertook to re-evaluate its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. On July 21, 2010, the Pennsylvania PUC issued an order, in response to West Penn’s request, to stay West Penn’s smart meter implementation proceedings for a period of 90 days. On September 10, 2010, West Penn filed an amended EE&C Plan that is less reliant on smart meter deployment and emphasized non-smart meter programs to meet the conservation and demand reduction requirements of Act 129. Additionally, on October 19, 2010, West Penn and Pennsylvania’s Office of Consumer Advocate (the “OCA”) filed a Joint Petition for Settlement addressing West Penn’s smart meter implementation plan with the Pennsylvania PUC. Under the terms of the proposed Settlement, West Penn proposes to decelerate its previously contemplated smart meter deployment schedule, targeting the installation of an estimated 25,000 smart meters, based on customer requests, by mid-2012, in support of its EE&C Plan. Thereafter, West Penn proposes to install an additional 15,000 smart meters by 2013 and an additional 60,000 smart meters between 2013 and 2016. The proposed Settlement also contemplates that West Penn take advantage of the 30-month grace period authorized by the Pennsylvania PUC to continue its efforts to re-evaluate its full-scale smart meter deployment plans, and that it file a revised smart meter implementation plan reflecting those efforts, including its proposed plans for full-scale deployment of smart meters, which West Penn currently anticipates filing in June 2012. Under the terms of the proposed Settlement, West Penn would be permitted to recover certain previously-incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain

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expenditures amortized over a ten-year period and other expenditures amortized through 2017, in each case with interest on deferred amounts. Additionally, West Penn would be permitted to seek recovery of certain other costs as part of its revised smart meter implementation plan for full-scale deployment that it currently intends to file in June 2012 or in a future base distribution rate case.

On December 8, 2010, the Pennsylvania PUC directed that the smart meter implementation proceeding be referred to the Administrative Law Judge for further proceedings to ensure that the impact of the proposed Merger with FirstEnergy is considered and that the Joint Petition for Settlement filed in October 2010 had adequate support in the record.

On December 17, 2010, an Administrative Law Judge issued a Recommended Decision that the Amended EE&C Plan filed by West Penn in September 2010 be approved. By order entered January 13, 2011, the Pennsylvania PUC approved West Penn’s Amended EE&C Plan.

West Penn’s actual cost to implement smart meter infrastructure may vary from its prior estimates as a result of changes in its procurement and installation plan as ultimately approved by the Pennsylvania PUC and the timing of that approval, among other factors.

Transmission Expansion.  By order entered on December 12, 2008, the Pennsylvania PUC authorized TrAIL Company to construct a 1.2 mile portion of TrAIL in Pennsylvania from the proposed 502 Junction Substation in Greene County to the Pennsylvania-West Virginia state line. In the same order, the Pennsylvania PUC also authorized TrAIL Company to engage in a collaborative process to identify possible solutions to reliability problems in the Washington County, Pennsylvania area in lieu of the Prexy Facilities that had been a part of the original TrAIL proposal. As a result of the collaborative process, a settlement and an amendment to the application based on a consensus of the participants in the collaborative process was approved by the Pennsylvania PUC on November 19, 2010.

Alternative Energy Portfolio Standard.  Legislation enacted in 2004 requires the implementation of an alternative energy portfolio standard in Pennsylvania. This legislation requires EDCs and retail electric suppliers in Pennsylvania to obtain certain percentages of their energy supplies from alternative sources. However, the 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 their respective transition periods end. West Penn’s compliance period began on January 1, 2011. 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 entered a final rulemaking order on September 28, 2008, adopting regulations for implementation and enforcement of the legislation.

Reliability Benchmarks.  In May 2004, the Pennsylvania PUC modified its utility specific benchmarks and performance standards for electric distribution system reliability. The benchmarks were set too low for West Penn, resulting in required reliability levels that were unattainable. West Penn appealed the benchmarks to the Pennsylvania PUC and ultimately entered into an agreement settling the proceeding and providing West Penn with attainable reliability benchmarks, which the Pennsylvania PUC approved in 2006. According to the Pennsylvania PUC’s Electric Service Reliability in Pennsylvania 2008 report, Allegheny’s overall performance in 2008 was substantially better than its performance during 2007. In 2007 and 2008, Allegheny’s System Average Interruption Frequency Index, Customer Average Interruption Duration Index and System Average Interruption Duration Index values were better than the applicable standards. As of December 31, 2010, West Penn was in compliance with the reliability standards approved by the Pennsylvania PUC in its July 2006 order.

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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. In 2000, Potomac Edison received approval to transfer its West Virginia generation assets to AE Supply. However, the West Virginia PSC never acted on a similar petition by Monongahela, and Monongahela agreed to withdraw its petition. Based on these actions, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West Virginia.

Merger.  On May 18, 2010, Monongahela, Potomac Edison and TrAIL Company filed a joint application with FirstEnergy requesting authorization for a change in control of Monongahela, Potomac Edison and TrAIL Company as a result of the proposed Merger. On November 3, 2010, AE and FirstEnergy filed a comprehensive settlement with the West Virginia PSC resolving all issues raised by the parties in the merger proceedings in West Virginia. In addition to the commitments made in the initial merger application, the settlement includes certain commitments that will apply if the proposed Merger is completed, including: a commitment to maintain a regional headquarters for Allegheny’s West Virginia utility operations within Monongahela’s service territory; $7.5 million in rate reductions over a two-year period for Allegheny’s West Virginia customers; certain customer service and reliability commitments aimed at reducing the duration of outages; a commitment to maintain customer call center operations in Fairmont, West Virginia for at least five years following the completion of the Merger; additional funding totaling $500,000 over a four-year period for Dollar Energy Fund in West Virginia; and specific demand-side management and energy efficiency savings levels in Allegheny’s West Virginia service territories. The West Virginia PSC approved the settlement and the proposed Merger on December 16, 2010.

Rate Case.  On August 13, 2009, Monongahela and Potomac Edison filed with the West Virginia PSC a request to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. On January 12, 2010, Monongahela and Potomac Edison filed supplemental testimony discussing a tax treatment change that resulted in a revenue requirement that is approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of Monongahela and Potomac Edison completed a securitization transaction to finance certain costs associated with the installation of Scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently, Monongahela and Potomac Edison ultimately requested an increase in retail rates of approximately $95 million, rather than $122.1 million, annually. On April 2, 2010, Monongahela and Potomac Edison filed with the West Virginia PSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:

• a $40 million annualized base rate increase effective June 29, 2010;

• a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;

• an additional $20 million annualized base rate increase effective in January 2011;

• a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and

• a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.

The West Virginia PSC approved the Joint Petition and Agreement of Settlement on June 25, 2010.

Annual Adjustment of Fuel and Purchased Power Cost Rates.  On September 1, 2009, Monongahela and Potomac Edison filed their annual fuel adjustment request with the West Virginia PSC, requesting a rate increase

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of $143.2 million to reflect increases in their unrecovered balances of fuel and purchased power costs that have accrued through June 2009 and projected increases through June 2010. The new rates were submitted pursuant to the schedule for annual fuel and purchased power cost reviews. On December 2, 2009, the parties to the proceeding filed a Joint Stipulation providing that Monongahela and Potomac Edison would receive an increase of $118 million, effective January 1, 2010, plus deferred recovery of an additional $23.1 million effective January 1, 2011, with carrying charges of 6% on the deferred amount. The West Virginia PSC approved the Joint Stipulation on December 29, 2009.

Transmission Expansion.  On May 15, 2009, PATH-WV, PATH-Allegheny and certain other related entities filed an application with the West Virginia PSC for authorization to construct the West Virginia portion of the PATH Project. A decision on the application is expected in February 2012.

Alternative and Renewable Energy Portfolio Standard.  In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (the “Portfolio Act”), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In recognition of West Virginia’s natural resources, the portfolio standard includes alternative energy resources, such as advanced coal technology, coal bed methane and natural gas, and renewable energy resources, such as solar and wind power. Included in the Portfolio Act is the requirement that the West Virginia PSC promulgate rules to establish a system of tradeable credits to establish, verify and monitor the generation and sale of electricity generated from alternative and renewable energy resource facilities. These credits may also be earned through participation in energy efficiency or demand-side energy initiative projects and greenhouse gas emissions reductions or offset projects. The Portfolio Act provides that the credits may be traded, sold or used to meet the requirements of the alternative and renewable energy portfolio standard. On November 5, 2010, the West Virginia PSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (the “RPS Rules”), which became effective on January 4, 2011. Per the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule must prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the West Virginia PSC seeking approval of such plan. Allegheny filed its compliance plan on December 30, 2010. Additionally, Allegheny currently intends to file an application with the West Virginia PSC during 2011 to certify owned and contracted resources to generate renewable credits towards meeting its requirements under the Portfolio Act.

Purchase of Distribution Assets.  Effective December 31, 2010, Potomac Edison purchased Shenandoah’s West Virginia distribution assets for approximately $14.5 million, subject to certain post-closing adjustments.

Maryland

In 1999, Maryland adopted electric industry restructuring legislation, 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 but remained obligated to provide standard offer generation service (“SOS”) at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. As discussed below, Potomac Edison has implemented a rate stabilization plan to transition customers from capped generation rates to rates based on market prices. 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).

Merger.  On May 27, 2010, Potomac Edison filed a joint application with FirstEnergy requesting authorization for a change in control of Potomac Edison as a result of the proposed Merger. The Maryland PSC conducted hearings on the Merger from November 3 to November 19, 2010. On December 1, 2010, Potomac Edison and FirstEnergy filed a settlement agreement reached with numerous parties including the State of Maryland, the Maryland Energy Administration, the Maryland Department of the Environment, county and

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municipal governments, and representatives of union employees and industrial customers. The settlement includes certain commitments that will apply if the Merger is completed, including provisions for: customer credits totaling $6.5 million over four years to Potomac Edison’s Maryland residential customers; additional contributions and cost adjustments totaling $1.35 million; reliability commitments aimed at reducing the duration of outages; and assistance in the development of renewable energy projects in Maryland with an average annual output of 13,000 megawatt-hours, or the megawatt equivalent. The Maryland PSC issued a decision on January 18, 2011 approving the Merger, subject to certain additional and modified conditions.

Standard Offer Service.  In 2003, the Maryland PSC approved two state-wide settlements relating to the future of PLR and SOS. The settlements extended Potomac Edison’s obligation to provide SOS after the expiration of the generation rate cap periods established for Potomac Edison as part of the 1999 restructuring of Maryland’s electric market. The settlements provided that, after expiration of the generation rate caps, SOS would be provided through 2012 for residential customers, through 2008 for smaller commercial and industrial customers and through 2006 for Potomac Edison’s medium-sized commercial customers. Potomac Edison’s obligation to provide SOS for its largest industrial customers expired at the end of 2005. A 2005 settlement extended Potomac Edison’s SOS obligations to its medium-sized commercial customers through May 2007, and a further order of the Maryland PSC issued on August 28, 2006 extended that obligation through at least the end of May 2009. The Maryland PSC issued an order on November 8, 2006, and a report to the Maryland legislature on December 31, 2006, that would continue SOS to small and medium-sized commercial customers with changes in procurement durations. In another proceeding, the Maryland PSC ordered the utilities to issue a request for proposals for possible acquisition of demand response resources for the period from 2011 to 2016 and to participate in a working group on the development of distributed generation resources. The request for proposals was issued on January 16, 2009. The Maryland PSC issued an order on March 11, 2009 approving the purchase of most of the resources offered, and the utilities have made the purchases.

By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the Maryland PSC to report to the legislature on the status of SOS. The other Maryland electric utilities providing SOS, all of whose initial settlement obligations have expired, continue to do so essentially in accordance with the terms of the 2003 settlements as modified by the Maryland PSC orders discussed immediately above, as does Potomac Edison. The terms on which Potomac Edison will provide SOS to residential customers after the settlement covering that initial obligation expires in 2012 depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible Maryland PSC decisions in the proceedings discussed below.

The Maryland PSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS, the aggregation of low income SOS customers, and a retail supplier proposal for the utility “purchase” of all retailer receivables (“POR”) at no discount and with no recourse. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects are delayed or defeated. Hearings on Phase I and II were held in October and November 2007 and in January 2008. The issue regarding POR was ultimately resolved in another proceeding, and the Maryland electric utilities’ tariffs implementing POR went into effect in July 2010. It is unclear when the Maryland PSC will issue its findings in this and other related pending proceedings discussed below.

On July 3, 2008, the Maryland PSC issued a further order requiring the utilities to prepare detailed studies of alternatives for possible managed portfolios, with a time horizon out to fifteen years, and to file those studies by October 1, 2008. The Maryland PSC expressly stated that the order, “should not be construed… as a decision to modify in any way, the current SOS procurement practice.” Potomac Edison filed its study with the Maryland PSC on October 1, 2008, and the Maryland PSC held hearings on the matter in December 2008. No order has been issued.

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On September 29, 2009, the Maryland PSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. Proposals were initially due to be filed by December 16, 2009, but the Maryland PSC indefinitely postponed that deadline while it considered recommendations as to what the filings should be required to contain. On December 29, 2010, the Maryland PSC issued an order soliciting comments by January 28, 2011 on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities.

Also, on December 18, 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the Maryland PSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. On August 16, 2010, the Maryland PSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010.

In August 2007, Potomac Edison filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps on December 31, 2008. The Maryland PSC approved the plan in a series of orders issued between September 2007 and September 2008. Potomac Edison will continue to conduct rolling auctions to procure the power supply necessary to serve its customer load going forward.

Rate Stabilization.  In special session on June 23, 2006, the Maryland legislature passed emergency legislation, directing the Maryland PSC to, among other things, investigate options available to Potomac Edison to implement a rate mitigation or rate stabilization plan for SOS to protect its residential customers from rate shock in connection with the January 1, 2009 expiration of generation rate caps.

In December 2006, Potomac Edison filed with the Maryland PSC a proposed Rate Stabilization Ramp-Up Transition Plan designed to transition residential customers from capped generation rates to rates based on market prices. Under the plan as approved by the Maryland PSC, residential customers who did not elect to opt out of the program began paying a surcharge in June 2007. The application of the surcharge resulted in an overall rate increase of approximately 15% in 2007 and 13% in 2008. With the expiration of the residential generation rate caps and the move to generation rates based on market prices on January 1, 2009, the surcharge converted to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, were returned to customers as a credit on their electric bills through December 2010, thereby reducing the effect of the rate cap expiration. The resulting rate increase in 2009 was 11.3%, and the rate change approved in 2009 for 2010 was actually a decrease of 2.5%. Of Potomac Edison’s approximately 219,000 residential customers in Maryland, as of December 31, 2010, approximately 21.5% elected to opt-out of, or are not eligible for, Potomac Edison’s plan.

Advanced Metering and Demand Side Management Initiatives.  On September 28, 2007, the Maryland PSC issued an order in this case that required the utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that, in Maryland, electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015. On October 26, 2007, Potomac Edison filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The Maryland PSC conducted hearings on Potomac Edison’s and other utilities’ plans in November 2007 and further hearings on May 7, 2008.

In a related development, the Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals and setting a deadline of September 1, 2008 for the utilities to file comprehensive plans for attempting to achieve those goals. Potomac Edison filed its proposals on August 29, 2008, asking the Maryland PSC to approve seven programs for residential customers, five programs for commercial, industrial, and governmental customers, a customer education program, and a pilot deployment of Advanced Utility Infrastructure (“AUI”) that Allegheny has previously been testing in West Virginia. On December 31, 2008, the Maryland PSC issued an order approving some of Potomac Edison’s programs and directing that others be redesigned. Potomac Edison filed its revised programs on March 31, 2009, with new cost and benefit

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information. The Maryland PSC approved the programs on August 6, 2009, and approved cost recovery for the programs on October 6, 2009. Expenditures are expected to be approximately $101 million and will be recovered over the next six years. Meanwhile, the AUI pilot was placed on a separate track and is currently being re-examined after discussion with the Staff of the Maryland PSC and other stakeholders.

Renewable Energy Portfolio Standard.  Legislation enacted in 2004 (and supplemented with respect to solar power in 2007 and again in 2010) 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 must 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.

Moratorium on Service Terminations.  On March 11, 2009, the Maryland PSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The order directed the utilities and other interested parties to meet and devise proposals for offering payment plans to all residential customers, not just low-income customers. On April 1, 2009, the Staff of the Maryland PSC and utilities filed a plan providing for additional and longer payment plans and for a temporary suspension of requests to customers for increased deposits. The Maryland PSC held a hearing on the matter on April 7, 2009, and subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. Potomac Edison and several other utilities filed requests for reconsideration of various parts of the order on May 26, 2009, which motions were denied on September 23, 2009. Potomac Edison filed a notice of appeal of that order on October 23, 2009, but withdrew the appeal when the Maryland PSC issued a further order on November 23, 2009 that clarified the limited scope and duration of the rule changes. The Maryland PSC is continuing to conduct hearings and collect data on payment plans and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

Transmission Expansion.  On December 21, 2009, Potomac Edison filed an application with the Maryland PSC for authorization to construct the Maryland portions of the PATH Project. The project in Maryland will be owned by PATH Allegheny Maryland Transmission Company, LLC, which is owned by Potomac Edison and PATH-Allegheny. Potomac Edison subsequently requested an extension of the procedural schedule, which the Hearing Examiner has not ruled on the request. Based on the current procedural schedule, a decision on the application is expected in the third quarter of 2011.

Virginia

Merger.  The Virginia SCC issued a decision approving the proposed Merger on September 9, 2010.

Sale of Distribution Operations.  On June 1, 2010, Potomac Edison sold its Virginia distribution business to the Co-Ops. Cash proceeds from the sale were approximately $317 million, resulting in a pre-tax gain of approximately $45 million. In connection with the sale, Potomac Edison agreed to contribute $27.5 million between July 1, 2011 and July 1, 2014 to reduce the impact of any future rate increases on its former customers, the present value of which was included in the $45 million pre-tax gain.

Transmission Expansion.  On September 20, 2010, PATH Allegheny Virginia Transmission Corporation filed an application with the Virginia SCC for authorization to construct the Virginia portions of the PATH Project. A decision on the application is expected in the third quarter of 2011.

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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, rules and regulations as to air and water quality, hazardous and solid waste disposal and other environmental matters, some of which may be uncertain. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities. See “Risk Factors.”

Global Climate Change

The United States relies on coal-fired power plants for more than 45% of its energy. However, coal-fired power plants have come under scrutiny due to their emission of gases implicated in climate change, primarily carbon dioxide, or “CO₂.”

Allegheny produces approximately 95% of its electricity at coal-fired facilities and currently produces approximately 42 to 44 million tons of CO₂ annually through its energy production. While there are many unknowns concerning the final regulation of greenhouse gases in the United States, federal and/or state legislation and implementing regulations addressing climate change, including limits on emissions of CO₂, likely will be adopted some time in the future. Thus, CO₂ legislation and regulation, if not reasonably designed, could have a significant impact on Allegheny’s operations. To date Congress has not passed any CO₂ –specific law.

The EPA is moving to regulate greenhouse gas emissions under the Clean Air Act of 1970 (the “Clean Air Act”). On December 7, 2009, the EPA announced its Greenhouse Gas Endangerment Finding, stating that greenhouse gas emissions from cars and light trucks, when mixed in the atmosphere, endanger public health. The finding provides the EPA with a basis on which to regulate greenhouse gas emissions from vehicle tailpipes under the provisions of the Clean Air Act. Once a pollutant is regulated under the Clean Air Act for one source category, the EPA has authority to apply similar regulations to other source categories. On April 1, 2010, the EPA and the Department of Transportation’s National Highway Traffic Safety Administration (“NHTSA”) announced a joint final rule that applies to passenger cars, light-duty trucks and medium-duty passenger vehicles, covering model years 2012 through 2016. Under the Clean Air Act, regulation of greenhouse gas emissions from vehicles also triggers requirements for new and modified stationary sources to control greenhouse gas emissions under the Prevention of Significant Deterioration (“PSD”) program. Regulation of the stationary sources will be implemented through the final version of the “tailoring rule” issued on June 3, 2010. The tailoring rule became effective on January 2, 2011. For six months, only new and modified sources already required to control emissions of other air pollutants will be required to control greenhouse gas emissions. Beginning July 1, 2011, new sources above 100,000 tons per year and modified existing sources with emissions increases above 75,000 tons per year (which may include Allegheny’s facilities, but only to the extent any modifications to those facilities triggers application of the rule) will be required to control emissions.

There is a gap between the current capabilities of technology and the desired reduction levels contemplated by past legislative proposals; no current commercial-scale technology exists to enable many of the reduction levels discussed in past national, regional and state proposals. Such technology may not become available within a timeframe consistent with the implementation of any future climate control initiatives or at all. To the extent that such technology does become available, Allegheny can provide no assurance that it will be suitable for installation at Allegheny’s generation facilities on a cost effective basis or at all. Based on estimates from a 2007 Department of Energy National Electric Technology Laboratory report and recently announced projects by other entities, it could cost in the range of $4,800 to $5,500 per kW to replace existing coal-based power generation with fossil fuel stations capable of capturing and sequestering CO₂ emissions. However, exact estimates are difficult because of the lack of distinctive rules and the current lack of deployable technology.

Regardless of the eventual mechanism for limiting CO₂ emissions, compliance will be a major and costly challenge for Allegheny, its customers and the region in which it operates. Most notable will be the potential impact on customer bills and disproportionate increases in energy cost in areas that have built their energy and industrial infrastructure over the past century based on coal-fired electric generation.

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Because the regulatory/legislative process and applicable technology each is in its infancy, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures until the exact nature and requirements of any regulation are known and the capabilities of control or reduction technologies are more fully understood. Allegheny’s current strategy in response to climate change initiatives focuses on:

• maintaining an accurate CO₂ emissions database;

• improving the efficiency of its existing coal-burning generation facilities;

• following developing technologies for clean-coal energy and for CO₂ emission controls at coal-fired power plants, including carbon sequestration;

• analyzing options for future energy investment (e.g. , renewables, clean-coal, etc.); and

• improving demand-side efficiency programs, as evidenced by customer conservation outreach plans and Allegheny’s Watt Watchers initiatives.

Allegheny’s energy portfolio also includes approximately 1,180 MWs of renewable hydroelectric and pumped storage power generation. Allegheny obtained a permit to allow for a limited use of bio-mass (wood chips and saw dust) at one of its coal-fired power stations in West Virginia and currently has approval to use waste-tire derived fuel at another of its coal-based power stations in West Virginia.

Allegheny is participating in the dialogue that will shape the regulatory landscape surrounding CO₂ emissions. Additionally, Allegheny intends to pursue proven and cost-effective measures to manage its emissions while maintaining an affordable and reliable supply of electricity for its customers.

Clean Air Act Compliance and State Air Quality Initiatives

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 other means. 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’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install control technologies on many of its generation facilities at significant cost. The proposed Clean Air Transport Rule (“CATR”) released by the EPA on July 6, 2010 may accelerate the need to install this equipment by phasing out a portion of the currently available allowances, limiting trading and accelerating federal emission reduction goals. The proposed CATR replaces certain portions of the Clean Air Interstate Rule (“CAIR”). In June 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR, which would have required reductions of SO₂ and NO_X emissions in two phases beginning in 2010 and 2015. In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect until replaced by a new EPA rule.

Following the February 2008 vacature of EPA’s 2005 Clean Air Mercury Rule (“CAMR”) by the U.S. Court of Appeals for the District of Columbia, the EPA announced plans to propose a new maximum achievable control technology rule for hazardous air pollutant emissions from electric utility steam generating units in March 2011. The EPA plans to finalize the new rule by November 2011. Allegheny is monitoring the EPA’s efforts to promulgate hazardous air pollutant rules that will include, but will not be limited to, mercury limits. To establish these standards, the EPA must identify the best performing 12% of sources in each source category and, to that end, issued an information request to members of the fossil fuel-fired generating industry requiring extensive stack emissions testing on selected generating units. Allegheny completed stack testing for eight of its generating units identified by EPA and submitted all results by September 2010. Depending on the final hazardous air pollution limits set by the EPA, Allegheny could incur significant costs for additional control equipment.

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Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NO_X, requires mercury emissions and mandates that Maryland join the Regional Greenhouse Gas Initiative (“RGGI”) and participate in that coalition’s regional efforts to reduce CO₂ emissions. On April 20, 2007, Maryland’s governor signed on to RGGI, as a result of which Maryland became the 10th state to join the Northeast regional climate change and energy efficiency program. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NO_X, SO₂ and mercury, based on a PJM declaration that the station is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) passed alternate NO_X and SO₂ limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances.

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. Allegheny continues to evaluate and implement options for compliance. It completed the elimination of a partial bypass of Scrubbers at its Pleasants generation facility in December 2007 and the construction of Scrubbers at its Hatfield’s Ferry and Fort Martin generating facilities in 2009. Allegheny now has Scrubbers installed and operating on all ten of the units at its four supercritical generating facilities and at Mitchell Unit 3.

Allegheny’s NO_X compliance plan functions on a system-wide basis, similar to its SO₂ compliance plan. Pending finalization of the CATR, AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NO_X allowances, if needed, to supplement their compliance strategies. Allegheny currently has installed selective non-catalytic reduction equipment at its Fort Martin and Hatfield’s Ferry generating stations and selective catalytic reduction equipment at its Harrison and Pleasants generating stations, together with other NO_X controls at these supercritical generating facilities, as well as its other generating facilities.

On January 8, 2010, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Notice of Violation for opacity emissions at Allegheny’s Pleasants generating facility. Allegheny will be installing a wet reagent injection system in 2011 to control the opacity.

Clean Water Act Compliance

In 2004, the EPA issued a final rule requiring all existing power plants with once-through cooling water systems withdrawing more than 50 million gallons of water per day to meet certain standards to reduce mortality of aquatic organisms pinned against the water intake screens or, in some cases, drawn through the cooling water system. The standards varied based on the type and size of the water bodies from which the plants draw their cooling water.

In January 2007, the Second Circuit Court of Appeals issued a decision on appeal that remanded a significant portion of the rule to the EPA. As a result, the EPA suspended the rule, except for a requirement, which existed prior to the EPA’s adoption of the 2004 rule, that permitting agencies use best professional judgment (“BPJ”) to determine the best technology available for minimizing adverse environmental impacts for existing facility cooling water intakes. Pending re-issuance of the 2004 rule by the EPA, permitting agencies thus will rely on BPJ determinations during permit renewal at existing facilities.

On April 1, 2009, the U.S. Supreme Court reversed the appeals court decision and upheld the EPA’s authority to use cost/benefit analysis. EPA plans to issue a proposed rule addressing the issues remanded by the Court in 2011 and to issue a final rule in 2012. Depending on the standards set by the EPA when it reissues this rule, Allegheny could incur significant costs for additional control equipment.

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Monongahela River Water Quality

In late 2008, the PA DEP imposed water quality criteria for certain effluents, including total dissolved solid (“TDS”) and sulfate concentrations in the Monongahela River, on new and modified sources, including the Scrubber project at the Hatfield’s Ferry generation facility. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the Scrubbers as designed. Preliminary studies indicate an initial capital investment of approximately $62 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council who seek to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin on September 13, 2011. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.

In a parallel rulemaking, the PA DEP recommended an end-of-pipe limit TDS rule, and the Pennsylvania Environmental Quality Board issued the final rule on August 21, 2010. Allegheny could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

On December 23, 2010, PA DEP submitted its Clean Water Act 303(d) list to EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. EPA is reviewing PA DEP’s recommendation. If the designation is approved, Pennsylvania will then need to develop a Total Maximum Daily Load (“TMDL”) limit for the river, a process that will take about five years. Based on the stringency of the TMDL, Allegheny Energy may incur significant costs for controls on its national pollution discharge elimination system, or “NPDES,” discharges to the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia. Allegheny appealed the PA DEP’s proposed 303(d) designation to the Pennsylvania Environmental Hearing Board in January 2011 on the basis that the PA DEP failed to follow its own methodologies for concluding the river segments are impaired.

In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the Scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for Monongahela to meet certain of the effluent limits that are effective immediately under the terms of the permit. Monongahela appealed the Fort Martin permit and the administrative order. The appeal includes a request to stay certain of the conditions of the permit and order while the appeal is pending. The request to stay has been granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. Monongahela moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require Monongahela to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. Monongahela intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

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Solid Waste

The EPA is reviewing its waste regulations relating to coal combustion residuals (“CCR”) partly in response to a Tennessee Valley Authority ash spill in Kingston, Tennessee in December 2008. CCR includes bottom ash, boiler slag, fly ash and Scrubber byproducts including gypsum. CCR has historically been designated and managed as a non-hazardous waste, and the EPA has twice determined that it is not appropriate to regulate it as a hazardous waste under the Resource Conservation and Recovery Act (“RCRA”). The EPA is reconsidering those earlier determinations and intends to issue new regulations for the management and disposal of CCR in 2011 or 2012. The EPA has not yet reached a final decision on whether to regulate CCR as a hazardous or special waste (RCRA Title C) or as a non-hazardous waste (RCRA Title D) and on May 4, 2010 released a draft proposed rule which contained both options for public comment. Should the EPA elect to designate CCR as hazardous or special waste at any point in its generation, storage, transportation or disposal cycle, it could significantly increase Allegheny’s cost of managing CCR materials and could also drive additional monitoring and corrective action at legacy disposal sites. In addition to potential additional management costs for CCR disposal, Allegheny might expect to see a reduction in options for beneficial reuse of CCR in applications such as mine reclamation, cement manufacture and agriculture, further increasing costs, as such materials will then enter landfills rather than beneficial reuse. While EPA’s proposed rule appears to attempt to protect beneficial CCR reuse whatever the CCR designation, we are still reviewing the rule and assessing its effect on Allegheny in that regard. The proposed rule also provides options for the management and closure of wet CCR storage and disposal impoundments. Even if EPA elects the non-hazardous CCR option in a final rule, reducing Allegheny’s potential waste management exposure, closure of wet disposal impoundments could be a source of significant costs. Allegheny is assessing the draft proposal and working with various trade groups and associations to determine potential costs and effects under either CCR option.

Potential Impact of Recent EPA and Climate Change Initiatives

Implementation of the EPA’s current proposals with regard to air quality, water quality and CCR, as described above, would, together with potential climate change legislation, require extensive and costly changes to the nation’s electric generation fleet, including the installation of new pollution controls, retirement of many existing generating facilities and construction of new generating capacity. Several industry and industry-related assessments, while varying in their estimates and assumptions, estimate that if implementation of these initiatives proceeds according to currently proposed schedules, the combined national cost through 2015 associated with required retrofitting of existing facilities and construction of new facilities could be hundreds of billions of dollars. Additionally, it is estimated that the cost of complying with these initiatives may not be economically justified for many individual facilities and would therefore result in the retirement of a significant portion of the nation’s existing coal-fired generation capacity. While specific estimates involve complex models incorporating many variables and assumptions that are subject to individual interpretation and are highly subject to change, it is clear that timely compliance would be challenging and require significant investment, both at the industry level and for Allegheny, which could be required to install a variety of additional pollution controls at a number of its generating facilities and could be compelled to retire certain of its subcritical facilities.

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/or 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, or “NSR,” standards under the Clean Air Act, which can require the installation of additional air emission 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.

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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 emission control technology.

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 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 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. On August 12, 2010, the Court granted the motion to dismiss, and the lawsuit has been concluded.

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. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. On November 18, 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case, who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. On April 18, 2010, the District Court issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. The non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law on December 23, 2010, and Allegheny must make its related filings on or before February 28, 2011. The District Court will issue its rulings after those filings have been made.

In addition to this lawsuit, on September 21, 2007, Allegheny received a Notice of Violation (“NOV”) from the EPA alleging NSR and PSD violations under the federal Clean Air Act, as well as Pennsylvania and West Virginia state laws. The NOV, which was directed to AE, Monongahela and West Penn, alleges violations at the Hatfield’s Ferry and Armstrong generation facilities in Pennsylvania and the Fort Martin and Willow Island generation facilities in West Virginia. The projects identified in the NOV are essentially the same as the projects at issue for these four facilities in the May 20, 2004 Notice and the PA Enforcement Action. Allegheny intends to vigorously pursue and defend against the Clean Air Act matters described above but cannot predict their outcomes.

Global Warming Class Action

On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District

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Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by Hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. On December 6, 2006, AE filed a motion to dismiss plaintiffs’ complaint on jurisdictional grounds and then joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. At a hearing on August 30, 2007, the Court granted the motion to dismiss that AE had joined and dismissed all of the plaintiffs’ claims against all defendants. Plaintiffs appealed that ruling to the United States Court of Appeals for the Fifth Circuit. On October 6, 2009, the assigned panel of the appellate court issued a written opinion that reversed the judgment entered by the District Court in favor of the defendants with respect to certain of the plaintiffs’ claims and remanded the case to the District Court for further proceedings. On November 25, 2009, AE and others filed a petition to have all of the judges of the Fifth Circuit rehear the issues addressed in the panel’s October 6, 2009 opinion. That petition was granted and oral argument was set for May 24, 2010. However, the parties were notified on April 30, 2010 that the Court was unable to empanel the necessary nine judges to hear the merits of the appeal due to recusals. The Court then entered an order on May 28, 2010, reinstating the ruling of the lower court that entered judgment in favor of the defendants and dismissing plaintiffs’ appeal. Plaintiffs filed a Petition for Mandamus with the United States Supreme Court on August 26, 2010, and Defendants subsequently filed their response to the petition. The Supreme Court denied Plaintiffs’ petition on or about January 20, 2011.

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EMPLOYEES

Substantially all of Allegheny’s officers and other personnel are employed by AESC. As of December 31, 2010, AESC employed 4,211 employees. Of these employees, 28.4% are subject to collective bargaining arrangements. Approximately 72% of the unionized employees are at the Distribution Companies and approximately 28% are at AE’s other subsidiaries. As of December 31, 2010, System Local 102 of the Utility Workers Union of America (the “UWUA”) represents 1,014 employees, and locals of the International Brotherhood of Electrical Workers (the “IBEW”) represent 183 employees.

Collective bargaining agreements with the IBEW and UWUA expire during 2012, 2013, 2014 and 2015. Members of the IBEW Local 50 are covered under the terms of a collective bargaining agreement that includes 32 members and expires on February 28, 2015. Allegheny’s current collective bargaining agreement with IBEW Local 2357 was set to expire on February 28, 2010, but the members of IBEW Local 2357 agreed to a two-year contract extension through February 28, 2012. Members of IBEW Local 307 agreed in 2010 to a new, four-year contract that extends through April 30, 2014, and members of UWUA Local 102 agreed to a new two-year contract extension through April 30, 2013.

Effective in October 2010, newly elected unions represent employees at the Harrison generation station and Webster Springs Service Center. UWUA Local 304 represents approximately 170 employees at Harrison and IBEW Local 2357 represents an additional 7 employees at Webster Springs.

Allegheny 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 with a service provider under which, on November 1, 2005, the service provider assumed responsibility for many of Allegheny’s information technology functions. Unless extended by AE or terminated, the Professional Services Agreement will expire on December 31, 2012.

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ITEM 1A.    RISK FACTORS

Allegheny is subject to a variety of significant risks that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond its control. A number of these risks are identified below, in addition to the matters set forth under “Special Note Regarding Forward-Looking Statements.” Allegheny’s susceptibility to certain risks could exacerbate other risks. These risk factors should be considered carefully in evaluating Allegheny’s risk profile.

Risks Relating to the Merger with FirstEnergy

Allegheny may be unable to obtain the approval required to complete its Merger with FirstEnergy or, in order to do so, the combined company may be required to comply with material restrictions or conditions.

On February 11, 2010, Allegheny announced the execution of its Merger Agreement with FirstEnergy. Completion of the Merger is subject to shareholder approval of the proposed transaction, as well as various approvals or other action by FERC, various utility regulatory, antitrust and other authorities in the United States. While Allegheny and First Energy have received most of these approvals, including approvals from FERC, the West Virginia PSC, the Maryland PSC and the Virginia SCC, as well as confirmation from the U.S. Department of Justice of the completion of its investigation of the proposed Merger, consummation of the Merger remains subject to approval by the Pennsylvania PUC. In October 2010, Allegheny and FirstEnergy filed with the Pennsylvania PUC a comprehensive settlement that addresses the issues raised by a majority of the parties to the merger proceedings in Pennsylvania. Nevertheless, the Pennsylvania PUC could impose conditions, in addition to those to which Allegheny and FirstEnergy committed in their original application to the Pennsylvania PUC and in the settlement, on the completion of the Merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following completion of the Merger. These conditions or changes could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company following the Merger, which could have a material adverse effect on the financial results of the combined company and/or cause either Allegheny or FirstEnergy to abandon the Merger.

If Allegheny and FirstEnergy are unable to complete the Merger, Allegheny still will incur and will remain liable for significant transaction costs, including legal, accounting, financial advisory, filing, printing and other costs relating to the Merger. Also, under certain limited circumstances, Allegheny may be required to pay FirstEnergy a termination fee of up to $150 million and reimburse FirstEnergy for its transaction expenses up to $45 million if the Merger is not completed and AE enters into, within 12 months following termination of the Merger Agreement, an agreement for another merger or similar transaction or a transaction by which the acquiror would acquire 20% or more of any class of AE’s equity securities or any business or assets constituting 20% or more of AE’s consolidated net revenues, net income or assets. Additionally, under specified circumstances in which the Merger is not completed but the $150 million termination fee is not payable, Allegheny may nevertheless be required to reimburse FirstEnergy for its transaction expenses up to $45 million. Any such payment could have a material adverse effect on Allegheny’s business, results of operations, cash flows and financial condition. See Note 2, “Merger Agreement,” to Allegheny’s consolidated financial statements.

If completed, Allegheny’s Merger with FirstEnergy may not achieve its intended results.

Allegheny and FirstEnergy entered into the Merger Agreement with the expectation that the Merger would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the businesses of Allegheny and FirstEnergy are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial results and prospects.

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Allegheny is subject to business uncertainties and contractual restrictions while the Merger with FirstEnergy is pending that could adversely affect Allegheny’s financial results.

Uncertainty about the effect of the Merger with FirstEnergy on employees, customers and suppliers may have an adverse effect on Allegheny. Although Allegheny has taken steps designed to reduce any adverse effects, these uncertainties may impair Allegheny’s ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with Allegheny to seek to change existing business relationships.

Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite Allegheny’s retention and recruiting efforts, key employees depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, Allegheny’s financial results could be affected.

The pursuit of the Merger and the preparation for the integration of Allegheny and FirstEnergy may place a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could affect Allegheny’s business, results of operations and financial condition.

In addition, the Merger Agreement restricts Allegheny, without FirstEnergy’s consent, from making certain acquisitions and taking other specified actions until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent Allegheny from pursuing otherwise attractive business opportunities and making other changes to its business prior to completion of the Merger or termination of the Merger Agreement.

Risks Relating to Regulation

Allegheny is subject to substantial governmental regulation. Compliance with current and future regulatory requirements and the need to obtain necessary approvals, permits and certificates may result in substantial costs to Allegheny, and failure to obtain necessary regulatory approvals could have an adverse effect on its business.

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 and construction, sales of securities, asset sales and accounting policies and practices. Although Allegheny believes that the necessary authorizations, permits, approvals and certificates have been obtained for its existing operations and that its business is conducted in accordance with applicable laws, it 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. See “Environmental Matters” and “Regulatory Framework Affecting Allegheny.”

Changes in regulations or the imposition of additional regulations could influence Allegheny’s operating environment and may result in substantial costs to Allegheny, which could have an adverse effect on its business, results of operations, cash flows and financial condition.

Allegheny’s costs to comply with environmental laws have been significant. 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. The cost of compliance with present and future environmental laws could have an adverse effect on Allegheny’s business.

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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 and may, in the future, become subject to new and potentially more extensive environmental regulations, including but not limited to regulations intended to address climate change. Compliance with these laws and regulations may require Allegheny to expend significant financial resources to, among other things, meet air emission and water quality standards, conduct site remediation, perform environmental monitoring, purchase emission allowances, use alternative fuels, install and operate pollution control equipment at its generation facilities 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. Either result could have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

Implementation of the EPA’s current proposals with regard to air quality, water quality and CCR would, together with potential climate change legislation, require extensive and costly changes to the nation’s electric generation fleet, including the installation of new pollution controls, retirement of many existing generating facilities and construction of new generating capacity. Several industry and industry-related assessments, while varying in their estimates and assumptions, estimate that if implementation of these initiatives proceeds according to currently proposed schedules, the combined national cost through 2015 associated with required retrofitting of existing facilities and construction of new facilities could be hundreds of billions of dollars. Additionally, it is estimated that the cost of complying with these initiatives may not be economically justified for many individual facilities and could therefore result in the retirement of a significant portion of the nation’s existing coal-fired generation capacity. While specific estimates involve complex models incorporating many variables and assumptions that are subject to individual interpretation and are highly subject to change, it is clear that timely compliance would be challenging and require significant investment, both at the industry level and for Allegheny, which could be required to install a variety of additional pollution controls at a number of its generating facilities and could be compelled to retire certain of its subcritical facilities.

Allegheny also may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations. For example, 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. See “Environmental Matters.”

Shifting state and federal regulatory policies impose risks on Allegheny’s operations. Compliance with emerging regulatory initiatives could require Allegheny to incur significant costs. Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have an adverse effect on its business.

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

Some deregulated electricity markets in which Allegheny operates have experienced price volatility. In some of these markets, government agencies and other interested parties have made proposals to delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although it is possible that, in an economic downturn, price increases resulting from the transition to market rates could be smaller than previously anticipated, the heightened public and political concern over the transition to market rates could nevertheless be exacerbated by a decline in the national economic climate and its potential effects on consumers.

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Consequently, proposals to re-regulate the industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be reversed in the states in which Allegheny operates. Reversals of electricity market restructurings in the markets in which Allegheny operates could have an adverse effect on its business, results of operations, cash flows 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. See “Regulatory Framework Affecting Allegheny.”

Furthermore, some of the states in which Allegheny operates have enacted or are considering various energy efficiency and conservation programs, which could prove costly for Allegheny. In 2008, for example, Pennsylvania adopted Act 129, which includes a number of provisions relating to conservation, demand-side management and power procurement processes. Among other things, Act 129 requires the implementation of smart meter technology, in connection with which Allegheny expects to incur substantial costs. Although Act 129 includes cost recovery provisions, any delay in or denial of cost recovery could adversely affect Allegheny. Additionally, failure to comply with Act 129 could result in significant penalties as early as 2011. Maryland has adopted some similar measures as part of its EmPOWER Maryland initiative. See “Regulatory Framework Affecting Allegheny.”

State rate regulation may delay or deny full recovery of costs and impose risks on Allegheny’s operations. Any denial of, or delay in, cost recovery could have an adverse effect on Allegheny’s business.

The retail rates in the states in which Allegheny operates are set by each state’s regulatory body. As a result, in certain states, Allegheny may not be able to recover increased, unexpected or necessary costs and, even if Allegheny is able to do so, there may be a significant delay between the time Allegheny incurs such costs and the time Allegheny is allowed to recover them. Any denial of, or delay in, cost recovery could have an adverse effect on Allegheny’s results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny.”

Allegheny could be subject to significant penalties if it violates mandatory NERC reliability standards.

The Energy Policy Act amended the FPA to, among other matters, provide for mandatory reliability standards designed to assure the reliable operation of the bulk power system. NERC established, and FERC approved, reliability standards that impose certain operating, record-keeping and reporting requirements on the Distribution Companies, TrAIL Company, PATH, LLC, AE Supply and AGC. NERC delegated the day-to-day implementation and enforcement of these standards to eight regional oversight entities, including ReliabilityFirst, of which Allegheny is a member.

Allegheny has been, and will continue to be, subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirst is currently conducting certain violation investigations with regard to matters of compliance by Allegheny. The results of these proceedings and investigations have not had, and are not expected to have, a material impact on Allegheny’s operations or the results thereof. It is possible, however, that any violation of these mandatory standards could subject Allegheny to civil fines imposed by FERC for up to $1.0 million per day, per violation, which could have an adverse effect on Allegheny’s results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny.”

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The PATH Project is subject to permitting and state regulatory approvals, and the failure to obtain any of these permits or approvals could have an adverse effect on Allegheny’s business.

The construction of the PATH Project is subject to the prior approval of various regulatory bodies. Allegheny has met substantial political opposition, as well as opposition from environmental, community and other groups, in obtaining siting approval for the PATH Project. There can be no assurance that Allegheny will be able to obtain the regulatory approvals required in connection with this project, particularly the required siting approvals, on a timely basis or at all. The inability to obtain any required state approval or other regulatory approval as a result of such opposition or otherwise, may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny.”

It is possible that PJM could determine to delay the currently required in-service date for the PATH Project, or suspend or cancel the project, if load projections indicate that the project may not be required by June 2015.

PJM initially authorized construction of the PATH Project in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. If after further analysis PJM determines that the project is not required by June 2015 to address potential NERC reliability violations, it may delay the required in-service date for the project to a later date or indefinitely or suspend or cancel the project. Delay or suspension of the PATH Project may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

Allegheny is from time to time subject to federal or state tax audits the resolution of which could have an adverse effect on Allegheny’s financial condition.

Allegheny is subject to periodic audits and examinations by the Internal Revenue Service (“IRS”) and other state and local taxing authorities. Determinations and expenses related to these audits and examinations and other proceedings by the IRS and other state and local taxing authorities could materially and adversely affect Allegheny’s financial condition.

Risks Relating to Allegheny’s Operations

Decreasing demand for electric power, as well as for certain commodities underlying the production of electric power and any related decline in market prices for power could adversely affect Allegheny’s business.

During 2009, customer demand for electric power in Allegheny’s region fell significantly as a result of the economic recession and mild summer weather, among other factors. Overall demand for some of the commodities that underlie the production of electricity, and as a result the prevailing prices for those commodities, also declined. Although power prices may be influenced by many factors, this weakening demand for electricity, together with significantly lower commodity prices, contributed to sharp declines in market prices for power in 2009. Partly as a consequence of these declines, AE Supply generated significantly less power in 2009 than in 2008.

Although markets improved in 2010, Allegheny can make no assurances regarding the impact of any further economic recovery on demand and market prices for power. Future improvements in demand and market prices for power, if any, may lag any future improvements in overall economic conditions, and the possibility exists for a long-term reduction of demand for power in Allegheny’s region, particularly among large industrial consumers. It is also possible that changes in customer behavior, as a result of conservation programs such as EmPOWER Maryland and Pennsylvania’s Act 129 or otherwise, could result in long-term reductions in demand for power.

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Allegheny’s coal inventories have, at times, exceeded desirable levels as a result of recent decreases in its power production resulting from declines in demand and market prices for power.

AE Supply and Monongahela have various longer term coal supply contracts in place that are intended to partially mitigate their exposure to negative fluctuations in coal prices. In some cases, these contracts may require that AE Supply or Monongahela purchase a minimum volume of coal over a given time period. However, as a result of falling demand and market prices for power, Allegheny experienced declines in 2009 in the frequency with which its coal burning power plants operated. As a result, Allegheny’s coal consumption decreased significantly. Although Allegheny was able to defer or cancel deliveries under certain contracts, it was at times required to purchase coal in excess of immediate needs, resulting in coal inventories at some of its facilities that exceeded what it considers to be optimal levels. It is possible that future economic downturns or other conditions that affect the demand for and price of power could have a similar impact on Allegheny, which could have an adverse impact on its business. If coal inventories exceed optimal levels, Allegheny may be unable to accept future deliveries at one or more of its facilities and may need to pursue alternative arrangements, including third party sales of inventory at levels below its cost, arrangements for third-party storage of a portion of its coal inventory, and modifications to its existing coal supply agreements.

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.

Allegheny’s supercritical generation facilities were originally constructed in the late 1960s and early 1970s, and many of its other generation facilities were constructed prior to that time. Older equipment may require significant maintenance and 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, all of which may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

Allegheny’s operating results are subject to seasonal and weather fluctuations and other factors that affect customer demand.

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 in Allegheny’s service territory peaks during the summer and winter months. 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 Regulated Operations 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 an adverse impact on Allegheny’s business, results of operations, cash flow and financial condition.

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Allegheny’s results also may be negatively impacted as a result of other circumstances that affect customer demand for power. For example, it is possible that the current economic downturn, as well as conservation efforts such as the EmPOWER Maryland program and Pennsylvania’s Act 129, have and will continue to contribute to changes in customer behavior, which may result in a significant reduction in demand, particularly among commercial and industrial customers, which could, in turn, have an adverse impact on Allegheny’s business, results of operations, cash flow and financial condition.

Changes in weather patterns as a result of global warming could have an adverse effect on Allegheny’s business.

Allegheny also could be impacted to the extent that global warming trends affect established weather patterns or exacerbate extreme weather or weather fluctuations. Although Allegheny’s physical assets are located in a region in which they are unlikely to experience detrimental physical damage from the rising sea levels that have been modeled in various analyses that attempt to predict the effects of global warming, other weather-related effects that could be associated with global warming, such as an increase in the frequency and/or severity of storms or other significant climate changes within or outside of Allegheny’s service territory, may have an adverse impact on Allegheny’s business, results of operations, cash flow and financial condition.

Allegheny’s assets 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 business, results of operations, cash flows 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 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 some losses may be recoverable through regulatory proceedings, the delay and uncertainty of any such recovery may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

The supply and price of fuel 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. However, Allegheny can provide no assurance that the counterparties to these agreements will fulfill their obligations to supply coal. The suppliers under these agreements may, as a general matter, experience financial, legal or technical problems that inhibit their ability to fulfill their obligations. Among other circumstances, constrained credit markets or other negative economic conditions could affect the ability of Allegheny’s suppliers to access the capital markets and maintain adequate liquidity to sustain their respective businesses. Additionally, to the extent that any of Allegheny’s coal suppliers seek bankruptcy protection, they may, in the current climate, be unable to obtain the financing necessary to continue their operations in bankruptcy and reorganize and, thus, may be forced to liquidate. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties may have negative effects on coal supplier performance. During periods of rising coal prices, the factors impacting supplier performance could have a more pronounced financial impact. Furthermore, 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. In addition, although these agreements generally contain specified prices, they also may provide for price adjustments related to changes in specified

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cost indices, as well as specific events, such as changes in regulations affecting the coal industry. Finally, it is possible that, in the future, market prices for coal could fall below the prices at which we have agreed to purchase coal under our long-term contracts. Changes in the supply and price of coal may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Additionally, Allegheny is subject to other fuel-related costs, which may fluctuate. For example, Allegheny has experienced, and may continue to experience, increases in its fuel handling and transportation costs and its costs to procure lime, urea and other materials necessary to the operation of its pollution controls. Significant increases in these and other fuel related costs could have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

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

Allegheny’s SO₂ and NO_x emission 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. Fluctuations in the availability or cost of these emission allowances could have a material adverse effect on Allegheny’s business, financial condition, cash flows and results of operations. It is also possible that any climate change legislation will incorporate a cap and trade scheme involving CO₂ emission allowances. In that case, the cost and availability of CO₂ emission allowances could have an adverse effect on Allegheny’s business, financial condition, cash flows and results of operations. See “Environmental Matters.”

Allegheny is currently involved in capital intensive projects that may involve various implementation and financial risks.

Allegheny currently is involved in a number of capital intensive projects, including the TrAIL Project, the PATH Project, the implementation of a new EMS system and the implementation of smart meter and other information technology necessary to comply with Pennsylvania’s recently-enacted Act 129. Allegheny’s ability to successfully complete these projects in a timely manner, within established budgets and without significant operational disruptions is contingent upon many variables, many of which are outside of its control. Failure to complete these projects as planned may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Additionally, Allegheny has contracted with specialized vendors in connection with these projects, and may in the future enter into additional such contracts with respect to these and other capital projects. As such, Allegheny is exposed to the risk that these contractors may not perform as required under their contracts. Such a failure could occur for any number of reasons. Among other things, it is possible that constrained credit markets or other negative economic conditions could affect the ability of Allegheny’s contractors, subcontractors, suppliers and vendors to access the capital markets and maintain adequate liquidity to sustain their respective businesses. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all. Any inability to make such alternate arrangements or any substantial delays or increases in costs associated therewith may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition. For additional information regarding Act 129, see “Regulatory Framework Affecting Allegheny.”

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

Because Allegheny has transferred functional control of its transmission facilities to PJM, is a load serving entity within the PJM Region and owns generation within the PJM Region, changes in PJM policies and/or market rules, including changes that are currently under consideration by FERC, could adversely affect Allegheny’s financial results. These matters include changes involving: the terms, conditions and pricing of

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transmission services; construction of transmission enhancements; auction of long-term financial transmission rights and the allocation mechanism for the auction revenues; the RPM; the locational marginal pricing mechanism; transmission congestion patterns due to the proposed implementation of PJM’s regional transmission expansion planning protocol or other required transmission system upgrades; new generation retirement rules and reliability pricing issues. Furthermore, changes in PJM’s credit and collateral requirements, deterioration in the credit quality of other PJM members, socialization of member defaults, the withdrawal from, or addition to, PJM of other transmission owners, may have an adverse effect on Allegheny’s results of operations, cash flow and financial condition.

The terms of AE Supply’s power sale agreements could require AE Supply to sell power below its costs or prevailing market prices.

Under the terms of its long term power sale agreements, AE Supply may not earn as much as it otherwise could by selling power at current market prices. In addition, AE Supply’s obligations under its 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, which may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Allegheny is exposed to price volatility as a result of its participation in wholesale energy markets.

AE Supply buys and sells electricity in wholesale markets, which exposes Allegheny to the risks of rising and falling prices in those markets. Among the factors that can influence such prices are:

• the balance of supply and demand for electricity, which may be influenced by any number of factors, including but not limited to prevailing weather and economic conditions;

• fuel costs, the cost of emissions allowances and other production costs;

• transmission constraints;

• changes in PJM rules and other changes in the regulatory framework for wholesale power markets; and

• market liquidity and the credit worthiness of market participants.

As a result of these and other factors, wholesale market prices for electricity may fluctuate substantially over relatively short periods of time and can be unpredictable, and may have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Allegheny’s use of derivative instruments for hedging purposes may result in financial losses.

Allegheny uses derivative instruments, such as futures, swaps, forwards and financial transmission rights, to manage its commodity and financial market risks. Allegheny could recognize losses on these contracts as a result of volatility in the market values of the underlying commodities or to the extent that a counterparty fails to perform. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these instruments involves management’s judgment or use of estimates. Furthermore, changes in the value of derivatives designated under hedge accounting to the extent not fully offset by changes in the value of the hedged transaction can result in ineffectiveness losses that may have an adverse effect on Allegheny’s results of operations.

Recently, members of Congress and various federal regulatory agencies, including the SEC, the Commodity Futures Trading Commission and the U.S. Treasury Department, have put forth proposals regarding the potential for more stringent regulation of the over-the-counter (“OTC”) derivatives markets. If ultimately adopted, such regulations could include requirements for greater standardization and more centralized trading of these instruments. Some have proposed that OTC derivatives trading take place on organized exchanges. Depending

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upon its specific terms, it is possible that any new legislation or regulation in this regard could significantly increase Allegheny’s costs with respect to, or otherwise constrain its ability to effectively use, these instruments to manage financial risks, which could have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

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, at times made it difficult for Allegheny to hedge its power supply obligations and fuel requirements. Although substantial improvements have been made in Allegheny’s credit position over the past few years, significant unanticipated changes in commodity market liquidity and/or Allegheny’s access to the commodity markets, including as a result of any decline in Allegheny’s credit ratings (including ratings for AE, AE Supply or Monongahela), 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. Furthermore, if Allegheny’s credit ratings were to decline, it would likely be required to deposit additional cash or cash-equivalent collateral with its hedging counterparties, which could have a negative impact on Allegheny’s liquidity and commodity trading activities.

As widely reported, the financial markets and overall economies in the United States and abroad are currently undergoing a period of significant uncertainty and volatility. These conditions can adversely impact the liquidity of the commodity markets in which Allegheny may wish to transact and may negatively affect the ability of Allegheny’s counterparties to honor their commitments. This, in turn, could inhibit Allegheny’s ability to transact in the desired timeframe or at a satisfactory price, which could increase Allegheny’s exposure to commodity price fluctuations and may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial conditions.

Allegheny’s policies and procedures cannot eliminate all risk involved in its energy commodity activities.

Allegheny may not always hedge the entire exposure of its operations to commodity price volatility. Furthermore, Allegheny’s risk management, wholesale marketing, fuel procurements and energy trading activities, including its decisions to enter into power sales or purchase agreements, rely on models that depend on the judgments and assumptions regarding factors such as generation facility availability, future market prices, weather and the demand for electricity and other energy-related commodities. Many of these models are developed utilizing statistical relationships between numerous interrelated factors. Such relationships can change significantly in an unpredictable manner, especially during periods of significant volatility. Even when Allegheny’s policies and procedures are followed and decisions are made based on these models, Allegheny’s policies and procedures cannot eliminate all risk involved in its energy commodity activities. Allegheny’s financial position and results of operations may be adversely affected if the judgments and assumptions underlying its models prove to be inaccurate or commodity prices otherwise fluctuate in ways that Allegheny does not anticipate.

Failure to retain and attract key executive officers and other skilled professionals and technical employees could have an adverse effect on Allegheny’s operations.

Allegheny’s business is dependent on its ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high. At the same time, Allegheny has an aging workforce. The inability to attract new employees, whether to appropriately replace retiring and other departing employees or otherwise, and to retain and motivate existing employees may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

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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 may have an adverse effect on its financial condition, cash flow and results of operations. See “Environmental Matters” and “Legal Proceedings.”

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” and Note 19, “Asset Retirement Obligations (“ARO”),” to Allegheny’s consolidated financial statements.

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. Recent results in the capital markets increased the level of underfunding in the pension plan. 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 and timing of such required cash contribution(s) 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, 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. Although Allegheny has made significant contributions to its pension plan in recent years, 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.

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 negative publicity, most recently in the context of the dialogue regarding climate change. Allegheny has come under some scrutiny in this regard, and also has faced public opposition in connection with its transmission expansion initiatives, as well as certain of its demand-side conservation efforts and ordinary utility rate increases. Negative publicity of this nature may make legislators, regulators and courts less likely to take a favorable view of energy companies in general and/or Allegheny, specifically, which could cause them to make decisions or take actions that are adverse to Allegheny.

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Risks Related to Allegheny’s Leverage and Financing Needs

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, decreases in market liquidity or the availability of credit, a downgrade in Allegheny’s credit ratings or other negative developments affecting Allegheny’s access to capital markets, could increase Allegheny’s cost of borrowing or could adversely affect its ability to access one or more financial markets. Causes of disruption to the capital markets could include, but are not limited to:

• a recession or other 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.

As widely reported, the financial markets and overall economies in the United States and abroad are currently undergoing a period of significant uncertainty and volatility. As a result, Allegheny’s management has placed increased emphasis on monitoring the risks associated with the current environment. At this point in time, there has not been a materially negative impact on Allegheny’s liquidity. However, there can be no assurance that the cost or availability of future borrowings or other financings, if any, will not be impacted by future capital market disruptions.

AE’s and AE Supply’s revolving credit facilities currently are well-diversified; at December 31, 2010, AE’s revolving credit facility included 18 lenders and AE Supply’s included 23 lenders. Additionally, West Penn, Monongahela, Potomac Edison, AGC and TrAIL Company each maintain separate revolving credit facilities that, overall, also include a diverse group of lenders. Allegheny currently anticipates that these lenders will participate in future requests for funding. However, there can be no assurance that negative developments in the credit markets or overall economy will not affect the ability of Allegheny’s lenders to meet their funding commitments. Additionally, Allegheny’s lenders have the ability to transfer their commitments to other institutions, and the risk that committed funds may not be available under distressed market conditions could be exacerbated to the extent that consolidation of the commitments under Allegheny’s facilities or among its lenders occurs.

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

Allegheny has substantial leverage. At December 31, 2010, Allegheny had approximately $4.7 billion of debt on a consolidated basis. Approximately $1.8 billion represented debt of AE Supply and AGC, $0.8 billion represented debt of TrAIL Company, and the remainder constituted debt of one or more of the Distribution Companies or their subsidiaries.

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

• 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;

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

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

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

Covenants contained in certain of Allegheny’s 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 (other than the proposed Merger with First Energy, for which Allegheny has obtained the requisite consent of the relevant lenders);

• make investments;

• dispose of assets; and

• pay dividends and other distributions on its equity securities.

These agreements may 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 leverage ratios. Allegheny’s failure to comply with the covenants contained in its financing agreements could result in an event of default, which may have an adverse effect on its financial condition.

A downgrade or negative outlook in Allegheny’s credit ratings could increase its financing costs and the cost of maintaining certain contractual relationships.

Allegheny cannot be assured that any of its current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in the agency’s judgment, circumstances in the future so warrant. Among other reasons, Allegheny’s credit ratings may change as a result of the differing methodologies used by various rating agencies or as a result of changes to those methodologies. Any downgrade or negative outlook in Allegheny’s credit ratings may increase its financing costs and the cost of maintaining certain contractual relationships. Among other things, if Allegheny’s credit ratings were to decline, it would likely be required to deposit additional cash or cash-equivalent collateral with its hedging counterparties, which would have a negative impact on Allegheny’s liquidity. Thus, a downgrade or negative outlook in Allegheny’s credit ratings may have an adverse effect on its business, results of operations, cash flows and financial condition.

AE has no income or cash flow apart from dividends paid or other obligations due it from its subsidiaries.

AE is a holding company and has no operations of its own. As a result, its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent upon the earnings and cash flow of its operating subsidiaries and their ability to pay dividends or make other distributions to, or repay loans from, AE. AE’s subsidiaries are distinct entities that have no obligations to make dividends or other distributions to AE, and their ability to do so is contingent upon their respective earnings and a number of other business considerations, including in some circumstances regulatory constraints.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.    PROPERTIES

Substantially all of Monongahela’s, Potomac Edison’s and West Penn’s properties are held subject to the lien of indentures securing their first mortgage bonds. Some of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations. Specifically, 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, West Penn 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 “Business—Electric Facilities,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and Note 9, “Capitalization and Debt,” to Allegheny’s 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 and its transmission headquarters in Fairmont, West Virginia, in buildings owned by Monongahela and TrAIL Company, respectively. Other ancillary offices exist throughout the Distribution Companies’ service territories.

ITEM 3.    LEGAL PROCEEDINGS

Allegheny is involved in a number of significant legal proceedings. In certain cases, plaintiffs seek to recover large and sometimes unspecified damages, and some matters may be unresolved for several years. Allegheny cannot currently determine the outcome of the proceedings described below or the ultimate amount of potential losses. Management provides for estimated losses to the extent that information becomes available indicating that losses are probable and that the amounts are reasonably estimable. Additional losses may have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Shareholder Actions

In connection with AE’s proposed Merger with a subsidiary of FirstEnergy, purported AE shareholders filed in the first quarter of 2010 several separate putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the United States District Court for the Western District of Pennsylvania against AE, its directors and certain of its officers (the “AE Defendants”), FirstEnergy and Merger Sub. The lawsuits alleged, among other things, that the AE directors breached their fiduciary duties by approving the Merger Agreement and that AE, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The lawsuits also alleged that the Merger consideration was unfair, that certain other terms in the Merger Agreement were unfair, and that certain individual defendants were financially interested in the Merger. Among other remedies, the lawsuits sought to enjoin the Merger, or in the event that an injunction was not awarded, money damages. While AE believed the lawsuits were without merit and defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants agreed to a disclosure-based settlement of the lawsuits.

In exchange for AE’s agreement with plaintiffs’ counsel to include additional disclosure in the joint proxy statement/prospectus mailed to AE’s and FirstEnergy’s shareholders in connection with the Merger, and subject to court approval, plaintiffs’ counsel agreed to, among other things, the dismissal of all claims asserted in the

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lawsuits and a release of claims related to the Merger on behalf of the putative class of AE shareholders. On December 13, 2010, the Maryland Circuit Court for Baltimore City approved the settlement and signed an order dismissing all claims. The Maryland court’s approval of the settlement is final and no longer subject to appeal, and the actions filed in Pennsylvania state court and the United States District Court for the Western District of Pennsylvania were also dismissed.

PJM Calculation Error

In March 2010, the Midwest ISO filed two complaints at FERC against PJM relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and the Midwest ISO since April 2005. The Midwest ISO claimed that this error resulted in PJM underpaying the Midwest ISO by approximately $130 million over the time period in question. Additionally, the Midwest ISO alleged that PJM did not properly trigger market-to-market settlements between PJM and the Midwest ISO during times when it was required to do so, which the Midwest ISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and Monongahela may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to the Midwest ISO complaints and PJM filed a related complaint at FERC against the Midwest ISO claiming that the Midwest ISO improperly called for market-to-market settlements several times during the same time period covered by the two Midwest ISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues in the dispute. The Offer of Settlement calls for the withdrawal of all pending complaints with no payments being made by any parties. Initial comments on the Offer of Settlement were filed at FERC on January 24, 2011.

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, NPC and other parties filed petitions for review of FERC’s June 26, 2003 order with the United States Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 19, 2006, the Ninth Circuit issued an opinion remanding the case to FERC to determine, in accordance with the guidance set forth in the Ninth Circuit’s opinion, whether FERC utilized the appropriate standard of review in deciding various claims, including NPC’s complaint. On May 3, 2007, AE Supply and others filed a petition to appeal the Ninth Circuit’s ruling to the United States Supreme Court. On June 26, 2008, the United States Supreme Court issued an opinion that rejected the Ninth Circuit’s reasoning, with instructions that the case be remanded to FERC for amplification or clarification of its findings on two issues set forth in the opinion. The case was remanded to FERC, and FERC issued an order on December 18, 2008 that provides for a paper hearing on the two issues identified by the United States Supreme Court, with initial filings due within 90 days and reply submissions within 90 days thereafter. However, the order holds those deadlines in abeyance, contingent upon settlement discussions between the parties, and a subsequent order lifting that stay has not been entered. On December 1, 2010, the parties filed with FERC a Joint Offer of Settlement that fully resolves all claims against AE Supply in this matter in exchange for a payment made by Merrill Lynch. By order dated January 31, 2011, FERC approved the settlement and terminated the docket.

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Claims by California Parties

On October 5, 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (“CDWR”) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers have filed motions to dismiss the Lockyer case. On March 18, 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On April 19, 2010, the California parties filed exceptions to the judge’s ruling with FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from FERC on the exceptions.

On June 2, 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their 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 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. Certain insurers have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. As of December 31, 2010, Allegheny is involved in three asbestos and/or environmental 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.), 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.) and Allegheny Energy, Inc., et al. v. Hartford Accident & Indemnity Company, Civil Action No. 10-CV-3142 WY (United States District Court, Eastern District of Pennsylvania). The parties are seeking a declaration of coverage under the policies for asbestos-related and environmental claims.

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. As of December 31, 2010, Allegheny’s total number of claims alleging exposure to asbestos was 886 in West Virginia, 11 in Pennsylvania and two in Illinois. Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

ICG Litigation

On December 28, 2006, AE Supply and Monongahela filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (“ICG”), Anker West Virginia Mining Company, Inc. (“Anker WV”), and Anker Coal Group, Inc. (“Anker Coal”). Anker WV entered into a long term

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Coal Sales Agreement with AE Supply and Monongahela for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants’ past and continued failure to supply the contracted coal, AE Supply and Mon Power have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held on January 10, 2011 through February 1, 2011. At trial, AE Supply and Monongahela presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. Post-trial filings are due on March 3, 2011, and no decision from the trial judge is expected before that time. AE Supply and Monongahela intend to vigorously pursue this matter but cannot predict its outcome.

Environmental Matters

In addition to the matters described above, Allegheny is involved in litigation relating to compliance with certain environmental laws and regulations. See “Environmental Matters.”

Ordinary Course of Business

AE and its subsidiaries are from time to time involved in litigation and other legal disputes in the ordinary course of business.

ITEM 4.    RESERVED.

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PART II

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

AE’s common stock is publicly traded. “AYE” is the trading symbol for AE’s common stock on the New York Stock Exchange. As of February 15, 2011, there were 15,587 holders of record of AE’s common stock. The table below shows the high and low sales prices of AE’s common stock in composite trading for the periods indicated:

	2010				2009
	High		Low		High		Low
1st Quarter	$	23.99	$	20.40	$	35.97	$	20.32
2nd Quarter	$	23.47	$	18.97	$	29.85	$	22.70
3rd Quarter	$	24.78	$	20.01	$	27.70	$	23.42
4th Quarter	$	25.44	$	22.78	$	27.15	$	21.84

In 2010, AE declared cash dividends of $0.15 per share on its common stock that were payable on March 22, June 21, September 27 and December 27, 2010, to shareholders of record on March 8, June 7, September 13 and December 13, 2010, respectively. In 2009, AE declared cash dividends of $0.15 per share on its common stock that were payable on March 23, June 22, September 28 and December 28, 2009, to shareholders of record on March 9, June 8, September 14 and December 14, 2009, respectively.

In addition, on December 21, 2010, AE declared a cash dividend on its common stock payable during the first quarter of 2011. If the proposed Merger does not become effective on or before March 14, 2011, a dividend of $0.15 per outstanding share of common stock will be payable on March 28, 2011 to stockholders of record at the close of business on March 14, 2011. If the proposed Merger is completed on or before March 14, 2011, a prorated dividend will be payable 14 days after the effective date of the Merger to stockholders of record at the close of business on the business day prior to the Merger effective date.

The amount and timing of dividends payable on AE’s common stock are within the sole discretion of AE’s Board of Directors. The Board of Directors reviews the dividend rate periodically in light of Allegheny’s financial position and results of operations, legislative and regulatory developments affecting Allegheny and the industry in general, overall market conditions and any other factors that the Board of Directors deems relevant. For a discussion regarding dividend restrictions, see Note 1, “Business, Basis of Presentation and Significant Accounting Policies,” and Note 9, “Capitalization and Debt,” to Allegheny’s consolidated financial statements.

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The following graph compares the cumulative 5-year total return provided shareholders on AE’s common stock relative to the cumulative total returns of the S&P 500 index and the Dow Jones US Electricity index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in AE’s common stock and in each of the indexes on December 31, 2005 and its relative performance is tracked through December 31, 2010.

	12/05		12/06		12/07		12/08		12/09		12/10
Allegheny Energy, Inc.		100.00		145.06		201.48		108.77		77.36		82.02
S&P 500		100.00		115.80		122.16		76.96		97.33		111.99
Dow Jones US Electricity		100.00		120.85		146.24		101.56		110.99		116.79

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

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ITEM 6.    SELECTED FINANCIAL DATA

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

	2010		2009		2008		2007		2006
(In millions, except per share amounts)
Income statement data for the year ended December 31:
Operating revenues	$	3,902.9	$	3,426.8	$	3,385.9	$	3,307.0	$	3,121.5
Operating expenses	$	2,971.4	$	2,507.0	$	2,576.4	$	2,489.7	$	2,389.2
Operating income	$	931.5	$	919.8	$	809.5	$	817.3	$	732.3
Income from continuing operations attributable to Allegheny Energy, Inc.	$	411.7	$	392.8	$	395.4	$	412.2	$	318.7
Income from discontinued operations, net of tax	$	0	$	0	$	0	$	0	$	0.6
Net income attributable to Allegheny Energy, Inc.	$	411.7	$	392.8	$	395.4	$	412.2	$	319.3
Weighted average number of diluted shares outstanding		170.3		170.0		170.0		169.5		168.7
Earnings per share attributable to Allegheny Energy, Inc.:
Income from continuing operations attributable to Allegheny Energy, Inc.
—Basic	$	2.42	$	2.32	$	2.35	$	2.48	$	1.94
—Diluted	$	2.42	$	2.31	$	2.33	$	2.43	$	1.89
Net income attributable to Allegheny Energy, Inc.
—Basic	$	2.42	$	2.32	$	2.35	$	2.48	$	1.94
—Diluted	$	2.42	$	2.31	$	2.33	$	2.43	$	1.89
Dividends declared per share of common stock (a)	$	0.75	$	0.60	$	0.60	$	0.15	$	0
Balance sheet data at December 31:
Property, plant and equipment, net	$	9,301.9	$	8,957.1	$	8,002.2	$	7,196.6	$	6,512.9
Total assets	$	12,089.3	$	11,589.1	$	10,811.0	$	9,906.6	$	8,552.4
Short-term debt	$	0	$	0	$	0	$	10.0	$	0
Long-term debt due within one year	$	15.5	$	140.8	$	93.9	$	95.4	$	201.2
Long-term debt	$	4,686.0	$	4,417.0	$	4,115.9	$	3,943.9	$	3,384.0
Total equity	$	3,441.7	$	3,128.1	$	2,855.7	$	2,548.6	$	2,115.1

(a) In each of 2010, 2009 and 2008, AE declared and paid four quarterly dividends, each in the amount of $0.15 per share. In 2010, AE also declared a quarterly dividend payable during the first quarter of 2011 in the amount of $0.15 per share or a lesser pro-rated amount if the proposed Merger with FirstEnergy becomes effective on or before March 14, 2011.

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

The primary purpose of Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is to provide information regarding Allegheny’s past and expected future performance in implementing its strategies and managing its risks and challenges. Allegheny’s MD&A includes the following sections:

• “Overview” includes a discussion of overall challenges and recent development and initiatives.

• “Results of Operations” provides an overview of Allegheny’s operating results in 2010, 2009 and 2008, including a review of earnings and results by reportable segment.

• “Financial Condition-Liquidity and Capital Resources” provides an analysis of Allegheny’s liquidity position and credit profile, including its sources of cash (including bank credit facilities and sources of operating cash flow) and uses of cash (including contractual obligations and capital expenditure requirements) and the key risks and uncertainties that impact Allegheny’s past and future liquidity position and financial condition.

• “Market Risk Information” describes significant market risks and credit risks to which Allegheny is exposed and Allegheny’s related risk management programs.

• “Application of Critical Accounting Policies” provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of Allegheny including those with respect to which management makes significant estimates, assumptions or other judgments.

OVERVIEW

Allegheny is an integrated energy business that owns and operates electric generation facilities primarily in Pennsylvania, West Virginia and Maryland. Additionally, Allegheny owns transmission assets in Pennsylvania, West Virginia, Maryland and Virginia and provides distribution services to customers in Pennsylvania, West Virginia and Maryland. See Note 1, “Business, Basis of Presentation and Significant Accounting Policies,” to Allegheny’s consolidated financial statements for more information.

Allegheny’s operations are aligned in two reportable segments, the Merchant Generation segment and the Regulated Operations segment. Allegheny changed the composition of its reportable segments during the fourth quarter of 2009, consistent with changes made to its management structure and the internal financial reporting used by its chief operating decision maker to regularly assess the performance of the business and allocate resources.

Pending Merger

On February 10, 2010, AE entered into an Agreement and Plan of Merger (as amended on June 4, 2010, the “Merger Agreement”) with FirstEnergy Corp. (“FirstEnergy”) and Element Merger Sub, Inc. (“Merger Sub”), a wholly owned subsidiary of FirstEnergy. Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into AE (the “Merger”), with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FirstEnergy. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended, and be tax-free to AE stockholders. Pursuant to the Merger Agreement, upon completion of the Merger, each issued and outstanding share of AE’s common stock, including grants of restricted stock, will automatically be converted into the right to receive 0.667 of a share of the common stock of FirstEnergy. This ratio is fixed, and the Merger Agreement does not provide for any adjustment to reflect stock price changes prior to completion of the Merger.

On July 16, 2010, FirstEnergy’s registration statement on Form S-4 containing a joint proxy statement/prospectus relating to the proposed Merger was declared effective by the SEC, and AE stockholders and

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FirstEnergy shareholders approved various proposals related to the Merger in separate shareholder meetings on September 14, 2010. The Virginia SCC approved the proposed Merger on September 9, 2010, the West Virginia PSC and FERC approved the Merger on December 16, 2010, and the Maryland PSC approved the Merger on January 18, 2011, subject to certain conditions. Additionally, on January 7, 2011, the DOJ notified AE and FirstEnergy that it had completed its review of the proposed Merger and closed its investigation.

Pursuant to the Merger Agreement, completion of the Merger remains subject to, among other customary closing conditions, approval by the Pennsylvania PUC. In October 2010, AE and FirstEnergy filed with the Pennsylvania PUC a comprehensive settlement that addresses the issues raised by a majority of the parties to the Merger proceedings in Pennsylvania. AE and FirstEnergy currently anticipate completing the Merger in the first quarter of 2011. See Note 2, “Merger Agreement,” to Allegheny’s consolidated financial statements and “Regulatory Framework Affecting Allegheny” for additional information.

The information included in this MD&A does not address or consider potential impacts or changes in Allegheny’s financial condition, business strategies or results of operations that may result from the completion of Allegheny’s anticipated Merger with FirstEnergy.

Business Segments

Allegheny’s business segments are as follows:

Merchant Generation Segment

The principal companies and operations in Allegheny’s Merchant Generation 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, including West Penn and Potomac Edison.

• AGC is owned approximately 59% by AE Supply and approximately 41% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC provides its share of the power generated by the Bath County generation facility to AE Supply and Monongahela in proportion to their ownership interests. Monongahela’s ownership interest in AGC is reflected as noncontrolling interest within the Merchant Generation segment and as an equity investment within the Regulated Operations segment.

Regulated Operations Segment

The principal companies and operations in Allegheny’s Regulated Operations segment include the following:

• The Distribution Companies include Monongahela, 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 owns and operates an electric T&D business and also owns and operates electric generation facilities in northern West Virginia.

• Potomac Edison owns and operates an electric T&D business in portions of West Virginia and Maryland and owns and operates a transmission business in Virginia.

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

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• TrAIL Company was formed in 2006 to develop, construct and operate transmission expansion projects, including the TrAIL Project.

• PATH, LLC was formed in 2007 by Allegheny and a subsidiary of AEP to develop, construct and operate the PATH Project. PATH, LLC is a series limited liability company. The “West Virginia Series” is owned equally by Allegheny and a subsidiary of AEP. The “Allegheny Series” is 100% owned by Allegheny.

All of Allegheny’s generation facilities are located within the PJM market. To facilitate the economic dispatch of generation, AE Supply and Monongahela sell power into the competitive wholesale energy market operated by PJM and purchase power from the PJM market to meet their obligations to supply power. See “Business” for more information regarding Allegheny’s business and the segments and subsidiaries discussed above.

Shared Services

AESC is a service company for AE that employs substantially all of the Allegheny personnel who provide services to AE and its subsidiaries, including AE Supply, AGC, the Distribution Companies, TrAIL Company, PATH, LLC and their respective subsidiaries. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had 4,211 employees as of December 31, 2010.

Certain Business Challenges

Allegheny faces a number of challenges and risks in its generation business, including electricity and capacity price risk, fuel supply and price risk, changes in electricity demand, competition from other electricity suppliers, changes in generating plant performance and evolving environmental and other regulations and requirements. Allegheny has executed and continues to enter into contracts for power sales and fuel supply purchase at varying prices and duration within established policies and guidelines. Allegheny’s future profitability will be affected by prevailing market conditions and the extent to and prices at which it has entered into intermediate or long-term power sales and fuel purchase agreements.

Allegheny manages the risks described above through various means, including risk-management programs that are designed to monitor and measure exposure to earnings and cash flow volatility related to changes in energy and fuel prices, counterparty credit quality and the operating performance of its generating units.

Allegheny also faces a number of challenges in its regulated utility business, including the challenge to maintain high quality customer service and reliability in a cost-effective manner. In addition, Allegheny’s regulated utility operations are subject to regulatory risk with respect to costs that may be recovered and investment returns that may be collected through regulated customer rates in each of its operating jurisdictions. See “Risk Factors.”

Although Allegheny has observed increased customer demand and increased market prices for power during 2010, the Company continues to face the ongoing effects of an economic downturn that began during the second half of 2008, including lower market prices for electricity, which have reduced realized revenues from the sale of unhedged generation output and, at times, caused Allegheny’s coal-fired plants to be placed in reserve status when they were otherwise available to generate power.

Certain Recent Developments and Initiatives

Initiatives and developments during 2010 included the following:

• Allegheny entered into a Merger Agreement with FirstEnergy in February 2010. Allegheny and FirstEnergy have obtained all of the regulatory approvals required to effect the proposed transaction,

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except for approval by the Pennsylvania PUC, with which Allegheny and FirstEnergy have filed a comprehensive settlement that addresses the issues raised by the majority of the parties to the merger proceedings.

• TrAIL Company completed construction of its new transmission operations center in Fairmont, West Virginia and continued the construction of its TrAIL transmission expansion project, which remains on schedule for a June 2011 in-service date.

• Potomac Edison sold its Virginia electric distribution business for cash proceeds of approximately $317 million.

• AE, TrAIL Company, Potomac Edison, West Penn and AGC each entered into new revolving credit facilities. Total available capacity under all revolving credit facilities was $1,766.9 million at December 31, 2010. Allegheny does not have any significant debt scheduled to mature prior to April 2012.

• Monongahela and Potomac Edison received approval for a June 29, 2010 base rate increase in West Virginia. See “Regulatory Environment Affecting Allegheny” and Note 5, “Rates and Regulation,” to Allegheny’s consolidated financial statements for additional information.

• In connection with the completion of the transition to market-based generation rates in Pennsylvania, West Penn conducted auctions to procure power to serve Pennsylvania customers and now has 80% of 2011, 52% of 2012 and 13% of 2013 residential power needs under contract. Potomac Edison conducted rolling auctions to procure its power supply for its Maryland customers. See “Business” and “Regulatory Framework Affecting Allegheny.”

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RESULTS OF OPERATIONS

Earnings attributable to AE by segment were as follows:

(In millions)	2010		2009		2008
Merchant Generation	$	163.1	$	234.0	$	324.3
Regulated Operations		247.7		157.9		70.2
Elimination of intercompany transactions		0.9		0.9		0.9
Consolidated net income attributable to Allegheny Energy, Inc.	$	411.7	$	392.8	$	395.4
Basic earnings per share	$	2.42	$	2.32	$	2.35
Diluted earnings per share	$	2.42	$	2.31	$	2.33

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Financial results for each segment were as follows:

(In millions)	Merchant Generation			Regulated Operations			Eliminations			Allegheny Consolidated
2010
Operating revenues	$	1,758.6		$	3,440.3		$	(1,296.0	)	$	3,902.9
Operating expenses:
Fuel		876.0			316.6			0			1,192.6
Purchased power and transmission		38.4			1,755.2			(1,290.7	)		502.9
Deferred energy costs, net		0			38.1			0			38.1
Gain on sale of Virginia distribution business		0			(44.6	)		0			(44.6	)
Operations and maintenance		250.7			487.5			(5.3	)		732.9
Depreciation and amortization		129.7			195.5			(1.7	)		323.5
Taxes other than income taxes		51.2			174.8			0			226.0
Total operating expenses		1,346.0			2,923.1			(1,297.7	)		2,971.4
Operating income		412.6			517.2			1.7			931.5
Other income (expense), net		3.6			22.2			(12.5	)		13.3
Interest expense		145.8			173.7			(3.1	)		316.4
Income before income taxes		270.4			365.7			(7.7	)		628.4
Income tax expense		98.7			118.0			0			216.7
Net income		171.7			247.7			(7.7	)		411.7
Net income attributable to noncontrolling interests		(8.6	)		0			8.6			0
Net income attributable to Allegheny Energy, Inc.	$	163.1		$	247.7		$	0.9		$	411.7
2009
Operating revenues	$	1,608.6		$	3,051.2		$	(1,233.0	)	$	3,426.8
Operating expenses:
Fuel		675.5			211.1			0			886.6
Purchased power and transmission		26.4			1,702.8			(1,227.2	)		502.0
Deferred energy costs, net		0			(64.4	)		0			(64.4	)
Operations and maintenance		247.0			445.9			(5.8	)		687.1
Depreciation and amortization		106.8			177.1			(1.8	)		282.1
Taxes other than income taxes		47.2			166.4			0			213.6
Total operating expenses		1,102.9			2,638.9			(1,234.8	)		2,507.0
Operating income		505.7			412.3			1.8			919.8
Other income (expense), net		1.0			17.1			(11.1	)		7.0
Interest expense		134.9			157.4			(1.2	)		291.1
Income before income taxes		371.8			272.0			(8.1	)		635.7
Income tax expense		128.8			112.8			0			241.6
Net income		243.0			159.2			(8.1	)		394.1
Net income attributable to noncontrolling interests		(9.0	)		(1.3	)		9.0			(1.3	)
Net income attributable to Allegheny Energy, Inc.	$	234.0		$	157.9		$	0.9		$	392.8

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(In millions)	Merchant Generation			Regulated Operations			Eliminations			Allegheny Consolidated
2008
Operating revenues	$	1,792.9		$	2,855.3		$	(1,262.3	)	$	3,385.9
Operating expenses:
Fuel		793.4			287.5			0			1,080.9
Purchased power and transmission		30.3			1,622.3			(1,257.0	)		395.6
Deferred energy costs, net		0			(63.7	)		0			(63.7	)
Operations and maintenance		222.1			458.0			(5.3	)		674.8
Depreciation and amortization		94.1			181.9			(2.1	)		273.9
Taxes other than income taxes		47.6			167.3			0			214.9
Total operating expenses		1,187.5			2,653.3			(1,264.4	)		2,576.4
Operating income		605.4			202.0			2.1			809.5
Other income (expense), net		7.8			28.6			(14.1	)		22.3
Interest expense		99.7			135.6			(3.4	)		231.9
Income before income taxes		513.5			95.0			(8.6	)		599.9
Income tax expense		179.7			24.4			0			204.1
Net income		333.8			70.6			(8.6	)		395.8
Net income attributable to noncontrolling interests		(9.5	)		(0.4	)		9.5			(0.4	)
Net income attributable to Allegheny Energy, Inc.	$	324.3		$	70.2		$	0.9		$	395.4

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MERCHANT GENERATION SEGMENT

Selected financial results for the Merchant Generation segment were as follows:

(In millions)	2010		2009		2008
Operating revenues	$	1,758.6	$	1,608.6	$	1,792.9
Operating income	$	412.6	$	505.7	$	605.4
Income before income taxes	$	270.4	$	371.8	$	513.5

The following is a summary of certain statistical information relating to the Merchant Generation segment that is regularly reviewed by its management:

	2010			2009			2008			2010/2009 Change			2009/2008 Change
Market prices:
Round-the-clock energy price ($/MWh, PJM Western Hub) (a)	$	46.58		$	38.75		$	69.81			20.2	%		(44.5	)%
Round-the-clock energy price ($/MWh, PJM AD Hub) (a)	$	37.58		$	32.98		$	53.19			13.9	%		(38.0	)%
Natural gas price-Henry Hub NYMEX ($/MMBtu)	$	4.37		$	3.92		$	8.84			11.5	%		(55.7	)%
Allegheny operating statistics:
Realized energy price ($/MWh) (b)	$	38.77		$	36.06		$	55.56			7.5	%		(35.1	)%
Supercritical Coal Units:
kWhs generated (in millions)		26,625			22,375			29,380			19.0	%		(23.8	)%
Equivalent Availability Factor (EAF) (d)		81.5	%		79.9	%		87.6	%		1.6	%		(7.7	)%
Net Capacity Factor (NCF) (e)		68.7	%		57.8	%		75.6	%		10.9	%		(17.8	)%
Station O&M (in millions) (f):
Base and operations	$	83.6		$	82.6		$	77.5			1.2	%		6.6	%
Special maintenance		43.9			55.5			27.3			(20.9	)%		103.3	%
Total Station O&M	$	127.5		$	138.1		$	104.8			(7.7	)%		31.8	%
All Generating Units:
kWhs generated (in millions) (c)		32,051			26,004			34,464			23.3	%		(24.5	)%
EAF (d)		83.8	%		82.3	%		87.9	%		1.5	%		(5.6	)%
NCF (e)		50.9	%		41.3	%		54.9	%		9.6	%		(13.6	)%
Station O&M (in millions):
Base and operations	$	123.3		$	123.5		$	116.4			(0.2	)%		6.1	%
Special maintenance		49.2			62.3			40.8			(21.0	)%		52.7	%
Total Station O&M	$	172.5		$	185.8		$	157.2			(7.2	)%		18.2	%

(a) Represents the historical round-the-clock energy prices for the PJM Western Hub and PJM AEP-Dayton Hub, which management periodically considers when reviewing price trends within Allegheny’s region of PJM.

(b) Represents the weighted average actual price received at the generation facility for power sold into PJM by Allegheny’s Merchant Generation plants.

(c) Excludes kWhs consumed by pumping at the Bath County, Virginia hydroelectric station.

(d) EAF represents the average available generating capacity expressed as a percentage of total generating capacity. This measure is commonly less than 100%, primarily due to planned and unplanned outages and derates.

(e) NCF is a measure of actual net electricity generated compared to the amount of electricity that could have been generated at maximum operating capacity. This measure is less than 100% due to periods during which generating capacity is not available as a result of planned and unplanned outages, as well as periods during

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which generating capacity is available, but is not dispatched because of the availability in the market of lower cost generation in amounts sufficient to meet demand.

(f) Station O&M includes base, operations and special maintenance costs. Base and operations costs consist of normal recurring expenses related to the ongoing operation of the generation facilities. Special maintenance costs include costs associated with outage-related maintenance and projects that relate to the generation facilities.

Forward prices at December 31, 2010 for certain commodities in Allegheny’s region were as follows:

	Forward Market Prices (a)
	2011		2012		2013
Round-the-clock energy price-PJM Western Hub ($/MWh)	$	44.88	$	46.08	$	47.98
Round-the-clock energy price-PJM AD Hub ($/MWh)	$	36.63	$	39.22	$	42.06
Natural gas price-Henry Hub NYMEX ($/MMBtu)	$	4.49	$	5.02	$	5.30

(a) Based on average prices at December 31, 2010.

The performance of Allegheny’s Merchant Generation segment is significantly impacted by changes in prices for power and for commodities that underlie the generation of electric power, such as coal and natural gas. Market prices for power and related commodities are volatile and difficult to predict. Changes in such prices result from changes in supply and demand, fuel costs, market liquidity, weather, environmental regulation and other factors. In lower power price environments, Allegheny may generate less power because of the increased amount of time during which it is not economical to run its generating units.

To manage exposure to market price changes, Allegheny sells and purchases physical energy at the wholesale and retail level and enters into various economic hedges within established risk management objectives and policies, some of which do not qualify for cash flow hedge accounting treatment. The following table shows the percentages of Allegheny’s estimated future power sales and coal purchases that were hedged as of December 31, 2010:

	2011			2012			2013
Percentage of expected coal-fired generation sales hedged		79	%		30	%		7	%
Percentage of expected coal purchases hedged		97	%		67	%		58	%

Operating Revenues

Merchant Generation operating revenues were as follows:

(In millions)	2010			2009			2008
PJM energy revenue (all generation)	$	1,240.2		$	936.5		$	1,913.1
PJM capacity revenue		403.6			356.2			195.2
Power hedge revenue, net:
Power sale revenue-affiliated contracts		1,264.6			1,198.7			1,210.6
Power sale revenue-nonaffiliated contracts		175.6			73.6			77.9
Power purchased from PJM to serve contracts		(1,347.2	)		(1,177.6	)		(1,626.7	)
Realized gains (losses) on financial hedges		(12.6	)		118.8			(25.6	)
Power hedge revenue, net		80.4			213.5			(363.8	)
Other, including unrealized gains (losses) on hedge instruments		34.4			102.4			48.4
Total operating revenues	$	1,758.6		$	1,608.6		$	1,792.9

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Total operating revenues increased $150.0 million in 2010 compared to 2009, primarily due to a $303.7 million increase in PJM energy revenue and a $47.4 million increase in PJM capacity revenue, partially offset by a $133.1 million decrease in power hedge revenue, net and a $68.0 million decrease in other revenues, including unrealized gains (losses) on hedge instruments.

Total operating revenues decreased $184.3 million in 2009 compared to 2008, primarily due to a $976.6 million decrease in PJM energy revenue, partially offset by a $577.3 million increase in power hedge revenue, a $161.0 million increase in PJM capacity revenue and a $54.0 million increase in other revenues, including unrealized gains (losses) on hedge instruments.

PJM Energy Revenue

PJM energy revenue represents the sale into PJM of all power produced by the Merchant Generation segment. PJM energy revenue increased $303.7 million in 2010 compared to 2009, primarily due to higher generation output and higher prices. The segment’s generation output was 23.3% higher in 2010 compared to 2009 and its realized energy price increased 7.5% in 2010 compared to 2009. In addition, the segment’s supercritical capacity factor, representing the MWhs actually generated compared to the amount of electricity that could have been generated at maximum operating capacity, increased to 68.7% in 2010 compared to 57.8% in 2009.

PJM energy revenue decreased $976.6 million in 2009 compared to 2008, resulting from significantly lower demand for electricity and lower natural gas and power prices. The segment’s generation output was 24.5% lower in 2009 compared to 2008, its realized energy price decreased 35.1% in 2009 compared to 2008 and its supercritical plant capacity factor decreased to 57.8% in 2009 compared to 75.6% in the prior year.

PJM Capacity Revenue

PJM capacity revenue represents payments received from PJM based on Allegheny’s available generation capacity and capacity prices as determined under the PJM RPM auction process. PJM capacity revenue increased $47.4 million in 2010 compared to 2009 and increased $161.0 million in 2009 compared to 2008 as a result of increased capacity prices.

PJM has conducted RPM capacity auctions through the planning year ending May 31, 2014. For Allegheny’s region of PJM, average capacity auction prices per MW-day for the planning years ending May 31, 2008, 2009, 2010, 2011, 2012, 2013 and 2014 were $41, $112, $191, $174, $110, $16 and $28, respectively.

Power Hedge Revenue, Net

Power sale revenue-affiliated contracts.  Power sale revenue-affiliated contracts, which represents sales of power by the Merchant Generation segment to West Penn and Potomac Edison under power sales contracts, increased $65.9 million in 2010 compared to 2009, primarily due to increased revenues in Pennsylvania resulting from higher sales volumes and higher generation rates charged to Pennsylvania customers, which were passed on to AE Supply under the terms of a power supply contract between West Penn and AE Supply. These increases in revenue were partially offset by a reduction in affiliated power sale revenue due to Potomac Edison’s June 1, 2010 sale of the Virginia distribution business to the Co-Ops. Beginning June 1, 2010, power sales between the Merchant Generation segment and the Co-Ops is being recorded in power sale revenue-nonaffiliated contracts. Prior to the sale of the Virginia distribution business, these sales were classified as affiliated revenue.

Power sale revenue-affiliated contracts decreased $11.9 million in 2009 compared to 2008 primarily due to decreased revenues resulting from Maryland residential customers going to market on January 1, 2009 and AE Supply winning a portion of the load contracts, as well as decreased revenues in Virginia due to lower demand, partially offset by increased revenues in Pennsylvania due to higher generation rates charged to Pennsylvania customers, which were passed on to AE Supply under the terms of a power supply contract between West Penn and AE Supply.

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Power sale revenue-nonaffiliated contracts.  Power sale revenue-nonaffiliated contracts, which represents sales of power by the Merchant Generation segment to third parties under power sales contracts, increased $102.0 million in 2010 compared to 2009, primarily due to the June 1, 2010 sale of Potomac Edison’s Virginia distribution business. Beginning June 1, 2010, power sales between the Merchant Generation segment and the Co-Ops are being recorded in power sale revenue-nonaffiliated contracts. Prior to the sale of the Virginia distribution business, these sales were classified as affiliated revenue.

Power purchased from PJM to serve affiliated and nonaffiliated contracts.  Power purchased from PJM to serve affiliated and nonaffiliated contracts increased $169.6 million in 2010 compared to 2009, primarily due to higher power prices and higher sales volumes.

Power purchased from PJM to serve affiliated and nonaffiliated contracts decreased $449.1 million in 2009 compared to 2008, primarily due to a decrease in market prices as well as decreased customer load, partially offset by an increase in capacity costs.

Realized gains (losses) on financial hedges.  Realized gains (losses) on financial hedges decreased $131.4 million in 2010 compared to 2009, primarily due to reduced gains on power sales hedges, partially offset by a reduction in losses on power purchase hedges. These reductions resulted from lower margins between contract price and market price in 2010 compared to 2009.

Realized gains (losses) on financial hedges increased by $144.4 million in 2009 compared to 2008 due to an increase in margin on the hedges as a result of a decrease in market prices.

Other Revenues

Other revenues decreased $68.0 million in 2010 compared to 2009, primarily due to unrealized losses on power sale hedges and pipeline capacity economic hedges that did not qualify for hedge accounting, partially offset by unrealized gains on FTRs.

Other revenues increased $54.0 million for 2009 compared to 2008 primarily due to unrealized gains on FTRs.

Operating Expenses

Fuel: Fuel expense represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power, as well as emission allowances, fuel handling and residual disposal costs. Fuel expense was as follows:

(In millions)	2010		2009		2008
Fuel	$	876.0	$	675.5	$	793.4

Fuel expense increased $200.5 million in 2010 compared to 2009, primarily due to:

• a $162.3 million increase in coal expense resulting from a 23.4% increase in tons of coal consumed and a 4.9% increase in the average cost of coal per ton,

• a $23.8 million increase in lime and other fuel expenses, primarily related to the operation of Scrubbers for a full year and

• a $14.3 million increase in natural gas expense resulting from a 30.6% increase in decatherms of natural gas consumed and a 17.8% increase in the average price of natural gas per decatherm.

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Fuel expense decreased $117.9 million in 2009 compared to 2008, primarily due to a $107.7 million decrease in coal expense, resulting from a 27.1% decrease in tons of coal consumed at Allegheny’s merchant coal-fired generation facilities, partially offset by a 14.7% increase in the average cost of coal per ton.

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

(In millions)	2010		2009		2008
Purchased power and transmission	$	38.4	$	26.4	$	30.3

Purchased power and transmission expense increased $12.0 million in 2010 compared to 2009, primarily due to a $10.6 million gain during the fourth quarter of 2009 on the effective settlement of power purchase agreements in connection with the purchase of certain hydroelectric generation facilities that did not recur during 2010.

Purchased power and transmission expense decreased $3.9 million in 2009 compared to 2008, primarily due to a $10.6 million gain on the effective settlement of power purchase agreements in connection with the purchase of certain hydroelectric generation facilities, partially offset by costs relating to a hedge strategy associated with a natural gas transportation agreement between AE Supply and Kern River Gas Transmission Company.

Operations and Maintenance:  Operations and maintenance expenses 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)	2010		2009		2008
Operations and maintenance	$	250.7	$	247.0	$	222.1

Operations and maintenance expenses increased $3.7 million in 2010 compared to 2009, primarily due to $13.5 million of expenses related to the proposed Merger with FirstEnergy and a $6.7 million credit to operations and maintenance expense during 2009 relating to the purchase of certain hydroelectric generation facilities that did not recur in 2010, partially offset by lower plant maintenance expense.

Operations and maintenance expenses increased $24.9 million in 2009 compared to 2008, primarily due to an increase in costs resulting from the timing of plant maintenance, partially offset by a $6.7 million credit to operations and maintenance expense relating to the purchase of certain hydroelectric generation facilities.

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

(In millions)	2010		2009		2008
Depreciation and amortization	$	129.7	$	106.8	$	94.1

Depreciation and amortization expenses increased $22.9 million in 2010 compared to 2009 and increased $12.7 million in 2009 compared to 2008, primarily due to the depreciation of Scrubber equipment that was placed into service in June 2009 at the Hatfield’s Ferry generating facility.

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

(In millions)	2010		2009		2008
Taxes other than income taxes	$	51.2	$	47.2	$	47.6

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Taxes other than income taxes increased $4.0 million in 2010 compared to 2009, primarily due to a tax refund received during 2009.

Other Income (Expense), net

Other income (expense), net was as follows:

(In millions)	2010		2009		2008
Other income (expense), net	$	3.6	$	1.0	$	7.8

Other income (expense), net increased $2.6 million in 2010 compared to 2009 and decreased $6.8 million in 2009 compared to 2008, primarily due to changes in interest income resulting from average investment balances.

Interest Expense

Interest expense was as follows:

(In millions)	2010		2009		2008
Interest expense	$	145.8	$	134.9	$	99.7

Interest expense increased $10.9 million in 2010 compared to 2009, primarily due to decreased capitalized interest expense resulting from capital projects that were completed and placed into service, including the Scrubber equipment at the Hatfield’s Ferry generating facility, higher average interest rates and increased commitment fees associated with AE Supply’s revolving credit facility. These increases were partially offset by lower interest expense from decreased average outstanding debt and lower debt redemption expenses.

Interest expense increased $35.2 million in 2009 compared to 2008, primarily due to costs associated with AE Supply’s September 2009 and October 2009 repurchases of outstanding medium-term notes.

See Note 9, “Capitalization and Debt,” to Allegheny’s consolidated financial statements for additional information.

Income Tax Expense

Income tax expense of $98.7 million for 2010 resulted in an effective tax rate of 36.5%. Income tax expense for 2010 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to the effect of state income taxes, which increased the rate by 4.6%, partially offset by adjustments to the liability for uncertain tax positions, which decreased the rate by 2.4%.

Income tax expense of $128.8 million for 2009 resulted in an effective tax rate of 34.6%. Income tax expense for 2009 was lower than income tax expense calculated at the federal statutory tax rate of 35%, primarily due to an adjustment to the Pennsylvania net operating loss carryforward deferred tax asset resulting from a Pennsylvania tax law change, which decreased the rate by 3.0%, and investment tax credits, which reduced the rate by 0.2%, partially offset by state taxes, which increased the rate by 2.8%.

Income tax expense of $179.7 million for 2008 resulted in an effective tax rate of 35.0%, which was equal to the federal statutory tax rate. Changes in tax reserves related to uncertain tax positions and audit settlements increased the effective rate by 0.9%. This increase was offset by state and other income taxes, which decreased the rate by 0.9%.

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REGULATED OPERATIONS SEGMENT

Selected financial results for the Regulated Operations segment were as follows:

(In millions)	2010		2009		2008
Operating revenues	$	3,440.3	$	3,051.2	$	2,855.3
Operating income	$	517.2	$	412.3	$	202.0
Income before income taxes	$	365.7	$	272.0	$	95.0

The performance of Allegheny’s Regulated Operations segment is significantly impacted by customer demand for electricity, regulatory ratemaking actions and the progress of its transmission expansion projects. Retail electricity sales, including sales by Potomac Edison’s Virginia distribution business, which Potomac Edison sold on June 1, 2010, were as follows:

	2010		2009		2008		2010/2009 Change			2009/2008 Change
Retail electricity sales (million kWhs)		42,389		42,040		44,192		0.8	%		(4.9	)%

Retail electricity sales, excluding sales by the Virginia distribution business, which Potomac Edison sold on June 1, 2010, were as follows:

	2010		2009		2008		2010/2009 Change			2009/2008 Change
Retail electricity sales (million kWhs)		41,107		39,100		41,116		5.1	%		(4.9	)%

In addition to retail electricity sales, management monitors the performance of the Regulated Operations segment based in part on certain statistical information including the following:

	Normal		2010		2009		2008		2010/2009 Change			2009/2008 Change
Revenue per MWh sold (a)		N/A	$	78.27	$	72.80	$	61.14		7.5	%		19.1	%
O&M per MWh sold (b)		N/A	$	11.18	$	10.27	$	10.16		8.9	%		1.1	%
HDD (c)		5,516		5,327		5,225		5,324		2.0	%		(1.9	)%
CDD (c)		811		1,208		816		772		48.0	%		5.7	%
kWhs generated (million kWhs) (d)		N/A		10,899		7,526		12,137		44.8	%		(38.0	)%

(a) This measure is calculated by dividing total revenues from retail sales of electricity by retail electricity sales.

(b) This measure is calculated by dividing total O&M, excluding O&M related to transmission expansion, which is recovered in formula rates, by retail electricity sales.

(c) 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, representing one of several factors that impact the volume of electricity delivered. Accordingly, deviations in weather from normal levels can affect Allegheny’s financial performance. 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. HDD and CDD are most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive.

(d) Represents kWhs generated by Monongahela’s regulated generation facilities.

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Operating Revenues

Regulated Operation revenues were as follows:

(In millions)	2010			2009			2008
Retail electric:
Generation and ancillary	$	2,500.3		$	2,280.0		$	1,902.7
Transmission		118.4			118.6			124.2
Distribution		698.9			661.7			675.1
Total retail electric		3,317.6			3,060.3			2,702.0
Transmission services and bulk power:
PJM revenue, net		(151.6	)		(198.8	)		(34.2	)
Warrior Run generation revenue		64.5			52.7			86.0
Transmission and other		171.7			100.1			73.2
Total transmission services and bulk power		84.6			(46.0	)		125.0
Other		38.1			36.9			28.3
Total operating revenues	$	3,440.3		$	3,051.2		$	2,855.3

Total operating revenues increased $389.1 million in 2010 compared to 2009, primarily due to a $257.3 million increase in retail electric revenues and a $130.6 million increase in transmission services and bulk power revenues.

Total operating revenues increased $195.9 million in 2009 compared to 2008, primarily due to a $358.3 million increase in retail electric revenues, partially offset by a $171.0 million decrease in transmission services and bulk power revenues.

Retail Electric

Retail electric revenues increased $257.3 million in 2010 compared to 2009, primarily due to:

• a $137.9 million increase resulting from higher generation rates charged to Pennsylvania customers,

• a $105.9 million increase related to the January 2010 fuel and purchased power costs rate adjustment in West Virginia,

• an approximately $21 million increase related to the June 2010 base rate increase in West Virginia and

• increased revenues resulting from a 5.1% increase in MWhs sold, excluding MWhs sold by the Virginia distribution business.

Retail electric revenues increased $358.3 million in 2009 compared to 2008, primarily due to:

• a $173.1 million increase in Pennsylvania operating revenues resulting from higher generation rates charged to Pennsylvania customers,

• a $149.4 million increase primarily related to the January 2009 fuel and purchased power costs rate adjustment in West Virginia,

• a $118.4 million increase in Maryland generation revenues primarily resulting from market-based generation pricing for residential customers effective January 1, 2009 and

• a $98.3 million increase due to higher rates under ratemaking settlements in Virginia.

These increases were partially offset by:

• a $102.0 million decrease in retail revenue related to reduced customer demand and

• a $38.5 million decrease due to the expiration of an earnings benefit related to stranded cost recovery in Pennsylvania.

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Transmission Services and Bulk Power

Transmission services and bulk power revenues increased $130.6 million in 2010 compared to 2009, primarily due to:

• a $71.6 million increase in transmission and other revenues resulting primarily from increased returns earned on construction work in progress relating to transmission expansion projects and

• a $47.2 million increase in PJM revenue, net resulting from increased sales of electricity into PJM at higher prices by Allegheny’s regulated generation facilities, partially offset by increased purchases of electricity from PJM at higher prices to serve power supply contracts.

Transmission services and bulk power revenues decreased $171.0 million in 2009 compared to 2008, primarily due to:

• a $164.6 million decrease in PJM revenue, net, due to lower sales into PJM as a result of significantly lower demand and a decrease in the market price of power, partially offset by decreased purchases of electricity from PJM due to a decrease in the market price of power and decreased customer demand,

• a $33.3 million decrease in revenues from the Warrior Run generating facility primarily resulting from the timing of maintenance outages at the facility,

• partially offset by a $26.9 million increase in transmission and other revenues as a result of increased recoverable expenses and returns on investment that are related to transmission expansion.

Operating Expenses

Fuel: Fuel expense represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power, as well as emission allowances, fuel handling and residual disposal costs. Fuel expense was as follows:

(In millions)	2010		2009		2008
Fuel	$	316.6	$	211.1	$	287.5

Fuel expense increased $105.5 million in 2010 compared to 2009, primarily due to:

• a $96.5 million increase in coal expense resulting from a 45.3% increase in tons of coal consumed and a 3.8% increase in the average cost of coal per ton and

• a $9.0 million increase in lime and other fuel expenses, primarily resulting from the operation of Scrubbers at the Fort Martin generating facility, which were placed into service during the fourth quarter of 2009.

Fuel expense decreased $76.4 million in 2009 compared to 2008, primarily due to:

• a $65.3 million decrease in coal expense resulting from a 39.1% decrease in tons of coal consumed, partially offset by a 22.2% increase in the average cost of coal per ton and

• an $8.5 million decrease in emission allowance expense.

Purchased Power and Transmission:  Purchased power and transmission expense represents power purchased from AE Supply and third-party suppliers, including purchases from qualifying facilities under PURPA. Purchased power and transmission expense was as follows:

(In millions)	2010		2009		2008
Purchased power and transmission	$	1,755.2	$	1,702.8	$	1,622.3

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Purchased power and transmission expense increased $52.4 million in 2010 compared to 2009, primarily due to a $162.3 million increase resulting from higher generation rates paid under the terms of a power supply agreement between West Penn and AE Supply and increased customer demand, partially offset by a $123.6 million decrease in purchased power resulting from the June 1, 2010 sale of Potomac Edison’s Virginia distribution business.

Purchased power and transmission expense increased $80.5 million in 2009 compared to 2008, primarily due to:

• a $97.7 million increase, primarily due to higher rates paid under the terms of market-based power purchase contracts to supply Maryland residential customers effective January 1, 2009, partially offset a reduction in power purchased resulting from reduced customer demand and

• an $84.1 million increase due to higher generation rates paid under the terms of a power supply agreement between West Penn and AE Supply, partially offset by a reduction in power purchased resulting from reduced customer demand.

These increases were partially offset by:

• a $50.0 million decrease related to the expiration of an intercompany market rate adjustment in Pennsylvania,

• a $15.2 million decrease in purchased power from PURPA facilities, primarily resulting from the timing of maintenance outages at the Warrior Run PURPA generation facility and

• a $15.0 million decrease primarily due to lower rates paid under the terms of market-based power purchase contracts to supply Virginia residential customers.

Deferred Energy Costs, net:  Deferred energy costs, net represent an adjustment of actual costs incurred during the period for amounts that are expected to be charged or credited to customers in rates in a future period under a regulatory mechanism. The components of deferred energy costs were as follows:

(In millions)	2010			2009			2008
AES Warrior Run PURPA generation	$	(2.5	)	$	(15.3	)	$	9.3
ENEC related costs		50.6			(49.9	)		(71.7	)
Market-based generation and other costs		(10.0	)		0.8			(1.3	)
Deferred energy costs, net	$	38.1		$	(64.4	)	$	(63.7	)

ENEC Costs.  Under the annual ENEC method of recovering net power supply costs in West Virginia, including fuel costs, purchased power costs and other related expenses, net of related revenue and interest earnings on the Fort Martin Scrubber project escrow fund, Monongahela and Potomac Edison track actual costs and revenues for under and/or over-recoveries, and generally file requests for revised ENEC rates on an annual basis. Any under-recovery and/or over-recovery of costs, net of related revenues, is deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability, with the corresponding impact on the consolidated statements of income reflected in “Deferred energy costs, net.”

AES Warrior Run PURPA Generation.  To satisfy certain of its obligations under PURPA, Potomac Edison entered into a long-term contract beginning July 1, 2000 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. Any under-recovery or over-recovery of net costs is being deferred pending subsequent recovery from, or return to, customers through adjustments to this surcharge.

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Market-based Generation and Other Costs.  Potomac Edison is authorized by the Maryland PSC to recover the costs of the generation component of power sold to certain residential, commercial and industrial customers that did not choose a third-party alternative generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet for any under-recovery or over-recovery of the generation component of costs charged to these customers. In addition, under an order by the Virginia PSC, Potomac Edison was permitted a rate adjustment to recover a portion of any increased purchased power costs. Following the June 1, 2010 sale of Potomac Edison’s Virginia distribution business, the Cooperatives became responsible for providing power to customers in Virginia. See Note 4, “Sale of Virginia Distribution Business” to Allegheny’s consolidated financial statements for additional information.

Gain on Sale of Virginia distribution business:  The June 1, 2010 sale of Potomac Edison’s Virginia distribution business resulted in a $44.6 million pre-tax gain. See Note 4, “Sale of Virginia Distribution Business” to Allegheny’s consolidated financial statements for additional information.

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)	2010		2009		2008
Operations and maintenance	$	487.5	$	445.9	$	458.0

Operations and maintenance expenses increased $41.6 million in 2010 compared to 2009, primarily due to:

• $26.1 million of expenses related to AE’s proposed Merger with FirstEnergy,

• a $12.1 million increase in restore service costs resulting from severe storms, net of a $7.9 million credit recorded for West Virginia storm costs that were permitted to be recovered under the June 2010 West Virginia rate order and

• increased costs relating to energy efficiency programs, which are recovered in customer rates.

These increases were partially offset by a $9.5 million decrease related to a litigation settlement during the fourth quarter of 2010 and decreased expenditures resulting from the June 1, 2010 sale of the Virginia distribution business.

Operations and maintenance expenses decreased $12.1 million in 2009 compared to 2008, primarily due to decreased costs associated with the timing of plant maintenance.

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

(In millions)	2010		2009		2008
Depreciation and amortization	$	195.5	$	177.1	$	181.9

Depreciation and amortization expenses increased $18.4 million in 2010 compared to 2009, primarily due to the depreciation of Scrubbers that were placed into service at the Fort Martin generating facility during the fourth quarter of 2009.

Depreciation and amortization expenses decreased $4.8 million in 2009 compared to 2008, primarily due to an $8.2 million decrease in amortization related to regulatory assets, partially offset by a $3.5 million increase in depreciation expense resulting from the depreciation of Scrubbers that were placed into service at the Fort Martin generating facility during the fourth quarter of 2009.

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

(In millions)	2010		2009		2008
Taxes other than income taxes	$	174.8	$	166.4	$	167.3

Taxes other than income taxes increased $8.4 million in 2010 compared to 2009, primarily due to increased gross receipts taxes in Pennsylvania resulting from higher taxable revenues during 2010 and higher fuel tax rates in Maryland during 2010, partially offset by decreased tax reserves.

Other Income (Expense), net

Other income (expense), net was as follows:

(In millions)	2010		2009		2008
Other income (expense), net	$	22.2	$	17.1	$	28.6

Other income (expense), net increased $5.1 million in 2010 compared to 2009, primarily due to equity earnings related to Allegheny’s investment in PATH-WV.

Other income (expense), net decreased $11.5 million in 2009 compared to 2008, primarily due to decreased interest income on investments resulting from lower investment balances and interest rates.

Interest Expense

Interest expense was as follows:

(In millions)	2010		2009		2008
Interest expense	$	173.7	$	157.4	$	135.6

Interest expense increased $16.3 million in 2010 compared to 2009, primarily due to increased net borrowings by TrAIL Company, partially offset by lower interest expense related to the repayment of $110 million of medium-term notes by Monongahela in January 2010.

Interest expense increased $21.8 million in 2009 compared to 2008, primarily due to Monongahela’s December 2008 issuance of $300 million of first mortgage bonds and borrowings under TrAIL Company’s credit facility.

See Note 9, “Capitalization and Debt,” to Allegheny’s consolidated financial statements for additional information.

Income Tax Expense

Income tax expense of $118.0 million for 2010 resulted in an effective tax rate of 32.3%. Income tax expense for 2010 was lower than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to adjustments to the liability for uncertain tax positions, which decreased the rate by 5.4%, offset by state income taxes, which increased the rate by 3.8%.

Income tax expense of $112.8 million for 2009 resulted in an effective tax rate of 41.5%. Income tax expense for 2009 was higher than income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state taxes, which increased the rate by 5.0% and the segment’s share of consolidated income tax expense, which increased the rate by 2.5%.

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Income tax expense of $24.4 million for 2008 resulted in an effective tax rate of 25.7%. Income tax expense for 2008 was lower than income tax expense calculated at the federal statutory tax rate of 35%, primarily due to adjustments to reserves for uncertain tax positions that decreased the rate by 9.4%, permanent differences, which decreased the rate by 7.9% and the segment’s share of consolidated tax savings, which decreased the rate by 2.0%. These deductions were partially offset by state taxes, which increased the rate by 5.8%, and the ratemaking effects of investment tax credits and depreciation differences, which increased the rate by 4.2%.

Transmission Expansion

The Regulated Operations segment includes the operations of TrAIL Company and PATH-Allegheny, as well as Allegheny’s interest in PATH-WV. TrAIL Company, PATH-Allegheny and PATH-WV are subject to regulation of rates by FERC for amounts billed through PJM. FERC has approved the use of a formula rate methodology for recovery of all prudently incurred operations and maintenance expenses and a return on debt and equity for all capital expenditures in connection with the TrAIL and PATH projects based on a hypothetical 50% debt and 50% equity capital structure until the transmission facilities are placed into service, as well as an income tax allowance. The actual capital structure for each company will be reflected in the formula rate once the transmission facilities are placed into service. TrAIL Company, PATH-Allegheny and PATH-WV recognize revenue based on allowable costs incurred and return earned. Therefore, revenues and operating income are expected to increase as the projects progress. The results of operations and selected balance sheet information related to transmission expansion were as follows:

	Year Ended December 31,
(In millions)	2010		2009			2008
Results of operations:
Operating revenues	$	147.7	$	80.5		$	34.5
Operations and maintenance		16.6		15.2			9.9
Depreciation and amortization		5.4		4.2			3.4
Taxes other than income taxes		2.2		1.9			1.1
Other		0		0			0.1
Total operating expenses		24.2		21.3			14.5
Operating income		123.5		59.2			20.0
Other income (expense), net		6.0		2.4			1.3
Interest expense, net of capitalized interest		34.3		7.3			2.9
Income before income taxes		95.2		54.3			18.4
Income tax expense		37.5		21.4			7.2
Net income		57.7		32.9			11.2
Net income attributable to noncontrolling interest		0		(1.4	)		(0.4	)
Net income attributable to Allegheny Energy, Inc.	$	57.7	$	31.5		$	10.8

	At December 31,
(In millions)	2010		2009
Balance sheet information:
Property, plant and equipment, net	$	1,241.7	$	825.3
Total assets	$	1,463.9	$	922.5
Long-term debt	$	818.6	$	455.0

As described in Note 23, “Variable Interest Entities” to Allegheny’s consolidated financial statements, effective January 1, 2010, Allegheny began to account for its investment in PATH-WV using the equity method of accounting, rather than its prior consolidation method of accounting. At December 31, 2009, Allegheny’s consolidated balance sheet included property, plant and equipment of PATH-WV in the amount of $35.8 million,

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cash and cash equivalents of $3.4 million and noncontrolling interest related to AEP’s ownership of approximately $14.9 million. At December 31, 2010, Allegheny’s consolidated balance sheet included Allegheny’s investment in PATH-WV on the equity method of accounting in the amount of $23.6 million. Allegheny’s consolidated statement of income for 2010 included other income of $3.5 million representing Allegheny’s 50% equity in the pre-tax earnings of PATH-WV. Allegheny’s consolidated statement of income for 2009 and 2008 included revenues of $10.8 million and $6.4 million, respectively, operating income of $4.4 million and $1.6 million, respectively, and net income attributable to noncontrolling interest of $1.4 million and $0.4 million, respectively, relating to PATH-WV.

FINANCIAL CONDITION-LIQUIDITY AND CAPITAL RESOURCES

To meet cash needs for operating expenses, the payment of interest, pension contributions, retirement of debt and construction programs, Allegheny has historically used internally generated funds (net cash provided by operations less common dividends) and external financings, including the sale of common and preferred stock, debt instruments and lease arrangements.

At December 31, 2010 and 2009, Allegheny had cash and cash equivalents of $503.7 million and $286.6 million, respectively, and current restricted funds of $46.9 million and $25.9 million, respectively. Current restricted funds at December 31, 2010 included $25.0 million of funds collected from West Virginia customers that will be used to service the environmental control bonds issued in connection with the construction of the Scrubbers at Fort Martin, $19.3 million of medical benefit trust assets and $2.6 million of energy contract collateral. Current restricted funds at December 31, 2009 included $20.6 million of funds collected from West Virginia customers that was used to service the environmental control bonds issued in connection with the construction of the Scrubbers at the Fort Martin generating facility and $5.3 million of intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. In addition, at December 31, 2010 and 2009, Allegheny had long-term restricted funds of $29.4 million and $60.2 million, respectively. Long-term restricted funds at December 31, 2010 related to proceeds from the issuance of ratepayer obligation bonds issued in connection with the construction of Scrubbers at the Fort Martin generating facility. Long-term restricted funds at December 31, 2009 included $10.3 million of funds remaining from the $235 million Pennsylvania Development Financing Authority bond issued in connection with the construction and installation of Scrubbers at the Hatfield’s Ferry generating facility, $49.6 million of funds relating to proceeds from the issuance of ratepayer obligation bonds in connection with the construction of Scrubbers at the Fort Martin generating facility and $0.3 million of escrow funds related to the Scrubber construction projects.

See Note 9, “Capitalization and Debt,” to Allegheny’s consolidated financial statements for a summary of Allegheny’s debt. Allegheny has no significant debt scheduled to mature prior to April 2012. At December 31, 2010, AE, AE Supply, Monongahela, Potomac Edison, West Penn, AGC and TrAIL Company had in place revolving credit facilities as follows:

(Dollar amounts in millions)	Matures		Total Capacity		Borrowed		Letters of Credit Issued		Available Capacity
AE		2013	$	250.0	$	0	$	3.1	$	246.9
AE Supply		2012		1,000.0		0		0		1,000.0
Monongahela		2012		110.0		0		0		110.0
Potomac Edison		2013		150.0		20.0		0		130.0
West Penn		2013		200.0		0		0		200.0
AGC		2013		50.0		50.0		0		0
TrAIL Company		2013		450.0		370.0		0		80.0
Total			$	2,210.0	$	440.0	$	3.1	$	1,766.9

Allegheny posts collateral with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. Approximately $30.7 million and $20.8 million of cash collateral deposits were included in

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current assets at December 31, 2010 and December 31, 2009, respectively. Approximately $6.5 million and $3.1 million of cash collateral deposits were netted against derivative liabilities on the Consolidated Balance Sheet at December 31, 2010 and December 31, 2009, respectively. If Allegheny’s credit ratings were to decline, it may be required to deposit additional cash or cash-equivalent collateral with its hedging counterparties. See Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to Allegheny’s consolidated financial statements for additional information regarding potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2010.

A downgrade of AE, AE Supply and the Distribution Companies at December 31, 2010 below Standard & Poor’s BB- or Moody’s Ba3, would have required Allegheny to post an additional $92 million of collateral to counterparties, including PJM, for both derivative and non-derivative contracts. At December 31, 2010, AE’s corporate credit rating outlook was stable.

Allegheny’s consolidated capital structure was as follows:

	December 31, 2010				December 31, 2009
(In millions)	Amount		%		Amount		%
Long-term debt	$	4,701.5		57.7	$	4,557.8		59.4
Allegheny Energy, Inc. common stockholders’ equity		3,441.7		42.3		3,113.2		40.6
Total	$	8,143.2		100.0	$	7,671.0		100.0

2010 Debt Activity

Borrowings and principal repayments on debt during the year ended December 31, 2010 were as follows:

(In millions)	Borrowings		Repayments
AE:
AE Revolving Credit Facility	$	130.1	$	130.1
AE Supply:
Medium-Term Notes		0		150.5
Revolving Credit Facility—AGC		50.0		0
TrAIL Company:
Medium-Term Notes		450.0		0
New TrAIL Company Credit Facility-Revolver		370.0		0
TrAIL Company Credit Facility-Term Loan (a)		30.0		465.0
TrAIL Company Credit Facility-Revolver (a)		0		20.0
West Penn:
Transition Bonds		0		16.0
Revolving Credit Facility		35.0		35.0
Monongahela:
Medium-Term Notes		0		110.0
Environmental Control Bonds		0		11.1
Potomac Edison:
Environmental Control Bonds		0		3.7
Revolving Credit Facility		140.0		120.0
Consolidated Total	$	1,205.1	$	1,061.4

(a) Represents debt under TrAIL Company’s previous credit facility, which was repaid and replaced in January 2010 by a new revolving credit facility, as described below.

On January 15, 2010, Monongahela repaid its $110 million in outstanding 7.36% medium-term notes.

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On January 25, 2010, TrAIL Company issued $450 million aggregate principal amount of 4.0% senior unsecured notes due in 2015 and also entered into a $350 million senior unsecured revolving credit facility with a three-year maturity. The revolving credit facility capacity was increased to $450 million in August 2010. Borrowings under the new credit facility bear interest at a rate that is calculated based on the London Interbank Offered Rate (“LIBOR”) plus a margin based on TrAIL Company’s senior unsecured credit rating. Currently, the margin is 3.0%. TrAIL Company used the net proceeds from the sale of the notes, together with funds from the credit facility, to repay all amounts outstanding under the $550 million senior unsecured credit facility that it entered into in 2008.

On May 3, 2010, Potomac Edison and West Penn entered into new $150 million and $200 million senior unsecured revolving credit facilities, respectively. On May 4, 2010, AE entered into a new $250 million senior unsecured revolving credit facility. The new AE revolving credit facility replaced AE’s previous $376 million revolving credit facility, which was scheduled to mature in May 2011. The AE, Potomac Edison and West Penn credit facilities mature April 30, 2013. Loans under all three credit facilities bear interest at a rate that is calculated based on LIBOR plus a margin based on the borrower’s senior unsecured credit rating. Currently, the margins are 3.0% for AE and 2.75% for Potomac Edison and West Penn. Allegheny capitalized approximately $5.6 million in debt issuance costs related to the three credit facilities.

On July 16, 2010, AE Supply redeemed all $150.5 million of its outstanding 7.80% Medium Term Notes due 2011 and expensed approximately $7.3 million in redemption premiums and unamortized costs associated with the notes.

On October 22, 2010, AGC entered into a $50 million senior unsecured revolving credit facility and borrowed $50 million under the credit facility to pay dividends and a return of capital of $30 million to AE Supply and $20 million to Monongahela. The credit facility matures on December 31, 2013. Loans under the credit facility bear interest at a rate that is calculated based on LIBOR plus a margin based on AGC’s senior unsecured credit rating. Currently, the margin is 2.50%.

2009 Debt Activity

Borrowings and principal repayments on debt during 2009 were as follows:

(In millions)	Issuances		Repayments
AE:
AE Revolving Credit Facility	$	120.0	$	120.0
AE Supply:
AE Supply Credit Facility-Revolving Loan (a)		120.0		120.0
AE Supply Credit Facility-Term Loan (a)		0		447.0
Exempt Facilities Revenue Bonds		235.0		0
Medium-Term Notes		600.0		396.3
TrAIL Company:
TrAIL Company Credit Facility-Term Loan		365.0		0
West Penn:
Transition Bonds		0		79.8
Monongahela:
Environmental Control Bonds		64.4		10.6
Potomac Edison:
Environmental Control Bonds		21.5		3.5
Consolidated Total	$	1,525.9	$	1,177.2

(a) Represents debt activity under AE Supply’s previous credit facility, which was replaced with a new credit facility during September 2009.

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On July 6, 2009, the Pennsylvania Economic Development Financing Authority issued $235 million of 7.0% tax-exempt bonds that mature in 2039 and loaned the proceeds from that issuance to AE Supply to finance a portion of the cost of constructing and installing Scrubbers at its Hatfield’s Ferry generation facility. AE Supply capitalized $2.4 million in debt issuance costs associated with this transaction.

On September 4, 2009, AE Supply repurchased $97.5 million and $146.8 million, respectively, of its 7.80% notes due 2011 and its 8.25% notes due 2012 pursuant to a cash tender offer, at an aggregate premium of $18.1 million. AE Supply expensed the $18.1 million premium, $0.7 million in unamortized debt costs, and $0.6 million in fees associated with the tender offer during the three months ended September 30, 2009.

On September 24, 2009, AE Supply entered into a new $1 billion senior unsecured revolving credit facility with a three-year maturity. The new revolving credit facility replaced AE Supply’s previous $400 million revolving credit facility, which was scheduled to mature in May 2011. Loans under the new facility bear interest that is calculated based on the LIBOR, plus a margin based on AE Supply’s senior unsecured credit rating. AE Supply capitalized $22.3 million in debt costs related to this facility.

On October 1, 2009, AE Supply issued $600 million aggregate principal amount of senior unsecured notes, consisting of $350 million of 5.75% notes due 2019 and $250 million of 6.75% notes due 2039. AE Supply used a portion of the net proceeds from the sale of these notes to repay in full its existing $447 million term loan on October 2, 2009. AE Supply capitalized $5.3 million in debt issuance costs associated with this new debt issuance and expensed $0.6 million of unamortized debt costs associated with the extinguished term loan.

On October 21, 2009, AE Supply used the remaining proceeds of its senior unsecured note offering to repurchase approximately $152 million aggregate principal amount of its 7.80% Medium Term Notes due 2011 pursuant to a cash tender offer at an aggregate premium of $12.7 million. AE Supply expensed the $12.7 million premium, $0.3 million in unamortized debt costs, and $0.4 million in fees related to this tender offer.

On December 18, 2009, Monongahela entered into a new $110 million senior unsecured revolving credit facility with a three-year maturity. Loans under the new facility generally bear interest that is calculated based on the LIBOR, plus a margin based on Monongahela’s senior unsecured credit rating. Monongahela capitalized approximately $1.4 million in debt costs related to this facility.

On December 23, 2009, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $64.4 million and $21.5 million, respectively, of Senior Secured Ratepayer Obligation Charge Environmental Control Bonds, Series B. These bonds securitize the right to collect an environmental control surcharge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. The bonds were issued with an interest rate of 5.1% and mature in January 2031. Net proceeds from the sale of the bonds are restricted funds and are being used to fund certain costs incurred in connection with the construction and installation of the Scrubbers at the Fort Martin generating facility. Monongahela and Potomac Edison capitalized $1.9 million and $0.7 million, respectively, in debt issuance costs associated with this transaction.

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Dividends

During 2010, 2009 and 2008, Allegheny paid the following dividends on its common stock:

Payment Date	Record Date	Dividend per Share
December 27, 2010	December 13, 2010	$	0.15
September 27, 2010	September 13, 2010	$	0.15
June 21, 2010	June 7, 2010	$	0.15
March 22, 2010	March 8, 2010	$	0.15
December 28, 2009	December 14, 2009	$	0.15
September 28, 2009	September 14, 2009	$	0.15
June 22, 2009	June 8, 2009	$	0.15
March 23, 2009	March 9, 2009	$	0.15
December 29, 2008	December 15, 2008	$	0.15
September 29, 2008	September 15, 2008	$	0.15
June 23, 2008	June 9, 2008	$	0.15
March 24, 2008	March 10, 2008	$	0.15

In addition to the dividends listed above, on December 21, 2010, the Board of Directors authorized a cash dividend on AE’s common stock. If the proposed Merger does not become effective on or before March 14, 2011, a dividend of $0.15 per outstanding share of common stock will be payable on March 28, 2011 to stockholders of record at the close of business on March 14, 2011. If the proposed Merger becomes effective on or before March 14, 2011, a prorated final dividend will be payable 14 days after the effective date of the Merger to stockholders of record at the close of business on the business day prior to the Merger effective date.

Dividends are declared at the discretion of the Board of Directors and future dividends will depend upon available earnings, cash flows and other relevant factors, provided, however, that under the terms of its proposed merger with FirstEnergy, AE is prohibited from increasing its quarterly cash dividend.

Capital Expenditures

Actual capital expenditures for 2010 and estimated capital expenditures for 2011 and 2012 are shown on a cash basis in the following table. The scope, amounts and timing of capital projects and related expenditures are subject to continuing review and adjustment, and actual capital expenditures may vary from these estimates.

	Actual 2010		Projected
(in millions)			2011		2012
Transmission and distribution:
TrAIL and TrAIL Company projects (a)	$	510.7	$	123.5	$	46.9
PATH (b)		23.9		33.6		456.9
Smart meter procurement and installation (c)		16.4		12.0		4.9
Other transmission and distribution		218.0		315.7		377.6
Total transmission and distribution		769.0		484.8		886.3
Environmental:
Fort Martin Scrubbers		16.1		0		0
Hatfield Scrubbers		16.1		0		0
Other environmental		71.8		115.4		217.0
Total environmental		104.0		115.4		217.0
Generation projects, excluding environmental projects included above		81.7		121.6		72.7
Other		4.3		0		0
Total capital expenditures	$	959.0	$	721.8	$	1,176.0

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(a) TrAIL has a target completion date of June 2011 and an estimated cost, excluding AFUDC, of approximately $990 million. TrAIL Company is also engaged in other transmission projects.

(b) Allegheny’s share of the estimated cost of the PATH Project is approximately $1.4 billion. Actual 2010 includes approximately $8 million in capital expenditures related to Allegheny’s portion of the West Virginia Series of PATH, LLC and approximately $16 million in capital expenditures related to PATH-Allegheny.

(c) Consists of expenditures related to Allegheny’s procurement and installation of smart meters to comply with Pennsylvania’s Act 129. See “Regulatory Framework Affecting Allegheny” for additional information, including West Penn’s current plans to decelerate its previous smart meter deployment schedule.

Other Matters Concerning Liquidity and Capital Requirements

Allegheny makes cash contributions to its qualified pension plan to meet the minimum funding requirements of employee benefit and tax laws and may include additional discretionary contributions to increase the funded level of the plan. Allegheny has not yet determined the amount of future contributions, but expects to contribute approximately $140 million to its pension plan for the year 2011. The amount of future contributions to the plan will depend on the funded status of the plan, asset performance and other factors. Allegheny currently anticipates that it will contribute $2 million to $3 million during 2011 to fund postretirement benefits other than pensions.

Allegheny has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel and transportation agreements and other contracts. The table below summarizes estimated contractual obligations by period as of December 31, 2010, excluding expected contributions for pension and postretirement benefits other than pensions, contingent liabilities and certain contractual commitments that are accounted for under fair value accounting.

Contractual Obligations and Commitments (In millions)	2011		2012-2013		2014-2015		Thereafter		Total
Debt (a)	$	15.5	$	1,369.7	$	1,037.3	$	2,286.5	$	4,709.0
Interest on debt (b)		275.4		465.7		340.7		1,464.9		2,546.7
Interest rate swap obligations		2.1		0		0		0		2.1
Capital lease obligations		14.8		22.0		14.9		7.9		59.6
Operating lease obligations		6.4		11.2		10.7		3.2		31.5
PURPA purchased power (c)		257.0		545.3		560.6		3,410.4		4,773.3
Fuel purchase and transportation commitments		1,069.1		1,481.8		1,114.9		1,509.7		5,175.5
Uncertain tax positions		6.1		87.8		4.9		0		98.8
EDS contract services (d)		23.8		22.9		0		0		46.7
Total	$	1,670.2	$	4,006.4	$	3,084.0	$	8,682.6	$	17,443.2

(a) Does not include unamortized debt expense, discounts, premiums and payments made and debt issued subsequent to December 31, 2010.

(b) Amounts were based on interest rates as of December 31, 2010 and do not reflect any debt or interest rate changes subsequent to December 31, 2010.

(c) Amounts were calculated based on expected PURPA purchased power prices at December 31, 2010 without giving effect to possible price changes that could occur as a result of any future CO₂ emissions regulation or legislation.

(d) Amounts represent Allegheny’s expected cash payments for certain information technology services under a contract that expires on December 31, 2012.

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Off-Balance Sheet Arrangements

Allegheny has no off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on its financial position, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

Cash Flows

Operating Activities

Allegheny’s cash flows from operating activities result primarily from the generation, sale and delivery of electricity. Future cash flows could be affected by, among other factors, the economy, weather, customer choice, future regulatory proceedings and future demand and market prices for energy, as well as Allegheny’s ability to produce and supply its customers with power at competitive prices. Cash flows from operating activities are summarized as follows:

(In millions)	2010			2009			2008
Net income	$	411.7		$	394.1		$	395.8
Non-cash items included in income		635.3			457.0			460.4
Contributions to pension and other postretirement plans		(82.3	)		(48.6	)		(49.3	)
Changes in certain assets and liabilities		(148.7	)		(2.9	)		54.5
Net cash provided by operating activities	$	816.0		$	799.6		$	861.4

The non-cash items included in income in 2010 primarily consisted of depreciation and amortization of $323.5 million and deferred income taxes of $239.3 million. Changes in certain assets and liabilities primarily consisted of changes in receivables and payables of $104.9 million, resulting from normal working capital activity, an increase in collateral deposits of $37.1 million, primarily due to increased collateral requirements with various counterparties to Allegheny’s power contracts, changes in accrued taxes of $32.2 million, primarily as a result of timing differences associated with the payments of certain tax obligations, and a decrease in regulatory liabilities of $30.1 million mostly due to providing credits to Maryland customers for amounts prepaid. These amounts were partially offset by a decrease in materials, supplies and fuel inventories of $60.8 million, primarily as a result of lower consumption of coal in the previous period as compared to the current period.

The non-cash items included in income in 2009 primarily consisted of depreciation and amortization of $282.1 million and deferred income taxes and investment tax credit, net of $235.3 million, partially offset by deferred energy costs, net of $64.4 million.

The non-cash items included in income in 2008 primarily consisted of depreciation and amortization of $273.9 million and deferred income taxes of $156.2 million. Changes in certain assets and liabilities primarily consisted, in part, of a change in regulatory liabilities of $60.4 million, primarily relating to Allegheny receiving payments from its customers in advance of providing service, in order to mitigate the impact of the transition to market-based generation rates, the advanced payments are being credited to the customers. Changes in certain assets and liabilities also included a change in regulatory assets of $51.3 million, primarily resulting from the recovery of previously deferred and earned revenue related to West Penn restructuring; a change in accrued taxes of $43.1 million, primarily as a result of timing differences associated with the payment of certain tax obligations; and a reduction in collateral deposits of $23.1 million, primarily due to reduced collateral requirements with various counterparties to Allegheny’s power contracts. These amounts were partially offset by $62.9 million in changes in receivables and payables resulting from normal working capital activity and an increase in materials, supplies and fuel of $62.8 million, primarily as a result of increased fuel inventory levels and higher prices.

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Investing Activities

Cash flows from investing activities are summarized as follows:

(In millions)	2010			2009			2008
Capital expenditures	$	(950.5	)	$	(1,166.2	)	$	(994.1	)
Purchase of WV assets		(14.5	)		0			0
Purchase of hydroelectric business		0			(2.0	)		0
Proceeds from sale of Virginia distribution business		317.2			0			0
Proceeds from asset sales		0.2			3.0			1.1
Purchase of Merrill Lynch interest in subsidiary		0			0			(50.0	)
Decrease in other restricted funds		31.3			84.1			224.4
Deconsolidation of PATH-WV		(3.4	)		0			0
Other		(5.9	)		(3.7	)		(3.7	)
Net cash used in investing activities	$	(625.6	)	$	(1,084.8	)	$	(822.3	)

Cash flows used in investing activities in 2010 were $625.6 million and primarily consisted of $950.5 million of capital expenditures partially offset by $317.2 million in proceeds from the sale of the Virginia distribution business.

Cash flows used in investing activities in 2009 were $1,084.8 million and primarily consisted of $1,166.2 million of capital expenditures partially offset by an $84.1 million decrease in restricted funds, primarily due to the use of restricted funds associated with the Fort Martin Scrubber project.

Cash flows used in investing activities in 2008 were $822.3 million and primarily consisted of $994.1 million of capital expenditures and $50.0 million relating to the acquisition of Merrill Lynch’s noncontrolling interest in AE Supply, partially offset by a $224.4 million decrease in restricted funds, primarily due to the use of restricted funds associated with the Fort Martin Scrubber project.

Financing Activities

Cash flows from financing activities are summarized as follows:

(In millions)	2010			2009			2008
Issuance of long-term debt	$	1,186.5		$	1,508.3		$	647.6
Repayment of long-term debt		(1,061.4	)		(1,177.2	)		(493.1	)
Costs associated with the AE Supply revolving credit facility refinancing		(0.1	)		(22.2	)		0
Issuance (repayment) of note payable		0			0			(10.0	)
Equity contribution to PATH, LLC by a joint venture partner		0			8.7			4.5
Payments on capital lease obligations		(11.2	)		(8.5	)		(9.0	)
Proceeds from exercise of employee stock options		1.3			2.3			25.3
Cash dividends paid on common stock		(101.8	)		(101.7	)		(101.1	)
Other		(0.1	)		0			0
Net cash provided by financing activities	$	13.2		$	209.7		$	64.2

Cash flows provided by financing activities in 2010 were $13.2 million and primarily included $1,186.5 million (net of $16.9 million related to debt issuance costs other than the costs associated with the AE Supply revolving credit facility refinancing of $0.1 million) in proceeds from the issuance of long-term debt, including borrowings of $755.1 million under AE’s and various subsidiaries’ revolving credit facilities as well as the issuance by TrAIL of $450.0 million in the aggregate of medium term notes. These amounts were partially offset by $1,061.4 million in various debt repayments and $101.8 million of cash dividends paid on common stock.

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Cash flows provided by financing activities in 2009 were $209.7 million and primarily included $1,508.3 million (net of $14.8 million related to debt issuance costs other than the costs associated with the AE Supply revolving credit facility refinancing of $22.2 million) in proceeds from the issuance of long-term debt, including borrowings of $605.0 million under AE’s and AE Supply’s revolving credit facilities and TrAIL Company’s senior secured credit facility, as well as the issuance by AE subsidiaries of $920.8 million in the aggregate of medium term notes and revenue bonds. These amounts were partially offset by $1,177.2 million in various debt repayments and $101.7 million of cash dividends paid on common stock.

Cash flows provided by financing activities in 2008 were $64.2 million and primarily included $647.6 million (net of $12.3 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, including borrowings of $360.0 million under AE Supply’s revolving credit facility and TrAIL Company’s senior secured credit facility as well as the issuance of $300.0 million of 7.95% First Mortgage Bonds, partially offset by $493.1 million in various debt repayments and $101.1 million of cash dividends paid on common stock.

AE Common Stock

AE issued 0.4 million and 0.2 million shares of common stock in 2010 and 2009, respectively, primarily in connection with stock option exercises and the settlement of stock units. AE did not repurchase any of its common stock in 2010 or 2009.

Recent Accounting Pronouncements

See Note 3, “Recently Adopted and Recently Issued Accounting Standards,” to Allegheny’s consolidated financial statements for information on recent accounting pronouncements affecting Allegheny.

MARKET RISK INFORMATION

Allegheny is exposed to various risks arising from commodity prices, interest rates and the credit of its commercial counterparties. Allegheny’s commodity price risk exposure results from market fluctuations in the price and transportation cost of electricity, coal, natural gas and other energy-related commodities. Allegheny’s interest rate risk exposure results from changes in interest rates related to variable-rate debt as well as refinancing risk associated with maturing debt. Allegheny’s credit risk exposure results from customers defaulting on their contractual obligations or failing to pay for service rendered.

To mitigate these risks, Allegheny has a program designed to systematically identify, measure, evaluate and actively manage and assess these risks. This program includes a Corporate Risk Policy adopted by AE’s Board of Directors. Compliance with this policy is monitored by a Risk Management Committee that is chaired by AE’s Chief Executive Officer or his designee and is composed of senior management. An independent risk management group within Allegheny measures and monitors risk exposures to ensure compliance with the policy and to ensure that the policy is periodically reviewed.

Commodity Price Risk

Allegheny has commodity price risk to the extent that the amount of energy it generates and contracts to purchase differs from the amount of energy it has contracted to sell. Allegheny is also exposed to market risks associated with changes in commodity prices resulting from changes in supply and demand, fuel costs, market liquidity, weather, environmental regulation and other factors.

To manage its exposure to market price changes relating to its energy related assets, liabilities and other contractual arrangements, Allegheny sells and purchases physical energy at the wholesale and retail level and enters into financial exchange-traded and over the counter derivative contracts. See Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to Allegheny’s consolidated financial statements for information regarding Allegheny’s derivative positions held at December 31, 2010.

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In general, increases in forward market prices for power have a positive impact, and decreases in forward market prices have a negative impact, on Allegheny’s owned and contracted generation positions that have not been hedged. As of December 31, 2010, the percentage of expected coal-fired generation hedged was approximately 79%, 30%, and 7% for 2011, 2012 and 2013, respectively. These percentages represent the estimated amount of equivalent sales divided by the amount of energy purchases contracted and estimated to be generated by Allegheny’s coal-fired generating facilities in such periods.

Allegheny measures the sensitivity of the portfolio to potential changes in market prices using high-level sensitivity analysis and Value at Risk. Allegheny performed a high-level sensitivity analysis of the impact of changes in power and coal prices on its future pre-tax income. The estimated market price exposure for Allegheny’s coal-fired generation portfolio associated with a $10 per MWh decrease in energy prices based on December 31, 2010 market conditions and hedged position would result in decreases in pre-tax income of approximately $70 million and $232 million in 2011 and 2012, respectively. The estimated market price exposure for Allegheny’s coal-fired generation portfolio associated with a $10 per ton increase in coal prices based on December 31, 2010 market conditions and hedged position would result in decreases in pre-tax income of approximately $3 million and $44 million in 2011 and 2012, respectively. These power and coal price sensitivities were estimated by individually adjusting power price assumptions and coal price assumptions, respectively, while in each case holding all other variables constant. Actual results could differ based on changes in load volumes, plant performance, dispatch and price basis relative to PJM Western Hub power prices, among other factors.

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 forward price curves and spot commodity prices.

Allegheny 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 generating facilities. For accounting purposes, the generating 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.

Allegheny is primarily exposed to commodity-driven risks associated with the wholesale and retail electricity markets, including generation, coal and other fuel procurement, power marketing and the purchase and sale of electricity. Allegheny’s wholesale and retail activities principally consist of bilateral forward contracts for the purchase and sale of electricity. The majority of these contracts represent commitments to purchase or sell electricity at fixed prices in the future. These forward contracts can require either physical or financial settlement.

Derivative Market Risk

Derivatives that are not designated as part of a cash flow hedge relationship or as normal purchase normal sale contracts are reported in revenues on a mark-to-market basis.

Allegheny and AE Supply measure their market risk exposure to mark-to-market derivative contracts other than FTRs using value at risk model (“VaR”). VaR is a statistical model that measures the variability of value and predicts the 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 using the Monte-Carlo technique by simulating thousands of scenarios sampled from the probability distribution of uncertain market variables. In addition to VaR, Allegheny and AE Supply routinely perform stress and scenario analyses to measure extreme losses due to exceptional events. FTRs are excluded from Allegheny’s calculation of VaR due to the absence of liquid spot and forward markets and are generally considered as an economic hedge against Allegheny’s load obligation.

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AE Supply calculated the VaR of a 1-day holding period at a 95% confidence level using the full term of all remaining wholesale energy market positions that are accounted for on a mark-to-market basis. These wholesale energy market positions consist of derivatives in power, emissions and natural gas excluding FTRs. As of December 31, 2010 and December 31, 2009, this calculation yielded a VaR of approximately $3 million and $1 million, respectively.

The value of FTRs generally represents an economic hedge of future congestion charges incurred to serve Allegheny’s load obligations. The related load obligations, however, are not reflected in Allegheny’s Consolidated Balance Sheets. As a result, the timing of recognition of gains or losses on FTRs will differ from the timing of power purchases, including incurred congestion charges. The fair value of FTRs has been determined using an internal model based on data from PJM annual and monthly FTR auctions. These monthly auction results can change significantly over time and may differ from the final settlement amounts. See Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to Allegheny’s consolidated financial statements for information regarding unrealized gains (losses) attributable to FTRs during the twelve months ended December 31, 2010.

Interest Rate Risk

Excluding variable rate debt relating to the TrAIL project, for which Allegheny recovers interest costs in formula rates, Allegheny had $70 million of variable rate debt outstanding at December 31, 2010. Allegheny did not have any debt subject to variable interest rates at December 31, 2009.

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 condition of existing counterparties on an ongoing basis. Allegheny’s independent risk management group oversees credit risk.

Allegheny engages in various energy transacting 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 counterparties in the electric and natural gas utility industries. This concentration of counterparties may affect Allegheny’s overall exposure to credit risk, either positively or negatively, because these counterparties may be similarly affected by changes in economic or other conditions.

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. However, Allegheny can provide no assurance that the counterparties to these agreements will fulfill their obligations to supply coal. The suppliers under these agreements may, as a general matter, experience financial, legal or technical problems that inhibit their ability to fulfill their obligations. Among other circumstances, constrained credit markets or other negative economic conditions may affect the ability of Allegheny’s suppliers to access the capital markets and maintain adequate liquidity to sustain their respective businesses. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties may have negative effects on coal supplier performance. During periods of rising coal prices, the factors impacting supplier performance could have a more pronounced financial impact. Furthermore, 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

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purchase coal at higher prices. In addition, although these agreements generally contain specified prices, they also provide for price adjustments related to changes in specified cost indices, as well as specific events, such as changes in regulations affecting the coal industry. Changes in the supply and price of coal could have a material adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

As of December 31, 2010, Allegheny’s electricity commodity contracts are comprised primarily of derivatives and non-derivatives that will expire at various times through May 2013.

Allegheny currently is involved in a number of capital intensive projects, including the TrAIL Project and the PATH Project. Allegheny has contracted, or expects to contract, with specialized vendors to acquire some of the necessary materials and construction related services in order to complete these projects. As such, Allegheny is exposed to the risk that these contractors may not perform as required under their contracts. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Furthermore, Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all.

Allegheny also may be subject to credit risk through its participation in PJM, to the extent that PJM socializes counterparty defaults across PJM members.

Wholesale Credit Risk

Allegheny measures wholesale credit risk as the replacement cost for derivatives in power and natural gas excluding FTRs (both mark-to-market and accrual) adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff. Allegheny monitors and manages the credit risk of our wholesale marketing, risk management, and energy transacting operation through credit policies and procedures which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as collateral and the use of master netting agreements.

As of December 31, 2010 and 2009, the credit portfolio of Allegheny’s wholesale, risk management and energy transacting operation had the following credit ratings:

	2010			2009
Rating:
Investment Grade (a)		100	%		78	%
Non-Investment Grade		0	%		2	%
Non-Rated		0	%		20	%

(a) Includes counterparties with an investment grade or equivalent rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used.

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A portion of Allegheny’s total wholesale is related to transactions that are recorded in its Consolidated Balance Sheets. These transactions primarily consist of open positions from Allegheny’s wholesale marketing, risk management and energy transacting operations that are accounted for using derivative accounting, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid. The following table highlights the credit quality and exposures related to these activities, excluding FTRs, at December 31, 2010:

(Dollar amounts in millions)	Total Exposure Before Collateral		Collateral		Net Exposure		Number of Counterparties With Greater than 10% of Net Exposure		Net Exposure of Counterparties With Greater Than 10% of Net Exposure
Rating:
Investment grade	$	35.9	$	19.1	$	55.0		5		67.7	%
Non-investment grade		0		0		0		0		0
Not rated		0		0		0		0		0
Total	$	35.9	$	19.1	$	55.0		5		67.7	%

Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, by failing to deliver the electricity our wholesale marketing, risk management, and energy transacting operation had contracted for), Allegheny could incur a loss that could have a material impact on its financial results.

Retail Credit Risk

Allegheny is exposed to retail credit risk through its competitive electricity activities, which serve commercial and industrial companies. Retail credit risk results when customers default on their contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.

Retail credit risk is managed through established credit approval policies, monitoring customer exposures, and the use of credit mitigation measures such as deposits in the form of letters of credit, surety bonds, and cash or prepayment arrangements.

Retail credit quality is dependent on the economy and the ability of Allegheny’s customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, Allegheny’s retail credit risk may be adversely impacted.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with GAAP requires management to apply accounting policies and make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. The areas described in this section require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are uncertain and that may change in subsequent periods. Further discussion of the application of these accounting policies can be found in the notes to consolidated financial statements.

Revenues and Receivables:  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. Energy

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billings to individual customers are based on meter readings, which are performed periodically on a systematic basis. At the end of each month, the amount of energy delivered to each customer is estimated based in part on the most recent reading of the customer’s meter, and the Distribution Companies recognize unbilled revenues that reflect these estimates. 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 provision for uncollectible accounts is recorded as a component of operations and maintenance expense.

Derivative Contracts:  Derivative contracts are recorded in Allegheny’s Consolidated Balance Sheets at fair value with changes in the fair value of the derivative contract included in revenues on the Consolidated Statements of Income unless the derivative falls within the normal purchases and normal sales scope exception or is designated as a cash flow 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 loss” and subsequently reclassified into earnings when the forecasted transaction is completed or settled. Changes in the value of any ineffective portion of the hedge are immediately recognized in earnings.

Fair values for exchange-traded instruments, principally futures, 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, FTRs and swaps, management uses available market data and pricing models to estimate fair values. Estimating the fair values of instruments that do not have quoted market prices requires management’s judgment in determining amounts that 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. These agreements 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 derivative assets and liabilities and of accounts receivable and accounts payable with each counterparty on a net basis. In addition, FTR assets and obligations are recorded on a net basis. Cash flows associated with derivative contracts are recorded in cash flows from operating activities. See Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” to Allegheny’s consolidated financial statements for additional details regarding energy transaction activities.

Regulatory Accounting:  The Distribution Companies, TrAIL Company and PATH, LLC are subject to regulations that set the rates that they are permitted to charge customers for reimbursement of costs. These rates are based on transmission, distribution and, for some entities, generation related costs that the applicable regulatory agencies determine that the Distribution Companies, TrAIL Company and PATH, LLC are permitted to recover. At times, regulators permit the future recovery through rates of incurred costs that would otherwise be charged to expense by an unregulated company. At times, regulators may also allow the collection of amounts in rates for costs expected to be incurred in the future or may require that amounts collected be set aside for a specific purpose or be credited or refunded to customers in the future. This ratemaking process often results in the recording of regulatory assets and liabilities based on estimated future cash inflows and outflows under regulatory guidelines and orders. Allegheny regularly reviews its regulatory assets and liabilities, including the estimates and assumptions on the basis of which they have been recorded and related regulatory interpretations.

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,

93

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 items of property are expensed as maintenance.

Long-Lived Assets:  Allegheny’s Consolidated Balance Sheets include significant long-lived assets that are not subject to recovery under cost of service based ratemaking. 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 its fair value as determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows and market-value-to-earnings comparisons, an impairment loss is recognized, and the asset is written down to its fair value.

Excess of Cost Over Net Assets Acquired (Goodwill):  Recorded goodwill is tested for impairment at least annually, and more frequently upon indication of possible impairment. The first phase of a goodwill impairment test involves comparison of reporting unit fair value to the carrying value of the reporting unit that has been assigned goodwill. All of Allegheny’s goodwill is recorded in its Merchant Generation reporting unit. This impairment testing requires the use of estimates, assumptions and other inputs to determine the fair value of the Merchant Generation reporting unit using both a discounted cash flow approach and a market-based valuation approach. These estimates, assumptions and other inputs involve the use of judgment, and changes in these inputs can significantly impact the estimated reporting unit fair value. Allegheny performed its annual goodwill impairment test as of August 31, 2010 and 2009 and the estimated fair value of the reporting unit exceeded its carrying amount by a significant amount. No goodwill impairment was indicated at that date and no impairment of goodwill was recorded during any of the years presented.

Income Taxes:  Allegheny is subject to income taxes in the United States and in various state jurisdictions. Significant judgment is required in evaluating tax positions and determining the provisions for income taxes. Allegheny establishes reserves for tax-related uncertainties based on estimates of whether, and the extent to which, additional taxes will be due. Allegheny adjusts these reserves in light of changing facts and circumstances, such as the outcome of tax audits.

Stock-Based Compensation:  GAAP requires measurement of compensation cost for all stock-based awards at fair value on the date of grant and recognition of compensation cost over the service period for the awards expected to vest. The determination of grant date fair value requires the use of judgment based on historical information as well as future expectations. In addition, the estimates of stock-based awards that will ultimately vest requires judgment, and actual results or updated estimates may differ from current estimates. See Note 11, “Stock-Based Compensation,” to Allegheny’s consolidated financial statements for additional information.

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 plan assets. Changes made to provisions for pension or other postretirement benefit plans may also affect current and future pension and OPEB costs. Allegheny believes that its assumptions are supported by historical data and reasonable projections, and its projections are reviewed annually with an outside actuarial firm. See Note 12, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to Allegheny’s consolidated financial statements for additional information concerning these assumptions.

Allegheny determines its discount rate assumptions through the use of a cash flow matching process in which the timing and amount of estimated benefit cash flows for each benefit plan are matched with an interest rate curve applicable to the returns of high quality corporate bonds over the expected benefit payment period to determine an overall effective discount rate.

94

Allegheny’s general approach for determining the overall expected long-term rate of return on plan assets assumption 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 discount rate and the expected rate of return on plan assets for 2010 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	$	(174.5	)	$	212.8
Net periodic pension and OPEB cost	$	(12.2	)	$	14.5
Change in expected rate of return on plan assets:
Net periodic pension and OPEB cost	$	(10.7	)	$	10.6

Contingencies:  Allegheny regularly reviews and assesses the likelihood of losses relating to environmental, legal and other contingencies and accrues a liability for matters for which it believes that a loss is probable if the probable loss can be estimated. See Note 25, “Commitments and Contingencies,” to Allegheny’s consolidated financial statements for additional information.

95

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by Item 7A relating to market risk is included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page No.
Consolidated Financial Statements of Allegheny Energy, Inc. and Subsidiaries		98
Reports of Independent Registered Public Accounting Firm		180
Schedule I AE (Parent Company) Condensed Financial Statements		184
Schedule II Valuation and Qualifying Accounts		187

97

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)	Year ended December 31,
	2010			2009			2008
Operating revenues	$	3,902.9		$	3,426.8		$	3,385.9
Operating expenses:
Fuel		1,192.6			886.6			1,080.9
Purchased power and transmission		502.9			502.0			395.6
Deferred energy costs, net		38.1			(64.4	)		(63.7	)
Gain on sale of Virginia distribution business		(44.6	)		0			0
Operations and maintenance		732.9			687.1			674.8
Depreciation and amortization		323.5			282.1			273.9
Taxes other than income taxes		226.0			213.6			214.9
Total operating expenses		2,971.4			2,507.0			2,576.4
Operating income		931.5			919.8			809.5
Other income (expense), net		13.3			7.0			22.3
Interest expense		316.4			291.1			231.9
Income before income taxes		628.4			635.7			599.9
Income tax expense		216.7			241.6			204.1
Net income		411.7			394.1			395.8
Net income attributable to noncontrolling interests		0			(1.3	)		(0.4	)
Net income attributable to Allegheny Energy, Inc.	$	411.7		$	392.8		$	395.4
Earnings per common share attributable to Allegheny Energy, Inc.:
Basic	$	2.42		$	2.32		$	2.35
Diluted	$	2.42		$	2.31		$	2.33
Average common shares outstanding:
Basic		169.8			169.5			168.5
Diluted		170.3			170.0			170.0

See accompanying Notes to Consolidated Financial Statements.

98

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)	Year ended December 31,
	2010			2009			2008
Cash Flows From Operating Activities:
Net income	$	411.7		$	394.1		$	395.8
Adjustments for non-cash items included in income:
Depreciation and amortization		323.5			282.1			273.9
Amortization of debt related costs		25.6			15.4			10.9
Amortization of Pennsylvania transition assets and liabilities		(17.9	)		(17.5	)		(8.1	)
Gain on sale of Virginia distribution business		(44.6	)		0			0
Gain relating to the purchase of hydroelectric generation facilities		0			(17.3	)		0
Provision for uncollectible accounts		16.8			16.4			16.5
Deferred income taxes and investment tax credit, net		239.3			235.3			156.2
Deferred energy costs, net		38.1			(64.4	)		(63.7	)
Unrealized losses (gains) on derivative contracts, net		23.1			(23.4	)		(18.8	)
Employee benefit expenses		73.3			55.7			45.2
Contributions to pension and other postretirement plans		(82.3	)		(48.6	)		(49.3	)
Deferred revenue-Fort Martin scrubber project		(4.0	)		11.0			10.8
Deferred revenue-Virginia		0			(28.3	)		28.3
Deferred revenue-energy efficiency programs		16.5			0			0
Unbilled transmission expansion revenue		(33.2	)		(16.0	)		(8.1	)
Other, net		(21.2	)		8.0			17.3
Changes in certain assets and liabilities:
Accounts receivable, net		(64.7	)		(42.9	)		(26.2	)
Materials, supplies and fuel		60.8			(75.2	)		(62.8	)
Collateral deposits		(37.1	)		37.7			23.1
Accounts payable		(40.2	)		29.5			(36.7	)
Accrued taxes		(32.2	)		(29.2	)		43.1
Regulatory assets and liabilities		(32.4	)		32.9			111.7
Assets and liabilities related to the sale of ACC fiber		0			21.3			0
Other operating assets and liabilities		(2.9	)		23.0			2.3
Net cash provided by operating activities		816.0			799.6			861.4
Cash Flows From Investing Activities:
Capital expenditures		(950.5	)		(1,166.2	)		(994.1	)
Purchase of WV distribution business		(14.5	)		0			0
Purchase of hydroelectric generation facilities		0			(2.0	)		0
Proceeds from sale of Virginia distribution business		317.2			0			0
Proceeds from asset sales		0.2			3.0			1.1
Purchase of Merrill Lynch interest in subsidiary		0			0			(50.0	)
Decrease in restricted funds		31.3			84.1			224.4
Deconsolidation of PATH-WV		(3.4	)		0			0
Other		(5.9	)		(3.7	)		(3.7	)
Net cash used in investing activities		(625.6	)		(1,084.8	)		(822.3	)

See accompanying Notes to Consolidated Financial Statements.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

(In millions)	Year ended December 31,
	2010			2009			2008
Cash Flows From Financing Activities:
Issuance of long-term debt		1,186.5			1,508.3			647.6
Repayment of long-term debt		(1,061.4	)		(1,177.2	)		(493.1	)
Costs associated with the AE Supply revolving credit facility refinancing		(0.1	)		(22.2	)		0
Repayment of note payable		0			0			(10.0	)
Equity contribution to PATH, LLC by a joint venture partner		0			8.7			4.5
Payments on capital lease obligations		(11.2	)		(8.5	)		(9.0	)
Proceeds from exercise of employee stock options		1.3			2.3			25.3
Cash dividends paid on common stock		(101.8	)		(101.7	)		(101.1	)
Other		(0.1	)		0			0
Net cash provided by financing activities		13.2			209.7			64.2
Net increase (decrease) in cash and cash equivalents		203.6			(75.5	)		103.3
Cash and cash equivalents at beginning of period		286.6			362.1			258.8
Cash and cash equivalents at end of period	$	490.2		$	286.6		$	362.1
Supplemental Cash Flow Information:
Cash paid during the year for interest (net of amounts capitalized)	$	286.9		$	264.8		$	228.2
Cash paid during the year for income taxes, net	$	15.1		$	41.3		$	10.8
Accounts payable at December 31 relating to capital expenditures	$	137.9		$	132.5		$	91.8
Non-cash investing activity relating to the purchase of hydroelectric generation facilities	$	0		$	17.3		$	0
Non-cash financing activity - AE common stock dividends accrued but not paid	$	25.5		$	0		$	0

See accompanying Notes to Consolidated Financial Statements.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions)	As of December 31,
	2010			2009
ASSETS
Current Assets:
Cash and cash equivalents	$	490.2		$	286.6
Accounts receivable:
Customer		245.9			188.2
Unbilled utility revenue		124.1			116.4
Wholesale and other		53.7			64.4
Allowance for uncollectible accounts		(15.7	)		(14.0	)
Materials and supplies		108.4			110.6
Fuel		151.3			206.4
Deferred income taxes		0			81.5
Prepaid taxes		48.9			48.4
Collateral deposits		30.7			20.8
Derivative assets		24.5			4.6
Restricted funds		46.9			25.9
Regulatory assets		177.5			132.7
Assets held for sale		0			32.4
Other		29.2			40.4
Total current assets		1,515.6			1,345.3
Property, Plant and Equipment:
Generation		7,623.2			7,469.4
Transmission		1,421.1			1,313.2
Distribution		3,937.5			3,784.4
Other		515.0			440.7
Accumulated depreciation		(5,362.9	)		(5,104.9	)
Subtotal		8,133.9			7,902.8
Construction work in progress		1,168.0			800.6
Property, plant and equipment held for sale, net		0			253.7
Total property, plant and equipment, net		9,301.9			8,957.1
Other Noncurrent Assets:
Regulatory assets		706.1			717.3
Goodwill		367.3			367.3
Restricted funds		29.4			60.2
Investments in unconsolidated affiliates		49.8			26.7
Other		105.7			115.2
Total other noncurrent assets		1,258.3			1,286.7
Total Assets	$	12,075.8		$	11,589.1

See accompanying Notes to Consolidated Financial Statements.

101

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Continued)

(In millions)	As of December 31,
	2010			2009
LIABILITIES AND EQUITY
Current Liabilities:
Long-term debt due within one year	$	15.5		$	140.8
Accounts payable		383.4			411.4
Accrued taxes		99.5			87.3
Payable to PJM for FTRs, excluding portion netted against derivative assets		0			31.7
Derivative liabilities		6.0			24.4
Regulatory liabilities		9.8			37.4
Accrued interest		72.2			68.3
Security deposits		55.6			51.0
Liabilities associated with assets held for sale		0			10.1
Deferred income taxes		26.1			0
Other		122.8			123.2
Total current liabilities		790.9			985.6
Long-term Debt:
Securitized debt-Environmental Control Bonds		481.0			496.5
Other long-term debt		4,205.0			3,920.5
Total long-term debt		4,686.0			4,417.0
Deferred Credits and Other Liabilities:
Derivative liabilities		7.4			6.7
Income taxes payable		43.4			85.7
Investment tax credit		58.3			61.6
Deferred income taxes		1,653.6			1,501.3
Regulatory liabilities		512.8			461.2
Pension and other postretirement employee benefit plan liabilities		596.8			597.4
Adverse power purchase commitment		96.3			114.4
Liabilities associated with assets held for sale		0			53.1
Other		188.6			177.0
Total deferred credits and other liabilities		3,157.2			3,058.4
Commitments and Contingencies (Note 25)
Equity:
Common stock—$1.25 par value per share, 260,000,000 shares authorized and 170,028,499 and 169,620,917 shares issued at December 31, 2010 and 2009, respectively		212.5			212.0
Other paid-in capital		1,987.8			1,970.2
Retained earnings		1,307.0			1,022.7
Treasury stock at cost—54,955 and 51,313 shares at December 31, 2010 and 2009, respectively		(1.9	)		(1.8	)
Accumulated other comprehensive loss		(63.7	)		(89.9	)
Total Allegheny Energy, Inc. common stockholders’ equity		3,441.7			3,113.2
Noncontrolling interest		0			14.9
Total equity		3,441.7			3,128.1
Total Liabilities and Equity	$	12,075.8		$	11,589.1

See accompanying Notes to Consolidated Financial Statements.

102

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME

(In millions, except shares)	Shares outstanding		Common stock		Other paid-in capital			Retained earnings			Treasury stock			Accumulated other comprehensive loss			Total Allegheny Energy, Inc. common stockholders’ equity			Noncontrolling interests			Total equity			Comprehensive income
Balance at December 31, 2007		167,223,576	$	209.1	$	1,924.1		$	444.2		$	(1.8	)	$	(40.2	)	$	2,535.4		$	13.2		$	2,548.6			—
Net income		—		—		—			395.4			—			—			395.4			0.4			395.8		$	395.8
Defined benefit pension and other benefit plans:
Net loss during the period, net of tax of $26.9		—		—		—			—			—			(39.5	)		(39.5	)		—			(39.5	)		(39.5	)
Amortization, net of tax of $1.1		—		—		—			—			—			1.7			1.7			—			1.7			1.7
Cash flow hedges, net of tax of $20.5		—		—		—			—			—			32.4			32.4			—			32.4			32.4
Comprehensive income		—		—		—			—			—			—			—			—						390.4
Comprehensive income attributable to noncontrolling interests		—		—		—			—			—			—			—			—			—			(0.4	)
Comprehensive income attributable to Allegheny Energy, Inc.		—		—		—			—			—			—			—			—			—		$	390.0
Purchase of noncontrolling interest in AE Supply		—		—		—			—			—			—			—			(13.2	)		(13.2	)		—
Equity contribution to PATH, LLC by the joint venture partner		—		—		—			—			—			—			—			4.5			4.5			—
Adoption of measurement date provisions for pension and other benefit plans:
Service cost, interest cost and expected return on plan assets, net of tax of $3.0		—		—		—			(4.4	)		—			—			(4.4	)		—			(4.4	)		—
Amortizations:
Net actuarial loss, net of tax of $0.7		—		—		—			(1.0	)		—			1.0			—			—			—			—
Net transition obligation, net of tax of $0.6		—		—		—			(0.9	)		—			0.9			—			—			—			—
Net prior service cost, net of tax of $0.3		—		—		—			(0.5	)		—			0.5			—			—			—			—
Dividends on common stock		—		—		—			(101.1	)		—			—			(101.1	)		—			(101.1	)		—
Stock-based compensation expense:
Stock units		—		—		0.6			—			—			—			0.6			—			0.6			—
Non-employee director stock awards		20,869		—		1.1			—			—			—			1.1			—			1.1			—
Stock options		—		—		9.3			—			—			—			9.3			—			9.3			—
Performance shares		—		—		2.9			—			—			—			2.9			—			2.9			—
Exercise of stock options		1,849,316		2.3		23.0			—			—			—			25.3			—			25.3			—
Settlement of stock units		270,633		0.4		(8.5	)		—			—			—			(8.1	)		—			(8.1	)		—
Dividends on stock units		—		—		—			(0.1	)		—			—			(0.1	)		—			(0.1	)		—
Other		—		—		—			—			—			(0.1	)		(0.1	)		—			(0.1	)		—
Balance at December 31, 2008		169,364,394	$	211.8	$	1,952.5		$	731.6		$	(1.8	)	$	(43.3	)	$	2,850.8		$	4.9		$	2,855.7			—

See accompanying Notes to Consolidated Financial Statements.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME (Continued)

(In millions, except shares)	Shares outstanding			Common stock		Other paid-in capital		Retained earnings			Treasury stock			Accumulated other comprehensive loss			Total Allegheny Energy, Inc. common stockholders’ equity			Noncontrolling interests		Total equity			Comprehensive income
Balance at December 31, 2008		169,364,394		$	211.8	$	1,952.5	$	731.6		$	(1.8	)	$	(43.3	)	$	2,850.8		$	4.9	$	2,855.7			—
Net income		—			—		—		392.8			—			—			392.8			1.3		394.1		$	394.1
Defined benefit pension and other benefit plans:
Net loss during the period, net of tax of $3.1		—			—		—		—			—			(5.3	)		(5.3	)		—		(5.3	)		(5.3	)
Amortization, net of tax of $2.1		—			—		—		—			—			3.5			3.5			—		3.5			3.5
Cash flow hedges, net of tax of $28.5		—			—		—		—			—			(44.8	)		(44.8	)		—		(44.8	)		(44.8	)
Comprehensive income		—			—		—		—			—			—			—			—		—			347.5
Comprehensive income attributable to noncontrolling interest		—			—		—		—			—			—			—			—		—			(1.3	)
Comprehensive income attributable to Allegheny Energy, Inc.		—			—		—		—			—			—			—			—		—		$	346.2
Equity contribution to PATH, LLC by the joint venture partner		—			—		—		—			—			—			—			8.7		8.7			—
Dividends on common stock		—			—		—		(101.7	)		—			—			(101.7	)		—		(101.7	)		—
Stock-based compensation expense:
Non-employee director stock awards		21,907			—		0.9		—			—			—			0.9			—		0.9			—
Stock options		—			—		7.4		—			—			—			7.4			—		7.4			—
Performance shares		—			—		7.2		—			—			—			7.2			—		7.2			—
Restricted shares		17,850			—		0.1		—			—			—			0.1			—		0.1			—
Exercise of stock options		163,700			0.2		2.1		—			—			—			2.3			—		2.3			—
Settlement of stock units		3,573			—		—		—			—			—			—			—		—			—
Purchase of treasury shares		(1,820	)		—		—		—			—			—			—			—		—			—
Balance at December 31, 2009		169,569,604		$	212.0	$	1,970.2	$	1,022.7		$	(1.8	)	$	(89.9	)	$	3,113.2		$	14.9	$	3,128.1			—

See accompanying Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME (Continued)

(In millions, except shares)	Shares outstanding			Common stock		Other paid-in capital			Retained earnings			Treasury stock			Accumulated other comprehensive loss			Total Allegheny Energy, Inc. common stockholders’ equity			Noncontrolling interests			Total equity			Comprehensive income
Balance at December 31, 2009		169,569,604		$	212.0	$	1,970.2		$	1,022.7		$	(1.8	)	$	(89.9	)	$	3,113.2		$	14.9		$	3,128.1			—
Net income		—			—		—			411.7			—			—			411.7			—			411.7		$	411.7
Defined benefit pension and other benefit plans:
Amortization and other, net of tax of $2.9 million		—			—		—			—			—			2.8			2.8			—			2.8			2.8
Net loss during the period, net of tax of $(7.7)		—			—		—			—			—			(11.6	)		(11.6	)		—			(11.6	)		(11.6	)
Adjustment to unamortized OPEB plan actuarial loss, net of tax of $5.2 million		—			—		—			—			—			7.8			7.8			—			7.8			7.8
Cash flow hedges, net of tax of $17.2		—			—		—			—			—			27.2			27.2			—			27.2			27.2
Comprehensive income		—			—		—			—			—			—			—			—			—		$	437.9
Deconsolidation of PATH- WV		—			—		—			—			—			—			—			(14.9	)		(14.9	)		—
Dividends on common stock		—			—		—			(127.3	)		—			—			(127.3	)		—			(127.3	)		—
Stock-based compensation expense:
Non-employee director stock awards		12,000			—		0.9			(0.1	)		—			—			0.8			—			0.8			—
Stock options		—			—		6.5			—			—			—			6.5			—			6.5			—
Performance shares		—			—		13.1			—			—			—			13.1			—			13.1			—
Restricted shares		—			—		0.3			—			(0.1	)		—			0.2			—			0.2			—
Exercise of stock options		85,784			0.1		1.2			—			—			—			1.3			—			1.3			—
Issuance of performance shares		309,798			0.4		(4.4	)		—			—			—			(4.0	)		—			(4.0	)		—
Purchase of treasury shares		(3,642	)		—		—			—			—			—			—			—			—			—
Balance at December 31, 2010		169,973,544		$	212.5	$	1,987.8		$	1,307.0		$	(1.9	)	$	(63.7	)	$	3,441.7		$	—		$	3,441.7			—

See accompanying Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note		Page Number
1	Business, Basis of Presentation and Significant Accounting Policies		107
2	Merger Agreement		116
3	Recently Adopted and Recently Issued Accounting Standards		117
4	Sale of Virginia Distribution Business		117
5	Rates and Regulation		118
6	Transmission Expansion		123
7	Regulatory Assets and Liabilities		125
8	Income Taxes		127
9	Capitalization and Debt		131
10	Earnings per Share		137
11	Stock-Based Compensation		137
12	Pension Benefits and Postretirement Benefits Other Than Pensions		143
13	Segment Information		152
14	Fair Value Measurements, Derivative Instruments and Hedging Activities		154
15	Purchase of Hydroelectric Generation Facilities		162
16	Jointly Owned Bath County Generation Facility		162
17	Fair Value of Financial Instruments		163
18	Goodwill and Intangible Assets		163
19	Asset Retirement Obligations (“ARO”)		164
20	Adverse Power Purchase Commitment Liability		165
21	Other Income (Expense), Net		165
22	Guarantees and Letters of Credit		166
23	Variable Interest Entities		166
24	Acquisition of Noncontrolling Interest in AE Supply		168
25	Commitments and Contingencies		168
26	Quarterly Financial Information (Unaudited)		179

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 1:  BUSINESS, BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Merger Agreement

On February 10, 2010, Allegheny Energy, Inc. (“AE”) entered into an Agreement and Plan of Merger (as amended on June 4, 2010, the “Merger Agreement”) with FirstEnergy Corp. (“FirstEnergy”) and Element Merger Sub, Inc. (“Merger Sub”), a wholly owned subsidiary of FirstEnergy. The accompanying financial statements do not reflect potential impacts or changes in accounting policies, basis of accounting, carrying values of assets and liabilities or other matters that may result from the completion of AE’s anticipated merger with FirstEnergy. See Note 2, “Merger Agreement” for additional information.

Business Description

AE (and together with its subsidiaries, “Allegheny”) is an integrated energy business. Allegheny owns and operates electric generation facilities primarily in Pennsylvania, West Virginia and Maryland. Additionally, Allegheny owns transmission assets in Pennsylvania, West Virginia, Maryland and Virginia and provides distribution services to customers in Pennsylvania, West Virginia and Maryland. Allegheny manages its operations through two business segments: Merchant Generation and Regulated Operations. These business segments are also referred to as reportable segments.

The Merchant Generation segment includes Allegheny’s unregulated electric generation operations including Allegheny Energy Supply Company, LLC (“AE Supply”) and AE Supply’s interest in Allegheny Generating Company (“AGC”). 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 Power Company (“Monongahela”), which own approximately 59% and 41% of AGC, respectively. The Merchant Generation segment is subject to various federal and state regulations but, unlike the Regulated Operations segment, is not generally subject to state regulation of rates.

The Regulated Operations segment includes the operations of Monongahela, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn” and, together with Monongahela and Potomac Edison, the “Distribution Companies”), which primarily operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia and Maryland, as well as transmission in Virginia. Monongahela also owns and operates electric generation facilities in West Virginia and has a 41% interest in AGC. The Distribution Companies are subject to various federal and state regulations, including state regulation of rates.

The Regulated Operations segment also includes the operations of Trans-Allegheny Interstate Line Company (“TrAIL Company”) and Allegheny’s interests in Potomac-Appalachian Transmission Highline, LLC (“PATH, LLC”). These entities were created to construct or facilitate the construction of high voltage transmission lines and other transmission facilities, including the Trans-Allegheny Interstate Line (“TrAIL”) and the Potomac-Appalachian Transmission Highline (“PATH”). PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (“PATH-WV”), which is a joint venture with a subsidiary of American Electric Power Company, Inc. (“AEP”). Allegheny accounts for its interest in PATH-WV using the equity method of accounting, effective January 1, 2010. TrAIL Company, PATH-Allegheny and PATH-WV are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). See Note 3, “Recently Adopted and Recently Issued Accounting Standards” for additional information.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of Allegheny’s personnel. As of December 31, 2010, AESC employed 4,211 employees, 1,197 of whom were subject to collective bargaining arrangements.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of AE and its subsidiaries, as well as certain variable interest entities (See Note 23, “Variable Interest Entities,” for additional information). These consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of derivative and energy contracts, asset retirement obligations, the effects of regulation, long-lived asset recovery, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

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 regulated utility operations industry specific accounting provisions. 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, revenues or other comprehensive income 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 regulated industry specific accounting provisions and considers factors such as regulatory changes and the impact of competition. If regulated industry specific accounting provisions would no longer apply to some portion of Allegheny’s operations, Allegheny would eliminate the related regulatory assets and liabilities and record the impact as an extraordinary item in the statement of income. See Note 7, “Regulatory Assets and Liabilities,” for additional information.

Revenues and Receivables

Revenues from the sale of generation are recorded in the period in which the electricity is delivered.

PJM Interconnection, LLC (“PJM”) is a regional transmission organization that operates a competitive wholesale energy market. To facilitate the economic dispatch of Allegheny’s generation, AE Supply and Monongahela sell the power they generate into the PJM market and purchase from the PJM market the power needed to meet their contractual obligations to supply power. PJM power purchases and sales are reported on a net basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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. Energy billings to individual customers are based on meter readings, which are performed periodically on a systematic basis. At the end of each month, the amount of energy delivered to each customer is estimated based in part on the most recent reading of the customer’s meter, and the Distribution Companies recognize unbilled revenues that reflect these estimates. 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 provision for uncollectible accounts, which is determined based upon Allegheny’s collection experience with its customers, is recorded as a component of operations and maintenance expense.

Fair Value Measurements, Derivative Instruments and Hedging Activities

Derivative contracts are recorded in Allegheny’s Consolidated Balance Sheets at fair value. Changes in the fair value of the derivative contract are included in revenues on the Consolidated Statements of Income unless the derivative falls within the “normal purchases and normal sales” scope exception or is designated as a cash flow 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 and that are designated in a hedging relationship, the effective portion of the changes in fair value of the derivative contract is recorded as a separate component of equity under the caption “Accumulated other comprehensive loss” and subsequently reclassified into earnings when the forecasted transaction is settled and impacts earnings. The ineffective portion of the hedge is immediately recognized in earnings.

Fair values for exchange-traded instruments, principally futures, 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, financial transmission rights (“FTRs”) and swaps, management uses available market data and pricing models to estimate fair values. Estimating the fair values of instruments that do not have quoted market prices requires management’s judgment in determining amounts that 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. These agreements 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 derivative assets, liabilities and cash collateral and accounts receivable and accounts payable with each counterparty on a net basis. Cash flows associated with derivative contracts are recorded in cash flows from operating activities. See Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for additional details regarding energy transacting activities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Deferred Energy Costs

Deferred energy costs represent the deferral of certain energy costs from the period in which they were incurred to the period in which such costs are recovered in rates. Allegheny records deferred energy costs relating to the following items:

Expanded Net Energy Cost (“ENEC”)

In May 2007, the Public Service Commission of West Virginia (the “West Virginia PSC”) issued an order that re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs, including purchased power costs associated with the Grant Town PURPA generation facility and other related expenses, net of related revenue and interest earnings on the Fort Martin Scrubber project escrow fund. Under the ENEC, actual costs and revenues are tracked for under and/or over recoveries, and revised ENEC rate filings are made on an annual basis. Any under and/or over recovery of costs, net of related revenues, is deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability, with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.” See Note 5, “Rates and Regulation,” and Note 7, “Regulatory Assets and Liabilities,” for additional information.

Market-based Generation Costs

Potomac Edison is authorized by the Public Service Commission of Maryland (the “Maryland PSC”) to recover the costs of the generation component of power sold to certain residential, commercial and industrial customers who did not choose a third-party alternative generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet for any under-recovery or over-recovery of the generation component of costs charged to these customers.

AES Warrior Run PURPA Generation Facility

To satisfy certain of its obligations under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), Potomac Edison entered into a long-term contract beginning July 1, 2000 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 pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge.

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 primarily using the effective interest method.

Common Services and Intercompany Transactions

Common Services.  Substantially all of Allegheny’s personnel are employed by AESC, which performs services at cost for other Allegheny entities and makes payments on behalf of Allegheny entities. Each entity is responsible for its share of the cost of services provided by AESC and payments made by AESC on behalf of the entities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

Power Sales and Purchases.  AE Supply provides power to Potomac Edison and West Penn to satisfy a portion of the power necessary to meet their respective retail load. 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 on a proportionate basis, based on their respective equity ownership of AGC. Additionally, Monongahela sells Potomac Edison the power necessary to service its West Virginia customers.

Leases.  West Penn and Monongahela own property, including buildings and software, that they lease primarily to AESC for its use in providing services to AE and its affiliates.

Long-Lived Assets

Property, Plant and Equipment

Property, plant and equipment (“property”) is recorded at original cost. This cost includes direct labor, materials and indirect costs, such as operation, maintenance and depreciation of transportation and construction equipment, taxes, postretirement benefits and other benefits related to employees to the extent they are engaged in construction. In addition, property subject to rate regulation includes an allowance for funds used during construction on property for which construction work in progress is not included in rate base. Property not subject to rate regulation includes capitalized interest during the construction period.

Upon retirement of property, no gain or loss is generally recognized and the original cost of the property less salvage is charged to accumulated depreciation. The cost of removal of regulated property is charged to the related regulatory liability or regulatory asset, and the cost of removal of unregulated property, for which no asset retirement obligation (“ARO”) has been recorded, is expensed as incurred.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 items of property are expensed as maintenance. Depreciation expense was approximately 2.5% of average depreciable property in 2010 and 2.3% of average depreciable property in 2009 and 2008. Estimated service lives for generation, T&D and other property at December 31, 2010 were as follows:

	Years
Generation property:
Steam scrubbers and equipment		43-65
Steam generator units		45-80
Internal combustion units		40-44
Hydroelectric dams and facilities		50-152
Transmission and distribution property:
Electric equipment		10-100
Easements		70-100
Other property:
Office buildings and improvements		42-60
General office and other equipment		10-25
Vehicles and transportation		7-25
Computers, software and information systems		5-20

The cost of repairs, maintenance including planned major maintenance activities, and minor replacements of property are charged to maintenance expense as incurred.

Capitalized Interest and Allowance for Funds Used During Construction (“AFUDC”)

For non-regulated companies, Allegheny capitalizes interest costs associated with construction activities. The average interest capitalization rates in 2010, 2009, and 2008 were 6.9%, 6.0% and 6.6%, respectively. Allegheny capitalized $2.7 million, $25.9 million, and $34.6 million of interest during 2010, 2009, and 2008, respectively.

AFUDC is a component of the construction of Property, Plant and Equipment defined in the applicable regulatory uniform system of accounts as representing “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 capitalized in those instances in which the related construction work in progress is not included in rate base in the rate setting process and is reflected in the Consolidated Statements of Income as a reduction to Interest expense and Other income (expense), net to the extent it relates to borrowed funds and other funds used in construction, respectively. Rates used by the regulated subsidiaries in computing AFUDC in 2010, 2009 and 2008 averaged 8.3%, 7.3% and 7.2%, respectively. Allegheny recorded AFUDC of $9.6 million in 2010, $8.3 million in 2009 and $6.6 million in 2008, of which $6.3 million, $5.0 million and $3.7 million was reflected in “Other income (expense), net” and $3.3 million, $3.3 million and $2.9 million was reflected as a reduction to “Interest expense” in 2010, 2009 and 2008, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Asset Impairment

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 to be generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Allegheny did not record any impairment charges during 2010, 2009 or 2008.

Asset Retirement Obligations and Cost of Removal

A liability for the fair value of an asset retirement obligation (“ARO”) is recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a part of the carrying amount of the long-lived assets. The asset retirement cost is subsequently charged to expense over its useful life. Changes in the ARO resulting from the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense, or as an adjustment to the related regulatory asset or regulatory liability. Changes resulting from revisions to the timing or amount of the original estimate of cash flows are recognized as an increase or decrease in the asset retirement cost and ARO. When settled, actual costs to retire the asset are charged against the recorded ARO liability.

In addition, the Distribution Companies and TrAIL Company recover cost of removal (“COR”) for property, plant and equipment in their rates. In some jurisdictions, the recovery is provided prior to the time of asset retirement, in which case, the amounts collected are recorded as a regulatory liability. When incurred, COR costs are charged to the regulatory liability. In other jurisdictions, the amounts are recovered only after being incurred, in which case, the COR costs incurred are recorded as a regulatory asset until recovered.

Goodwill and Intangible Assets

Goodwill represents the acquisition cost of a business combination in excess of fair value of tangible and intangible assets acquired, less liabilities assumed. Recorded goodwill is not amortized, but is tested 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 18, “Goodwill and Intangible Assets” for additional information.

Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates are typically accounted for under the equity method of accounting. The income or loss on such investments is recorded in “Other income (expense), net” in the Consolidated Statements of Income. Investments in unconsolidated affiliates at December 31, 2010 primarily consisted of $23.6 million relating to PATH-WV, which Allegheny consolidated until January 1, 2010, and Allegheny’s investment of $23.7 million, through AE Supply, in Buchanan Generation LLC. Investments in unconsolidated affiliates at December 31, 2009, primarily consisted of Allegheny’s investment, through AE Supply, in Buchanan Generation LLC of $24.1 million. See Note 23, “Variable Interest Entities” for information relating to variable interest entities.

Cash Equivalents

For purposes of the Consolidated Statements of Cash Flows and Consolidated Balance Sheets, investments in money market funds and highly liquid investments purchased with original maturities of three months or less are considered to be the equivalent of cash.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Restricted Funds

At December 31, 2010 and 2009, Allegheny had current restricted funds of $46.9 million and $25.9 million, respectively. Current restricted funds at December 31, 2010 included $25.0 million of funds collected from West Virginia customers that will be used to service the environmental control bonds issued in connection with the construction of the flue gas desulfurization equipment (“Scrubbers”) at Fort Martin, $19.3 million of medical benefit trust assets and $2.6 million of contractually restricted bid assurances. Current restricted funds at December 31, 2009 included $20.6 million of funds collected from West Virginia customers that will be used to service the environmental control bonds issued in connection with the construction of Scrubbers at the Fort Martin generating facility and $5.3 million of intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. In addition, at December 31, 2010 and 2009, Allegheny had long-term restricted funds of $29.4 million and $60.2 million, respectively. Long-term restricted funds at December 31, 2010 included $29.4 million of funds relating to proceeds from the issuance of ratepayer obligation bonds issued in connection with the construction of Scrubbers at the Fort Martin generating facility. Long-term restricted funds at December 31, 2009 included $10.3 million of funds remaining from the $235 million Pennsylvania Development Financing Authority bond issued in connection with the construction and installation of Scrubbers at the Hatfield’s Ferry generating facility, $49.6 million of funds relating to proceeds from the issuance of ratepayer obligation bonds issued in connection with the construction of Scrubbers at the Fort Martin generating facility and $0.3 million of escrow funds related to the Scrubber construction projects.

Collateral Deposits

Allegheny posts collateral with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. Approximately $30.7 million and $20.8 million of cash collateral deposits were included in current assets at December 31, 2010 and 2009, respectively. Approximately $6.5 million and $3.1 million of cash collateral deposits were netted against derivative liabilities on the Consolidated Balance Sheets at December 31, 2010 and 2009, respectively.

In addition, no collateral deposits were netted against derivative assets on the Consolidated Balance Sheets at December 31, 2010, and approximately $27.5 million of counterparty collateral deposits were netted against derivative assets on the Consolidated Balance Sheets at December 31, 2009.

Inventory

Allegheny records materials, supplies and fuel inventory, including emission allowances, using the average cost method.

Income Taxes

Allegheny computes income taxes under the liability method. Deferred income tax balances are generally determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Tax benefits are recognized in the financial statements when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. Such tax positions are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.

Deferred income tax assets have also been recorded on the tax effects of net operating losses that are more likely than not to be realized through future operations and through the reversal of existing temporary

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differences. Allegheny has deferred investment tax credits associated with its regulated business and assets previously held by its regulated business. These investment tax credits are amortized to income on a straight-line basis over the life of the assets. See Note 8, “Income Taxes” for additional information.

Taxes Collected from Customers and Remitted to Governmental Authorities

Allegheny records taxes collected from customers, which are directly imposed on a transaction with that customer, on a net basis. That is, in instances in which Allegheny acts as a collection agent for a taxing authority by collecting taxes that are the responsibility of the customer, Allegheny records the amount collected as a liability and relieves such liability upon remittance to the taxing authority without impacting revenues or expenses.

Pension and Other Postretirement Benefits

Allegheny sponsors a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. Allegheny also maintains a Supplemental Executive Retirement Plan for certain senior executives. Allegheny also provides subsidies for medical and life insurance plans for eligible retirees and dependents. Eligible retirees are charged premiums for medical coverage based on plan provisions, including age and years-of-service.

Pension and other postretirement benefit expense is determined by an actuarial valuation, based on assumptions that are evaluated annually.

See Note 12, “Pension Benefits and Postretirement Benefits Other Than Pensions” for additional information.

Stock-Based Compensation

Share-based payments are generally measured at fair value on the date of grant and are expensed over the requisite service period. For options, Allegheny is entitled to income tax deductions in an amount equal to the fair value of shares on the date of the option exercise less the option exercise price. To the extent that the income tax deduction exceeds the cumulative compensation expense recorded for book purposes, the tax effect of the excess (referred to as a windfall tax benefit) is recorded as a credit to stockholders’ equity when the tax benefit is realized. See Note 11, “Stock-Based Compensation” for additional information.

Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss, included in the shareholders’ equity section of the Consolidated Balance Sheets, were as follows:

	December 31,
(In millions)	2010			2009
Cash flow hedges, net of tax of $6.4 million and $(10.8) million, respectively	$	10.4		$	(16.8	)
Net unrecognized pension and other benefit plan costs, net of tax of $(49.3) million and $(49.7) million, respectively		(74.1	)		(73.1	)
Total	$	(63.7	)	$	(89.9	)

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NOTE 2:  MERGER AGREEMENT

Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into AE (the “Merger”), with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FirstEnergy. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended, and be tax-free to AE stockholders. Pursuant to the Merger Agreement, upon completion of the Merger, each issued and outstanding share of AE’s common stock, including grants of restricted stock, would automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy. This ratio is fixed, and the Merger Agreement does not provide for any adjustment to reflect stock price changes prior to completion of the Merger.

Pursuant to the Merger Agreement, completion of the Merger is subject to various customary conditions, including (i) approvals by shareholders of both companies; (ii) the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger; (iii) expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Anti-Trust Improvements Act of 1976; (iv) receipt of all required regulatory approvals, including approvals by FERC and state public service and utility commissions in Virginia, Maryland, Pennsylvania and West Virginia; (v) the absence of any governmental action challenging or seeking to prohibit the Merger and (vi) the absence of any material adverse effect with respect to either Allegheny or FirstEnergy.

Shareholder Approvals.  On July 16, 2010, FirstEnergy’s registration statement on Form S-4 containing a joint proxy statement/prospectus relating to the proposed Merger was declared effective by the SEC, and AE stockholders and FirstEnergy shareholders approved the various proposals related to the Merger in separate shareholder meetings on September 14, 2010.

Hart-Scott-Rodino.  On January 7, 2011, the U.S. Department of Justice (the “DOJ”) notified AE and FirstEnergy that it had completed its review of the proposed Merger pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and closed its investigation.

FERC.  On December 16, 2010, FERC approved the proposed Merger.

Virginia SCC.  The Virginia SCC issued a decision approving the proposed Merger on September 9, 2010.

West Virginia PSC.  On November 3, 2010, AE and FirstEnergy filed a comprehensive settlement with the West Virginia PSC that resolved all issues raised by the parties in the merger proceedings in West Virginia. The settlement includes certain commitments that will apply if the proposed Merger is completed, including: a commitment to maintain a regional headquarters for Allegheny’s West Virginia utility operations within Monongahela’s service territory; $7.5 million in rate reductions over a two-year period for Allegheny’s West Virginia customers; a commitment to maintain customer call center operations in Fairmont, West Virginia for at least five years; additional funding totaling $500,000 over a four-year period for Dollar Energy Fund in West Virginia and an agreement that certain merger-related costs will not be recoverable in customer rates. The West Virginia PSC approved the settlement and the proposed Merger on December 16, 2010.

Maryland PSC.  On December 1, 2010, AE and FirstEnergy filed a comprehensive settlement with the Maryland PSC that addressed the issues raised by 10 parties to the merger proceedings in Maryland. The settlement includes certain commitments that will apply if the proposed Merger is completed, including a commitment to maintain a regional headquarters for Potomac Edison’s Maryland service territory, $6.5 million in rate reductions over a four-year period for Potomac Edison’s Maryland customers and an agreement that certain merger-related costs will not be recoverable in customer rates. The Maryland PSC approved the settlement and the proposed Merger on January 18, 2011, subject to certain conditions, including crediting residential customers for the $6.5 million rate reduction within the first three months following the Merger.

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Pennsylvania PUC.  On October 22, 2010, AE and FirstEnergy filed a comprehensive settlement with the Pennsylvania PUC that addresses the issues raised by 18 parties to the merger proceedings in Pennsylvania. The settlement includes certain commitments that will apply if the proposed Merger is completed, including commitments related to employment levels, including a five-year commitment to maintain certain minimum employment levels in Greensburg and Westmoreland County, an approximately $11 million in distribution rate credits for West Penn customers, a $6.19 million credit for certain West Penn customers for costs related to energy-efficiency and conservation programs due to recently proposed changes in West Penn’s smart meter implementation plan and an agreement that certain merger-related costs will not be recoverable in customer rates. The settlement is subject to approval by the Pennsylvania PUC and does not resolve issues raised by certain parties who did not join in the settlement.

AE and FirstEnergy currently anticipate completing the proposed Merger in the first quarter of 2011.

NOTE 3:  RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS

Consolidations and Variable Interest Entities

Allegheny adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2009-17 (Consolidations Topic 810), “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” on January 1, 2010. Under this new guidance, consolidation of a variable interest entity (“VIE”) is required by an enterprise (the “primary beneficiary”), if any, that is determined qualitatively to have both the power to direct the activities that most significantly impact the VIE’s economic success and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. Under the prior guidance, the primary beneficiary (consolidator) of a VIE was the party that absorbed a majority of the expected losses or the majority of the expected residual returns of the VIE using a quantitative analysis.

Through December 31, 2009, Allegheny consolidated PATH-WV for financial statement purposes, because Allegheny determined that PATH-WV was a VIE and that Allegheny was its primary beneficiary under the prior accounting standard. Under the new accounting standard, Allegheny determined that it is not the primary beneficiary of PATH-WV, and therefore deconsolidated PATH-WV for financial statement purposes, effective January 1, 2010. Allegheny did not retrospectively apply this new guidance by deconsolidating PATH-WV in its financial statements for periods prior to January 1, 2010. The deconsolidation of PATH-WV did not impact retained earnings or net income attributable to AE. See Note 23, “Variable Interest Entities,” for additional information.

Fair Value Measurements and Disclosures

Allegheny adopted the FASB’s ASU No. 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements” in January 2010. The ASU added new requirements for disclosures about transfers into and out of fair value Levels 1 and 2 and separate disclosures about purchases, sales, issuances and settlements relating to Level 3 measurements. The ASU also clarified existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. Allegheny’s adoption of this ASU did not affect its results of operations or financial position.

NOTE 4:  SALE OF VIRGINIA DISTRIBUTION BUSINESS

On June 1, 2010, Potomac Edison sold its electric distribution business in Virginia (the “Virginia distribution business”) to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative. Cash proceeds from the sale were approximately $317 million, resulting in a pre-tax gain of approximately $45 million.

The Virginia distribution business was included in the Regulated Operations segment. Assets and liabilities relating to the Virginia distribution business were classified as “held for sale” in Allegheny’s consolidated

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balance sheet, and depreciation expense on those assets ceased, as of May 1, 2009. The operating results of the Virginia distribution business have not been reported as discontinued operations, because AE Supply will continue to provide the majority of the power to serve the customers of this business through June 30, 2011 under a power sales agreement. Assets held for sale and liabilities associated with assets held for sale at December 31, 2009 were as follows:

(In millions)	December 31, 2009
Current Assets:
Accounts receivable	$	31.2
Materials and supplies		0.7
Regulatory assets		0.5
Total current assets		32.4
Property, Plant and Equipment:
Distribution property, plant and equipment		344.9
Accumulated depreciation		(91.2	)
Property, plant and equipment, net		253.7
Total assets held for sale	$	286.1
Current Liabilities:
Customer deposits	$	5.5
Regulatory liabilities		3.7
Other		0.9
Total current liabilities		10.1
Deferred Credits and Other Liabilities:
Regulatory liabilities		51.8
Other		1.3
Total deferred credits and other liabilities		53.1
Total liabilities associated with assets held for sale	$	63.2

In connection with the sale, Potomac Edison agreed to contribute $27.5 million between July 1, 2011 and July 1, 2014 to reduce the impact of any future rate increases and the obligation for such contributions was included in the calculation of the gain on the sale of this business. On December 31, 2010, Potomac Edison purchased Shenandoah Valley Electric Cooperative’s West Virginia distribution business for approximately $14.5 million, subject to certain post-closing adjustments.

NOTE 5:  RATES AND REGULATION

Pennsylvania

Rates.  Rate caps on transmission services in Pennsylvania expired on December 31, 2005. Distribution rate caps were also scheduled to expire on December 31, 2005 and generation rate caps were scheduled to expire on December 31, 2008. By order entered May 11, 2005, the Pennsylvania Public Utility Commission (the “Pennsylvania PUC”) approved an extension of generation rate caps for West Penn customers from 2008 to 2010 and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously approved rate cap increases for 2006 and 2008. The order 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. The intent of this transition plan was to gradually move generation rates closer to market prices. T&D rates for all customers are subject to traditional

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regulated utility ratemaking (i.e., cost-based rates). West Penn’s transition period ended for the majority of its customers on December 31, 2010, when its generation rate caps expired.

Advanced Metering and Demand-Side Management Initiatives.  In October 2008, Pennsylvania adopted Act 129, which includes a number of measures relating to conservation, demand-side management and power procurement processes. Act 129 requires each electric distribution company (“EDC”) with more than 100,000 customers to adopt a plan, approved by the Pennsylvania PUC, to reduce, by May 31, 2011, electric consumption by at least one percent of its expected consumption for June 1, 2009 through May 31, 2010. By May 31, 2013, the total annual weather-normalized consumption is to be reduced by a minimum of three percent, and peak demand is to be reduced by a minimum of four and one-half percent of the EDC’s annual system peak demand. Act 129 also:

• directed the Pennsylvania PUC to adopt an energy conservation and efficiency program to require EDCs to develop and file, by July 1, 2009, plans to reduce energy demand and consumption; and

• required EDCs to file a plan for “smart meter” technology procurement and installation in August 2009.

West Penn expects to incur significant capital expenditures to comply with these requirements.

Act 129 also requires EDCs to obtain energy through a prudent mix of contracts, with an emphasis on competitive procurement. The Act includes a “grandfather” provision for West Penn’s procurement and rate mitigation plan, which was previously approved by the Pennsylvania PUC.

In June 2009, West Penn filed its Energy Efficiency and Conservation (“EE&C”) Plan containing 22 programs to meet its Act 129 demand and consumption reduction obligations. The proposed programs cover most energy-consuming devices of residential, commercial and industrial customers. The EE&C Plan also proposed a reconcilable surcharge mechanism to obtain full and current cost recovery of the EE&C Plan costs as provided in Act 129. The EE&C Plan projected an aggregated cost of the energy efficiency measures in the amount of approximately $94.3 million through mid 2013. A hearing concerning West Penn’s EE&C Plan was held August 19, 2009.

The Pennsylvania PUC approved West Penn’s EE&C Plan, in large part, by Opinion and Order entered October 23, 2009. The new programs approved by the Pennsylvania PUC include: rebates for customers who purchase high efficiency appliances, lighting and heating and cooling systems; residential home audits and rebates toward implementing audit recommendations; home audit, weatherization and air conditioner replacement programs for low-income customers; new rate options that will provide financial incentives for customers to lower their demand for electricity or shift their usage to lower-priced times; incentives for customers who install in-home devices that reduce electric usage when demand is highest; and various programs for commercial, industrial, government and non-profit customers to increase energy efficiency and conservation. The Pennsylvania PUC also approved West Penn’s proposal to recover its EE&C Plan costs on a full and current basis via an automatic surcharge to customers’ bills, subject to an annual reconciliation mechanism.

The Pennsylvania PUC declined to approve West Penn’s proposed distributed generation program and West Penn’s proposed contract demand response program and encouraged West Penn to submit revisions to both programs. On December 21, 2009, West Penn filed an Amended EE&C Plan as directed by the Pennsylvania PUC, in which it added a new customer resources demand response program intended to replace the previously proposed distributed generation and contract demand programs. The Pennsylvania PUC reviewed West Penn’s amended Plan at its public meeting on February 11, 2010 and ordered West Penn to file an amended plan within 60 days to include additional detail on the costs associated with the previously approved customer load response program and the new customer resources demand response program.

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On August 14, 2009, West Penn filed its Smart Meter Technology Procurement and Installation Plan. The Plan provided for extensive deployment of smart meter infrastructure with replacement of all of West Penn’s approximately 725,000 meters by the end of 2014. On December 18, 2009, West Penn filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less rapid deployment of smart meters. On January 13, 2010, the Pennsylvania PUC granted the motion to reopen the record and remanded the proceeding to the ALJ. The Pennsylvania PUC also waived the late January 2010 deadline by which the ALJ’s recommended decision would have been required. The hearing was held on March 16, 2010, and on May 6, 2010, the ALJ issued a decision finding that West Penn’s alternative smart meter deployment plan, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including West Penn’s proposed cost recovery mechanism, by the Pennsylvania PUC.

However, in light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades as previously proposed, as well as its evaluation of recent Pennsylvania PUC decisions approving less rapid deployment proposals by other EDCs, West Penn undertook to re-evaluate its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. On July 21, 2010, the Pennsylvania PUC issued an order, in response to West Penn’s request, to stay West Penn’s smart meter implementation proceedings for a period of 90 days. On September 10, 2010, West Penn filed an Amended EE&C Plan that is less reliant on smart meter deployment and emphasized non-smart meter programs to meet the conservation and demand reduction requirements of Act 129. Additionally, on October 19, 2010, West Penn and Pennsylvania’s Office of Consumer Advocate filed a Joint Petition for Settlement addressing West Penn’s smart meter implementation plan with the Pennsylvania PUC. Under the terms of the proposed Settlement, West Penn proposes to decelerate its previously contemplated smart meter deployment schedule, targeting the installation of an estimated 25,000 smart meters, based on customer requests, by mid-2012, in support of its EE&C Plan. Thereafter, West Penn proposes to install an additional 15,000 smart meters by 2013 and an additional 60,000 smart meters between 2013 and 2016. The proposed Settlement also contemplates that West Penn take advantage of the 30-month grace period authorized by the Pennsylvania PUC to continue its efforts to re-evaluate its full-scale smart meter deployment plans, and that it file a revised smart meter implementation plan reflecting those efforts, including its proposed plans for full-scale deployment of smart meters, which West Penn currently anticipates filing in June 2012. Under the terms of the proposed Settlement, West Penn would be permitted to recover certain previously-incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period and other expenditures amortized through 2017, in each case with interest on deferred amounts. Additionally, West Penn would be permitted to seek recovery of certain other costs as part of its revised smart meter implementation plan for full-scale deployment that it currently intends to file in June 2012 or in a future base distribution rate case. On December 8, 2010, the Pennsylvania PUC directed that the smart meter implementation proceeding be referred to the Administrative Law Judge for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement filed in October 2010 had adequate support in the record.

On December 17, 2010, an Administrative Law Judge issued a Recommended Decision that the Amended EE&C Plan filed by West Penn in September 2010 be approved. By order entered January 13, 2011, the Pennsylvania PUC approved West Penn’s Amended EE&C plan.

West Penn’s actual cost to implement smart meter infrastructure may vary from its previous estimates as a result of changes in its procurement and installation plan as ultimately approved by the Pennsylvania PUC and the timing of that approval, among other factors.

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West Virginia

Rates.  Rates in West Virginia are subject to traditional regulated utility ratemaking (i.e., cost-based rates).

Rate Case.  On August 13, 2009, Monongahela and Potomac Edison filed with the West Virginia PSC a request to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. On January 12, 2010, Monongahela and Potomac Edison filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement that is approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of Monongahela and Potomac Edison completed a securitization transaction to finance certain costs associated with the installation of Scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently, Monongahela and Potomac Edison ultimately requested an increase in retail rates of approximately $95 million, rather than $122.1 million, annually. On April 2, 2010, Monongahela and Potomac Edison filed with the West Virginia PSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:

• a $40 million annualized base rate increase effective June 29, 2010;

• a deferral of $9 million of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;

• an additional $20 million annualized base rate increase effective in January 2011;

• a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and

• a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.

The West Virginia PSC approved the Joint Petition and Agreement of Settlement on June 25, 2010.

Annual Adjustment of Fuel and Purchased Power Cost Rates.  On August 29, 2008, Monongahela and Potomac Edison filed with the West Virginia PSC a request to increase retail rates by approximately $173 million annually to reflect expected increases in fuel and purchased power costs during 2009 and under-recovery of past costs through June 2008. The new rates, proposed to become effective January 1, 2009, were submitted pursuant to the schedule for annual fuel and purchased power cost reviews in connection with Monongahela’s and Potomac Edison’s purchased power cost recovery clause in West Virginia. On December 29, 2008, the West Virginia PSC issued an order approving a settlement agreement among Allegheny, the Consumer Advocate Division, the Staff of the West Virginia PSC and the West Virginia Energy Users Group, pursuant to which Allegheny’s rates in West Virginia were increased by $142.5 million annually beginning on January 1, 2009.

On September 1, 2009, Monongahela and Potomac Edison filed their annual fuel adjustment request with the West Virginia PSC, requesting a rate increase of $143.2 million to reflect increases in their unrecovered balances of fuel and purchased power costs that have accrued through June 2009 and projected increases through June 2010. The new rates were submitted pursuant to the schedule for annual fuel and purchased power cost reviews. On December 2, 2009, the parties to the proceeding filed a Joint Stipulation providing that Monongahela and Potomac Edison would receive an increase of $118 million, effective January 1, 2010, plus deferred recovery of an additional $23.1 million effective January 1, 2011, with carrying charges of 6% on the deferred amount. The West Virginia PSC approved the Joint Stipulation on December 29, 2009.

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Maryland

Rates.  In 1999, Maryland adopted electric industry restructuring legislation, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation supplier. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply but remained obligated to provide standard offer generation service, or “SOS,” at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. As discussed below, Potomac Edison has implemented a rate stabilization plan to transition customers from capped generation rates to rates based on market prices. T&D rates for all customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).

Rate Stabilization.  In special session on June 23, 2006, the Maryland legislature passed emergency legislation, directing the Maryland PSC to, among other things, investigate options available to Potomac Edison to implement a rate mitigation or rate stabilization plan for SOS to protect its residential customers from rate shock in connection with the January 1, 2009 expiration of generation rate caps.

In December 2006, Potomac Edison filed with the Maryland PSC a proposed Rate Stabilization Ramp-Up Transition Plan designed to transition residential customers from capped generation rates to rates based on market prices. Under the plan as approved by the Maryland PSC, residential customers who did not elect to opt out of the program began paying a surcharge in June 2007. The application of the surcharge resulted in an overall rate increase of approximately 15% in 2007 and 13% in 2008. With the expiration of the residential generation rate caps and the move to generation rates based on market prices on January 1, 2009, the surcharge converted to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, were returned to customers as a credit on their electric bills through December 2010, thereby reducing the effect of the rate cap expiration. The resulting rate increase in 2009 was 11.3%, and the rate change approved in 2009 for 2010 was actually a decrease of 2.5%. Of Potomac Edison’s approximately 219,000 residential customers in Maryland, as of December 31, 2010, approximately 21.5% elected to opt-out of, or are not eligible for, Potomac Edison’s plan.

Advanced Metering and Demand Side Management Initiatives.  On September 28, 2007, the Maryland PSC issued an order in this case that required the utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that in Maryland electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015. On October 26, 2007, Potomac Edison filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The Maryland PSC conducted hearings on Potomac Edison’s and other utilities’ plans in November 2007 and further hearings on May 7, 2008.

In a related development, the Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals and setting a deadline of September 1, 2008 for the utilities to file comprehensive plans for attempting to achieve those goals. Potomac Edison filed its proposals on August 29, 2008, asking the Maryland PSC to approve seven programs for residential customers, five programs for commercial, industrial, and governmental customers, a customer education program, and a pilot deployment of Advanced Utility Infrastructure (“AUI”) that Allegheny has previously been testing in West Virginia. On December 31, 2008, the Maryland PSC issued an order approving some of Potomac Edison’s programs and directing that others be redesigned. Potomac Edison filed its revised programs on March 31, 2009, with new cost and benefit information. The Maryland PSC approved the programs on August 6, 2009, and approved cost recovery for the programs on October 6, 2009. Expenditures are expected to be approximately $101 million and will be recovered over the next six years. Meanwhile, the AUI pilot was placed on a separate track and is currently being re-examined after discussion with the Staff of the Maryland PSC and other stakeholders.

See Note 6, “Transmission Expansion,” for information regarding rates and regulation related to the PATH and TrAIL projects.

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NOTE 6:  TRANSMISSION EXPANSION

Trans-Allegheny Interstate Line

TrAIL is a 500 kV high voltage line that is to extend from southwestern Pennsylvania through West Virginia to a point of interconnection with Virginia Electric and Power Company (“Dominion”) in northern Virginia. In addition, TrAIL Company and Dominion will jointly own an approximately 30-mile 500 kV line segment that Dominion will construct in Virginia. TrAIL is scheduled to be completed and placed in service no later than June 2011.

In June 2006, the board of directors of PJM approved TrAIL and designated Allegheny to build the Allegheny Power Zone (the “AP Zone”) portion of the line. PJM, which is a regional transmission operator, is responsible for the operation of, and reliability planning for, the transmission network in the PJM region and included the new line in its 2006 regional transmission expansion plan. In October 2006, Allegheny formed TrAIL Company as the entity responsible for financing, constructing, owning, operating and maintaining the new line.

In addition to TrAIL, other TrAIL Company projects include a new static volt-ampere reactive power compensator at the Black Oak substation, upgrades and/or replacements of transformers and/or buses at other substations and the construction of a new transmission operations center located in West Virginia, which was completed in 2010.

Potomac-Appalachian Transmission Highline

In June 2007, the board of PJM directed the construction of the PATH Project, a high-voltage transmission line project. In September 2007, Allegheny and AEP formed PATH, LLC to construct and operate PATH. PATH, LLC is a series limited liability company. The “West Virginia Series” is owned equally by Allegheny and a subsidiary of AEP. The “Allegheny Series” is 100% owned by Allegheny.

The PATH Project is comprised of a 765 kV transmission line that is proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of PATH in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 2015. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. If after further analysis PJM determines that the PATH Project is not required by June 2015 to address potential NERC reliability violations, it may delay the required in-service date for PATH to a later date or indefinitely, or it may suspend or cancel the project.

Applications requesting authorization to construct the PATH Project are currently pending before state commissions in West Virginia, Maryland and Virginia. Allegheny anticipates that decisions by the state commissions on these applications will be issued in the third quarter of 2011 in Virginia and Maryland and in the first quarter of 2012 in West Virginia.

See Note 23, “Variable Interest Entities,” for additional information relating to PATH-WV.

Federal Regulation and Rate Matters

TrAIL.  In July 2008, FERC approved a settlement that provides for an incentive return on equity of 12.7% for TrAIL and the Black Oak SVC and a return on equity of 11.7% for any other projects TrAIL Company may undertake for which no incentive return was requested. TrAIL Company was also granted the following incentives:

• a return on construction work in process prior to the in-service date of TrAIL and

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• recovery of prudently incurred development and construction costs if TrAIL is abandoned as a result of factors beyond its control.

PATH Project.  PATH, LLC submitted a filing to FERC under Section 205 of the FPA in December 2007 to implement a formula rate tariff effective March 1, 2008. The filing also included a request for certain incentive rate treatments. In February 2008, FERC issued an order setting the cost of service formula rate to calculate annual revenue requirements for the project and granting the following incentives:

• a return on equity of 14.3%;

• a return on CWIP;

• recovery of prudently incurred start-up business and administrative costs incurred prior to the time the rates go into effect; and

• recovery of prudently incurred development and construction costs if the PATH Project is abandoned as a result of factors beyond the control of PATH, LLC.

In December 2008, PATH, LLC submitted to FERC a settlement of the formula rate and protocols with the active parties that resolves all issues set for hearing. The return on equity was not included in the settlement because it was authorized by the February 2008 order and not set for hearing. On November 19, 2010, FERC approved the settlement, set the base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its operating results.

State Regulation Matters

Pennsylvania

By order entered on December 12, 2008, the Pennsylvania PUC authorized TrAIL Company to construct a 1.2 mile portion of TrAIL in Pennsylvania from the proposed 502 Junction Substation in Greene County to the Pennsylvania-West Virginia state line. In the same order, the Pennsylvania PUC also authorized TrAIL Company to engage in a collaborative process to identify possible solutions to reliability problems in the Washington County, Pennsylvania area in lieu of the Prexy Facilities that had been a part of the original TrAIL proposal. As a result of the collaborative process, a settlement and an amendment to the application based on a consensus of the participants in the collaborative process was approved by the Pennsylvania PUC on November 19, 2010.

West Virginia

On May 15, 2009, PATH-WV, PATH-Allegheny and certain other related entities filed an application with the West Virginia PSC for authorization to construct the West Virginia portion of the PATH Project.

Maryland

On December 21, 2009, Potomac Edison filed an application with the Maryland PSC for authorization to construct the Maryland portions of the PATH Project. The project in Maryland will be owned by PATH-Allegheny Maryland Transmission Company, LLC, which is owned by Potomac Edison and PATH-Allegheny. Potomac Edison subsequently requested an extension of the procedural schedule. The Hearing Examiner has not ruled on the request. Based on the current procedural schedule, a decision on the application is expected in the third quarter of 2011.

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Virginia

On September 20, 2010, PATH-Allegheny Virginia Transmission Corporation filed an application with the Virginia SCC for authorization to construct the Virginia portions of the PATH Project. A decision on the application is expected in the third quarter of 2011.

NOTE 7:  REGULATORY ASSETS AND LIABILITIES

Allegheny’s regulated utility operations are subject to industry-specific accounting provisions. Regulatory assets represent probable future revenues associated with incurred costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process or amounts collected for costs not yet incurred. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets were as follows:

	December 31,
(In millions)	2010		2009
Regulatory assets, including current portion:
Income taxes (a)(b)	$	232.3	$	234.9
Pension benefits and postretirement benefits other than pensions (a)(c)		384.7		396.5
ENEC under recovery (a)(d)		90.1		109.5
Transmission revenue requirement and recoverable costs (e)		76.5		36.3
Unamortized loss on reacquired debt (a)(f)		32.4		26.8
Market-based generation costs (a)(g)		9.5		0.9
Unrealized loss on financial transmission rights (a)		0		1.7
Other (h)		58.1		43.4
Subtotal		883.6		850.0
Regulatory liabilities, including current portion:
Net asset removal costs (i)		388.3		374.2
Fort Martin Scrubber project-environmental control surcharge		36.1		40.1
ENEC over recovery (d)		30.3		0
Income taxes		27.4		29.3
SO2 allowances		12.3		12.8
Maryland rate stabilization and transition plan surcharge		0		30.1
Unrealized gain on financial transmission rights		9.8		0
Other		18.4		12.1
Subtotal		522.6		498.6
Net regulatory assets	$	361.0	$	351.4

(a) Does not earn a return.

(b) Amount is being recovered over various periods associated with the remaining useful life of related regulated utility property, plant and equipment.

(c) Amount is being recovered over various periods up to 13 years.

(d) Amounts include a current regulatory asset and a long-term regulatory liability. ENEC under recovery is being recovered through 2012.

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(e) Amount earns interest at the approved FERC interest rate and will generally be recovered through 2013.

(f) Amount is being recovered over various periods through 2025, based upon the maturities of reacquired debt.

(g) Amount is being recovered over one year.

(h) Includes amounts that do not earn a return with various recovery periods through 2027.

(i) Net asset removal costs of $51.0 million are included in liabilities associated with assets held for sale at December 31, 2009 in the consolidated balance sheet.

See Note 5, “Rates and Regulation,” for additional information regarding regulatory developments impacting regulatory assets and liabilities, Note 12, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for a discussion of regulatory assets relating to pension and other postretirement benefits, and Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities” for information relating to regulatory assets relating to unrealized gains and losses on FTRs. Other regulatory assets and liabilities reflected in the table above relate to the following:

Income Taxes

In certain jurisdictions, deferred income tax expense is not permitted as a current cost in the determination of rates charged to customers. In certain of these jurisdictions a deferred income tax liability, or asset as appropriate, is recorded with an offsetting regulatory asset or liability. These deferred income taxes primarily relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. In addition, deferred income tax assets are recorded with offsetting regulatory liabilities related to deferred investment tax credits. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. The income tax regulatory liability represents amounts that will be returned to customers as the investment tax credits are amortized against taxes paid.

Pension Benefits and Postretirement Benefits Other Than Pensions

Allegheny recognizes the underfunded status of its defined benefit postretirement plans as a liability on its consolidated balance sheet and recognizes changes in the funded status in other comprehensive income. However, to the extent that the funded status relates to Allegheny’s rate-regulated subsidiaries and such amounts will be recovered through the rate-making process, the funded status and changes in funded status are recognized as a regulatory asset rather than as a charge to other comprehensive income.

Expanded Net Energy Cost

In May 2007, the West Virginia PSC issued a rate order that re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs, including purchased power costs associated with the Grant Town PURPA Generation Facility and other related expenses, net of related revenue and interest earnings on the Fort Martin Scrubber project escrow fund. Under the ENEC, actual costs and revenues are tracked for under and/or over recoveries, and revised ENEC rate filings are generally made on an annual basis. Any under and/or over recovery of costs, net of related revenues, is deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability, with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.” See Note 5, “Rates and Regulation” for additional information.

Net Asset Removal Costs

In certain jurisdictions, depreciation rates include a factor representing the estimated costs associated with removing an asset from service upon retirement. The accrual accumulates during the asset’s service life and is reduced when the actual cost of removal is incurred. The accumulated balance of such removal costs represents a

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regulatory liability. In other jurisdictions, retirement costs are collected in rates only after they are incurred, in which case the costs are recorded as a regulatory asset. See Note 19, “Asset Retirement Obligations (“ARO”), for a description of asset retirement obligations.

Fort Martin Scrubber Project

The Fort Martin scrubber project regulatory liability represents the difference between amounts collected from customers under an environmental control surcharge and interest on the Environmental Control Bonds and depreciation expense incurred on the Scrubbers. This liability will decrease, over the remaining useful life of the Scrubbers, after the environmental control surcharge ends and the Environmental Control Bonds have been repaid.

Transmission Revenue Requirement and Recoverable Costs

Under a formula rate mechanism approved by FERC, TrAIL Company, PATH-WV and PATH-Allegheny make annual filings in order to recover incurred costs and an allowed return. An initial rate filing is made for each calendar year using estimated costs, which is used to determine the billings to customers. All prudently incurred allowable costs and return earned during each calendar year are eventually recovered on a dollar-for-dollar basis through a true-up mechanism. As such, TrAIL Company, PATH-WV and PATH-Allegheny recognize revenue as they incur recoverable costs and earn the allowed return on a monthly basis. Any differences between revenues earned based on actual costs and the amounts billed based on estimated costs are included in a regulatory asset or liability and will be recovered or refunded, respectively, in subsequent periods.

Market-based Generation Costs

Potomac Edison is authorized by the Maryland PSC to recover the costs of the generation component of power sold to certain residential, commercial and industrial customers that did not choose a third-party alternative generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet for any under-recovery or over-recovery of the generation component of costs charged to these customers.

NOTE 8:  INCOME TAXES

Components of federal and state income tax expense were as follows:

(In millions)	2010			2009			2008
Income tax expense (benefit) - current:
Federal	$	7.0		$	(12.0	)	$	15.5
State		9.5			11.0			24.5
Total		16.5			(1.0	)		40.0
Income tax expense (benefit) - deferred:
Federal		238.0			232.7			170.2
State		4.8			6.2			(10.4	)
Total		242.8			238.9			159.8
Income tax expense (benefit) - non-current:
Federal		(1.8	)		(2.9	)		(1.9	)
State		(37.2	)		10.2			9.8
Total		(39.0	)		7.3			7.9
Amortization of deferred investment tax credit		(3.6	)		(3.6	)		(3.6	)
Income tax expense	$	216.7		$	241.6		$	204.1

Income tax expense (benefit) - non-current primarily relates to changes in uncertain tax positions.

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On March 31, 2008, West Virginia enacted a change in its income tax law that implemented combined reporting and a reduction in its income tax rate that phases in from 2009 through 2014. During 2008, Allegheny recognized a benefit of approximately $6.8 million, net of federal income tax, representing an adjustment of its deferred tax assets and liabilities to reflect the effects of this rate reduction.

The Commonwealth of Pennsylvania limited the amount of net operating loss carryforwards that may be used to reduce current year taxable income to the greater of $3 million or 12.5% of apportioned Pennsylvania taxable income per year through 2008. During 2008, an additional benefit of $3.9 million, net of applicable federal income tax, was recorded to adjust the recorded Pennsylvania net operating loss carryforward asset to reflect estimates of future Pennsylvania taxable income during the carryforward period.

On October 9, 2009, Pennsylvania enacted H.B. 1531, which modified the corporate net operating loss utilization rules and made minor modifications to apportionment provisions. Under H.B. 1531, the annual net operating loss carryforward limitation was increased to 15% of taxable income for 2010 and 20% thereafter. During 2009, an additional benefit of $11.0 million, net of applicable federal income tax, was recorded to reflect estimates of future Pennsylvania taxable income during the carryforward period and to adjust the Pennsylvania net operating loss carryforward asset to reflect estimated benefits resulting from the increased utilization caps under H.B. 1531.

The following is a reconciliation of reported income tax expense to income tax expense calculated by applying the federal statutory rate of 35% to income before income taxes:

(In millions, except percent)	2010						2009						2008
	Amount			%			Amount			%			Amount			%
Income before income taxes	$	628.4					$	635.7					$	599.9
Income tax expense calculated at the federal statutory rate of 35%		220.0			35.0			222.5			35.0			210.0			35.0
Increases (reductions) resulting from:
Rate-making effects of depreciation differences		3.1			0.5			(1.7	)		(0.3	)		5.3			0.9
AFUDC		(2.5	)		(0.4	)		(2.0	)		(0.3	)		(1.8	)		(0.3	)
Change in estimated Pennsylvania net operating loss benefits, net of federal income tax		0			0			(11.0	)		(1.7	)		(3.9	)		(0.7	)
March 2008 West Virginia state income tax rate change, net of federal income tax		0			0			0			0			(6.8	)		(1.1	)
Other state income tax, net of federal income tax benefit		26.4			4.2			29.1			4.6			12.7			2.1
Amortization of deferred investment tax credits		(3.6	)		(0.6	)		(3.6	)		(0.6	)		(3.6	)		(0.6	)
Changes in tax reserves related to uncertain tax positions and audit settlements		(26.4	)		(4.2	)		3.5			0.6			(3.4	)		(0.5	)
Other, net		(0.3	)		(0.1	)		4.8			0.7			(4.4	)		(0.8	)
Income tax expense	$	216.7			34.4		$	241.6			38.0		$	204.1			34.0

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At December 31, deferred income tax assets and liabilities consisted of the following:

(In millions)	2010			2009
Deferred income tax assets:
Recovery of transition costs	$	46.8		$	42.4
Unamortized investment tax credits		33.6			35.9
Postretirement benefits		105.6			98.9
Tax effect of net operating loss carryforwards and credits		190.4			247.8
Derivative contracts		0			2.2
Valuation allowance on deferred tax assets		0			(5.0	)
Other		121.2			46.2
Total deferred income tax assets		497.6			468.4
Deferred income tax liabilities:
Plant asset basis differences, net		2,012.3			1,816.6
Derivative contracts		6.1			0
Other		158.9			71.6
Total deferred income tax liabilities		2,177.3			1,888.2
Total net deferred income tax liability		1,679.7			1,419.8
Deferred income taxes included in current assets (liabilities)		(26.1	)		81.5
Total long-term net deferred income tax liability	$	1,653.6		$	1,501.3

Allegheny has recorded as deferred income tax assets the effect of net operating losses and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. The tax effected net operating loss carryforwards consisted of $151.8 million of state net operating loss carryforwards that expire from 2019 through 2029 and $13.4 million of federal net operating loss carryforwards that expire from 2023 to 2029. Federal Alternative Minimum Tax credits of $25.2 million have an indefinite carryforward period.

Allegheny’s valuation allowance on deferred tax assets was reduced in 2009 primarily because of a change in Pennsylvania tax law with respect to net operating loss carryforwards enacted in the fourth quarter of 2009. This benefit was partially offset by a reduction in the expected realization of carryforward amounts due to forecasted taxable income.

Allegheny records interest and penalties associated with uncertain tax positions as a component of income tax expense. Allegheny recognized interest expense (benefit) related to uncertain tax positions, net of tax, of approximately $(2.1) million, $1.0 million and $1.8 million during 2010, 2009 and 2008, respectively. Accrued interest, net of tax, related to uncertain tax positions was $3.3 million and $5.4 million at December 31, 2010 and December 31, 2009, respectively. The reduction in interest in 2010 compared to 2009 is due primarily to a change in facts resulting in a remeasurement of existing uncertain tax positions.

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The following represents an analysis of the changes in unrecognized tax benefits during 2010, 2009 and 2008, excluding accrued interest:

(In millions)	2010			2009			2008
Balance at January 1	$	126.4		$	112.6		$	102.9
Additions based on tax positions related to the current year		6.9			53.8			10.7
Additions for tax positions of prior years		9.2			0.2			0
Reductions for tax positions of prior years		(43.8	)		(37.8	)		(1.0	)
Settlements		(3.2	)		(2.4	)		0
Balance at December 31	$	95.5		$	126.4		$	112.6

If recognized, the portion of the unrecognized tax benefits that would reduce Allegheny’s effective tax rate was $28.8 million and $54.3 million at December 31, 2010 and December 31, 2009, respectively ($46.2 million and $84.1 million, respectively, before the federal income tax effects on state income tax positions). The reduction in unrecognized tax benefits in 2010 is due to internal restructuring of subsidiary companies that reduced exposure to state liabilities.

At December 31, 2010, approximately $43.4 million of the reserve is not expected to be resolved in the next 12 months and, therefore, has been classified as long term income taxes payable on the accompanying Consolidated Balance Sheet.

The unrecognized tax benefit balance also included approximately $49.3 million and $42.4 million of tax positions at December 31, 2010 and December 31, 2009, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would impact the timing of cash payments to the taxing authorities.

The major jurisdictions in which Allegheny is subject to income tax are U.S. Federal, Pennsylvania, West Virginia, Maryland and Virginia. Allegheny files consolidated federal income tax returns, and those returns are currently under audit by the Internal Revenue Service (“IRS”) for the tax years 2007 and 2008. The 2009 federal return has been filed and is subject to review. State tax returns are substantially complete through 2006, and returns for tax years 2007 through 2009 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain of Allegheny’s subsidiaries that are subject to tax in those states.

The IRS audits of Allegheny’s income tax returns for the tax years 2004 through 2006 have been completed. During 2010, Allegheny reached a settlement with the IRS on substantially all issues and recorded a benefit of $1.8 million due to the release of related uncertain tax position reserves. The Joint Committee on Taxation reviewed these audits. Additionally, Allegheny has liabilities for uncertain positions taken on various state income tax returns that it files. The statute of limitations for some of these returns expired during 2010 and 2009 and resulted in a benefit of approximately $10.8 million and $2.2 million, respectively. During 2011, additional state statute of limitations will expire that may result in a net benefit of approximately $4.0 million.

In September 2010, President Obama signed into law the “Small Business Jobs Act.” That legislation includes an extension of the bonus depreciation provision to 2010 and into 2011 for certain qualified property, retroactive to the beginning of 2010. This provision will allow Allegheny to accelerate its depreciation deductions on qualifying property for federal income tax purposes. This provision also increases Allegheny’s net operating loss carryforward into 2011 and creates significant accelerated deductions in 2011.

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NOTE 9:  CAPITALIZATION AND DEBT

Common Stock

During 2010, 2009 and 2008, Allegheny paid the following dividends on its common stock:

Payment Date	Record Date	Dividend per Share
December 27, 2010	December 13, 2010	$0.15
September 27, 2010	September 13, 2010	$0.15
June 21, 2010	June 7, 2010	$0.15
March 22, 2010	March 8, 2010	$0.15
December 28, 2009	December 14, 2009	$0.15
September 28, 2009	September 14, 2009	$0.15
June 22, 2009	June 8, 2009	$0.15
March 23, 2009	March 9, 2009	$0.15
December 29, 2008	December 15, 2008	$0.15
September 29, 2008	September 15, 2008	$0.15
June 23, 2008	June 9, 2008	$0.15
March 24, 2008	March 10, 2008	$0.15

In addition to the dividends listed above, on December 21, 2010, AE’s Board of Directors authorized a cash dividend on AE’s common stock payable during the first quarter of 2011. If the proposed Merger does not become effective on or before March 14, 2011, a dividend of $0.15 per outstanding share of common stock will be payable on March 28, 2011 to stockholders of record at the close of business of March 14, 2011. If the proposed Merger is completed on or before March 14, 2011, a prorated dividend will be payable 14 days after the effective date of the Merger to stockholders of record at the close of business on the last business day prior to the Merger effective date.

Dividends are declared at the discretion of AE’s Board of Directors, and future dividends will depend upon available earnings, cash flows and other relevant factors, provided, however, that under the terms of its Merger Agreement with FirstEnergy, AE is prohibited from increasing its quarterly cash dividend.

AE issued 0.4 million, 0.2 million and 2.1 million shares of common stock in 2010, 2009 and 2008, respectively, primarily in connection with stock option exercises and the settlement of stock units and performance shares.

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Debt

Allegheny’s long-term debt was as follows:

	As of December 31, 2010				As of December 31,
(Dollar amounts in millions)	Contractual Maturities		Interest Rate %		2010			2009
AE Supply:
Medium-Term Notes		2012-2039		5.750 – 8.250	$	1,103.2		$	1,253.7
Pollution Control Bonds		2012-2037		5.050 – 6.875		268.5			268.5
Exempt Facilities Revenue Bonds		2039		7.000		235.0			235.0
Debentures—AGC		2023		6.875		100.0			100.0
Revolving Credit Facility—AGC (a)		2013		2.788		50.0			0
Unamortized debt discounts						(3.5	)		(4.4	)
Total AE Supply long-term debt					$	1,753.2		$	1,852.8
Monongahela:
First Mortgage Bonds		2013-2017		5.375 – 7.950	$	640.0		$	640.0
Environmental Control Bonds		2016-2031		4.982 – 5.523		372.3			383.3
Pollution Control Bonds		2012-2029		5.050 – 6.875		70.3			70.3
Medium-Term Notes						0			110.0
Unamortized debt discounts						(0.9	)		(1.0	)
Total Monongahela long-term debt					$	1,081.7		$	1,202.6
West Penn:
First Mortgage Bonds		2016-2017		5.875 – 5.950	$	420.0		$	420.0
Medium-Term Notes		2012		6.625		80.0			80.0
Transition Bonds						0			16.0
Unamortized debt discounts						(0.9	)		(1.0	)
Total West Penn long-term debt					$	499.1		$	515.0
Potomac Edison:
First Mortgage Bonds		2014-2016		5.125 – 5.800	$	420.0		$	420.0
Environmental Control Bonds		2016-2031		4.982 – 5.523		124.3			128.0
Revolving Credit Facility (a)		2013		4.006		20.0			0
Unamortized debt discounts						(0.8	)		(1.0	)
Total Potomac Edison long-term debt					$	563.5		$	547.0
TrAIL Company:
Medium-Term Notes		2015		4.000	$	450.0		$	0
Revolving Credit Facility (a)		2013		3.287		370.0			20.0
Term Loan						0			435.0
Unamortized debt discounts						(1.4	)		0
Total TrAIL Company long-term debt					$	818.6		$	455.0
Eliminations						(14.6	)		(14.6	)
Total					$	4,701.5		$	4,557.8
Less amounts due within one year						(15.5	)		(140.8	)
Consolidated long-term debt					$	4,686.0		$	4,417.0

(a) Variable rate debt

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Outstanding debt and scheduled debt repayments at December 31, 2010 were as follows:

(In millions)	2011			2012			2013			2014			2015			Thereafter			Total
AE Supply:
Medium-Term Notes	$	0		$	503.2		$	0		$	0		$	0		$	600.0		$	1,103.2
Pollution Control Bonds		0			1.3			0			15.4			7.1			244.7			268.5
Exempt Facilities Revenue Bonds		0			0			0			0			0			235.0			235.0
Debentures-AGC		0			0			0			0			0			100.0			100.0
Revolving Credit Facility -AGC		0			0			50.0			0			0			0			50.0
Total AE Supply		0			504.5			50.0			15.4			7.1			1,179.7			1,756.7
Monongahela:
First Mortgage Bonds		0			0			300.0			120.0			70.0			150.0			640.0
Securitized Debt-Environmental Control Bonds (a)		11.6			12.2			12.8			13.5			14.2			308.0			372.3
Pollution Control Bonds		0			6.0			7.1			0			25.0			32.2			70.3
Total Monongahela		11.6			18.2			319.9			133.5			109.2			490.2			1,082.6
West Penn:
First Mortgage Bonds		0			0			0			0			0			420.0			420.0
Medium-Term Notes		0			80.0			0			0			0			0			80.0
Total West Penn		0			80.0			0			0			0			420.0			500.0
Potomac Edison:
First Mortgage Bonds		0			0			0			175.0			145.0			100.0			420.0
Securitized Debt-Environmental Control Bonds (a)		3.9			4.1			4.3			4.5			4.7			102.8			124.3
Revolving Credit Facility		0			0			20.0			0			0			0			20.0
Total Potomac Edison		3.9			4.1			24.3			179.5			149.7			202.8			564.3
TrAIL Company:
Medium-Term Notes		0			0			0			0			450.0			0			450.0
Revolving Credit Facility		0			0			370.0			0			0			0			370.0
Total TrAIL		0			0			370.0			0			450.0			0			820.0
Unamortized debt discounts		(1.5	)		(1.2	)		(1.1	)		(0.9	)		(0.5	)		(2.3	)		(7.5	)
Eliminations (b)		0			(1.3	)		0			0			(7.1	)		(6.2	)		(14.6	)
Total consolidated debt	$	14.0		$	604.3		$	763.1		$	327.5		$	708.4		$	2,284.2		$	4,701.5

(a) Amounts represent repayments based upon estimated surcharge collections from customers.

(b) Amounts represent the elimination of certain pollution control bonds, for which Monongahela and AE Supply are co-obligors.

The environmental control bonds shown in the table above were issued by two bankruptcy remote, special purpose limited liability companies (the “Funding Companies”) that are indirect subsidiaries of Monongahela and Potomac Edison, respectively. Proceeds from the bonds were used to construct environmental control facilities. The Funding Companies own the irrevocable right to collect non-bypassable environmental control charges (the “Environmental Control Charge”) from all customers who receive electric delivery service in Monongahela’s and Potomac Edison’s West Virginia service territories. Principal and interest owing on the environmental control bonds is secured by and payable solely from the proceeds of the Environmental Control Charge. The right to collect Environmental Control Charges is not included on Allegheny’s consolidated balance sheets. Creditors of AE and its subsidiaries other than the Funding Companies have no recourse to any assets or revenues of the Funding Companies.

Certain of Allegheny’s properties are subject to liens of various relative priorities securing debt.

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Credit Facilities

At December 31, 2010, AE, AE Supply, Monongahela, Potomac Edison, West Penn, AGC and TrAIL Company had in place revolving credit facilities as follows:

(Dollar amounts in millions)	Matures		Total Capacity		Borrowed		Letters of Credit Issued		Available Capacity
AE		2013	$	250.0	$	0	$	3.1	$	246.9
AE Supply		2012		1,000.0		0		0		1,000.0
Monongahela		2012		110.0		0		0		110.0
Potomac Edison		2013		150.0		20.0		0		130.0
West Penn		2013		200.0		0		0		200.0
AGC		2013		50.0		50.0		0		0
TrAIL Company		2013		450.0		370.0		0		80.0
Total			$	2,210.0	$	440.0	$	3.1	$	1,766.9

Under terms of their individual credit facilities, outstanding debt of AE Supply, Monongahela, Potomac Edison, West Penn and AGC may not exceed 65% of the sum of their debt and equity as of the last day of each calendar quarter. Outstanding debt of TrAIL Company may not exceed 70% and 65% of the sum of its debt and equity as of the last day of each calendar quarter through June 30, 2011 and December 31, 2012, respectively. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE.

2010 Debt Activity

Borrowings and principal repayments on debt during the year ended December 31, 2010 were as follows:

(In millions)	Borrowings		Repayments
AE:
AE Revolving Credit Facility	$	130.1	$	130.1
AE Supply:
Medium-Term Notes		0		150.5
AGC Revolving Credit Facility		50.0		0
TrAIL Company:
Medium-Term Notes		450.0		0
New TrAIL Company Credit Facility-Revolver		370.0		0
TrAIL Company Credit Facility-Term Loan (a)		30.0		465.0
TrAIL Company Credit Facility-Revolver (a)		0		20.0
West Penn:
Transition Bonds		0		16.0
Revolving Credit Facility		35.0		35.0
Monongahela:
Medium-Term Notes		0		110.0
Environmental Control Bonds		0		11.1
Potomac Edison:
Environmental Control Bonds		0		3.7
Revolving Credit Facility		140.0		120.0
Consolidated Total	$	1,205.1	$	1,061.4

(a) Represents debt under TrAIL Company’s previous credit facility, which was repaid and replaced in January 2010 by a new revolving credit facility, as described below.

On January 15, 2010, Monongahela repaid its $110 million in outstanding 7.36% medium-term notes.

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On January 25, 2010, TrAIL Company issued $450 million aggregate principal amount of 4.0% senior unsecured notes due in 2015 and also entered into a $350 million senior unsecured revolving credit facility with a three-year maturity. The revolving credit facility capacity was increased to $450 million in August 2010. Borrowings under the new credit facility bear interest at a rate that is calculated based on the London Interbank Offered Rate (“LIBOR”) plus a margin based on TrAIL Company’s senior unsecured credit rating. Currently, the margin is 3.0%. During 2010, TrAIL Company borrowed $370.0 million under its senior unsecured credit facility. TrAIL Company used the net proceeds from the sale of the notes, together with funds from the credit facility, to repay all amounts outstanding under the $550 million senior unsecured credit facility that it entered into in 2008.

On May 3, 2010, Potomac Edison and West Penn entered into new $150 million and $200 million senior unsecured revolving credit facilities, respectively. On May 4, 2010, AE entered into a new $250 million senior unsecured revolving credit facility. The new AE revolving credit facility replaced AE’s previous $376 million revolving credit facility, which was scheduled to mature in May 2011. The AE, Potomac Edison and West Penn credit facilities mature on April 30, 2013. Loans under all three credit facilities bear interest at a rate that is calculated based on LIBOR plus a margin based on the borrower’s senior unsecured credit rating. Currently, the margins are 3.0% for AE and 2.75% for Potomac Edison and West Penn. Allegheny capitalized approximately $5.6 million in debt issuance costs related to the three credit facilities.

On July 16, 2010, AE Supply redeemed all $150.5 million of its outstanding 7.80% Medium Term Notes due 2011 and expensed approximately $7.3 million in redemption premiums and unamortized costs associated with the notes.

On October 22, 2010, AGC entered into a $50 million senior unsecured revolving credit facility and borrowed $50 million under the credit facility to pay dividends and a return of capital of $30 million to AE Supply and $20 million to Monongahela. The credit facility matures on December 31, 2013. Loans under the credit facility bear interest at a rate that is calculated based on LIBOR plus a margin based on AGC’s senior unsecured credit rating. Currently, the margin is 2.50%.

2009 Debt Activity

Borrowings and principal repayments on debt during 2009 were as follows:

(In millions)	Issuances		Repayments
AE:
AE Revolving Credit Facility	$	120.0	$	120.0
AE Supply:
AE Supply Credit Facility-Revolving Loan (a)		120.0		120.0
AE Supply Credit Facility-Term Loan (a)		0		447.0
Exempt Facilities Revenue Bonds		235.0		0
Medium-Term Notes		600.0		396.3
TrAIL Company:
TrAIL Company Credit Facility-Term Loan		365.0		0
West Penn:
Transition Bonds		0		79.8
Monongahela:
Environmental Control Bonds		64.4		10.6
Potomac Edison:
Environmental Control Bonds		21.5		3.5
Consolidated Total	$	1,525.9	$	1,177.2

(a) Represents debt activity under AE Supply’s previous credit facility, which was replaced with a new credit facility in September 2009.

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On July 6, 2009, the Pennsylvania Economic Development Financing Authority issued $235 million of 7.0% tax-exempt bonds that mature in 2039 and loaned the proceeds from that issuance to AE Supply to finance a portion of the cost of constructing and installing Scrubbers at its Hatfield’s Ferry generation facility. AE Supply capitalized $2.4 million in debt issuance costs associated with this transaction.

On September 4, 2009, AE Supply repurchased $97.5 million and $146.8 million, respectively, of its 7.80% Notes due 2011 and its 8.25% Notes due 2012 pursuant to a cash tender offer, at an aggregate premium of $18.1 million. AE Supply expensed the $18.1 million premium, $0.7 million in unamortized debt costs, and $0.6 million in fees associated with the tender offer.

On September 24, 2009, AE Supply entered into a new $1 billion senior unsecured revolving credit facility with a three-year maturity. The new revolving credit facility replaced AE Supply’s previous $400 million revolving credit facility, which was scheduled to mature in May 2011. Loans under the new facility bear interest that is calculated based on the LIBOR, plus a margin based on AE Supply’s senior unsecured credit rating. AE Supply capitalized $22.3 million in debt costs related to this facility.

On October 1, 2009, AE Supply issued $600 million aggregate principal amount of senior unsecured notes, consisting of $350 million of 5.75% Notes due 2019 and $250 million of 6.75% Notes due 2039. AE Supply used a portion of the net proceeds from the sale of these notes to repay in full its existing $447 million term loan on October 2, 2009. AE Supply capitalized $5.3 million in debt issuance costs associated with this new debt issuance and expensed $0.6 million of unamortized debt costs associated with the extinguished term loan.

On October 21, 2009, AE Supply used the remaining proceeds of its senior unsecured note offering to repurchase approximately $152 million aggregate principal amount of its 7.80% Medium Term Notes due 2011 pursuant to a cash tender offer at an aggregate premium of $12.7 million. AE Supply expensed the $12.7 million premium, $0.3 million in unamortized debt costs, and $0.4 million in fees related to this tender offer.

On December 18, 2009, Monongahela entered into a new $110 million senior unsecured revolving credit facility with a three-year maturity. Loans under the new facility generally bear interest that is calculated based on the LIBOR, plus a margin based on Monongahela’s senior unsecured credit rating. Monongahela capitalized approximately $1.4 million in debt costs related to this facility.

On December 23, 2009, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $64.4 million and $21.5 million, respectively, of Senior Secured Ratepayer Obligation Charge Environmental Control Bonds, Series B. These bonds securitize the right to collect an environmental control surcharge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. The bonds were issued with an interest rate of 5.1% and mature in January 2031. Net proceeds from the sale of the bonds are restricted funds and are being used to fund certain costs incurred in connection with the construction and installation of the Scrubbers at the Fort Martin generating facility. Monongahela and Potomac Edison capitalized $1.9 million and $0.7 million, respectively, in debt issuance costs associated with this transaction.

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NOTE 10:  EARNINGS PER SHARE

The reconciliation of the basic and diluted earnings per common share calculation is as follows:

(In millions, except share and per share amounts)	2010		2009		2008
Basic Income per Share:
Numerator:
Net income attributable to Allegheny Energy, Inc.	$	411.7	$	392.8	$	395.4
Denominator:
Weighted average common shares outstanding		169,792,703		169,537,642		168,458,909
Basic earnings per share attributable to Allegheny Energy, Inc.	$	2.42	$	2.32	$	2.35
Diluted Income per Common Share:
Numerator:
Net income attributable to Allegheny Energy, Inc.	$	411.7	$	392.8	$	395.4
Denominator:
Weighted average common shares outstanding		169,792,703		169,537,642		168,458,909
Effect of dilutive securities:
Stock options (a)		308,080		387,444		1,251,445
Performance shares		151,308		34,017		14,056
Stock units		0		2,697		209,342
Non-employee stock awards		0		0		57,511
Total shares		170,252,091		169,961,800		169,991,263
Diluted earnings per share attributable to Allegheny Energy, Inc.	$	2.42	$	2.31	$	2.33

(a) The diluted share calculations for 2010, 2009 and 2008 exclude 1,673,312 shares, 1,808,960 shares and 576,101 shares, respectively, under outstanding stock options because the inclusion of these shares would have been antidilutive under the treasury stock method.

NOTE 11:  STOCK-BASED COMPENSATION

On May 15, 2008, AE’s stockholders approved the Allegheny Energy, Inc. 2008 Long-Term Incentive Plan (the “2008 LTIP”). The 2008 LTIP authorized the grant of equity-based compensation to AE’s directors and to its executives and other key employees in the form of performance awards, stock options and stock appreciation rights, restricted shares, and restricted stock units.

Allegheny records compensation expense for share-based payments to employees and non-employee directors, including grants of employee stock options, performance shares, restricted shares and stock units, over the requisite service period based on their estimated fair value on the date of grant.

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No stock-based compensation cost was capitalized in 2010, 2009 or 2008. The following table summarizes stock-based compensation expense included in operations and maintenance expense during 2010, 2009 and 2008:

(In millions)	2010		2009		2008
Performance shares	$	13.1	$	7.3	$	2.9
Stock options		6.5		7.4		9.3
Non-employee director stock awards		0.8		0.9		1.1
Restricted shares		0.3		0.1		0
Stock units		0		0		0.6
Total stock-based compensation expense		20.7		15.7		13.9
Income tax benefit		8.3		6.4		5.7
Total stock-based compensation expense, net of tax	$	12.4	$	9.3	$	8.2

Employee stock options, performance shares and restricted share awards granted prior to February 10, 2010 became fully vested and exercisable or payable upon the approval of the proposed Merger with FirstEnergy by AE’s stockholders at a special meeting held on September 14, 2010. The remaining cost of approximately $4.5 million associated with these awards that previously was being amortized over the original vesting period was accelerated and expensed during the third quarter of 2010. Stock-based compensation expense recognized in the Consolidated Statements of Income is based on awards ultimately expected to vest, using an estimated annual forfeiture rate of 5%.

Stock Options

The exercise price, terms and other conditions applicable to stock option awards are generally determined by the Management Compensation and Development Committee of AE’s Board or the independent directors of the Board. The exercise price per share for each award is equal to or greater than the fair market value of a share of AE’s common stock on the grant date. Stock options vest in annual tranches on a pro-rata basis over the vesting period, which is typically two to five years, and become fully vested and exercisable upon a change in control. Stock options typically expire after 10 years. Stock option awards are expensed using the straight-line attribution method over the requisite service period of the last separately vesting tranche of the award.

No stock options were granted in 2010. Allegheny records compensation expense for employee stock options based on the estimated fair value of the options on the date of grant under the Black-Scholes option-pricing model using the following weighted-average assumptions for stock options granted in 2009 and 2008:

	2009			2008
Annual risk-free interest rate		2.86	%		3.18	%
Expected term of the option (in years)		6.00			6.06
Expected annual dividend yield		2.53	%		1.13	%
Expected stock price volatility		36.4	%		27.5	%
Grant date fair value per stock option	$	7.14		$	15.18

The annual risk-free interest rate is based on the United States Treasury yield curve at the date of the grant for a period equal to the expected term of the options granted. The expected term of the 2009 and 2008 stock option grants was calculated using the “simplified” method. AE used the simplified method for its calculation of expected term due to its lack of sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term and because AE has granted stock options in prior years with varying vesting terms,

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which also made it difficult to evaluate historical exercise data. The expected annual dividend yield assumption was based on AE’s current dividend rate at the time of each grant. For stock options granted in 2009 and 2008, the expected stock price volatility was based on both historical stock volatility and the volatility levels implied on the grant date by actively traded option contracts on AE’s common stock.

Stock option activity was as follows:

	Stock Options			Weighted- Average Exercise Price
Outstanding at December 31, 2007		3,191,409		$	16.11
Granted		628,763		$	52.36
Exercised		(1,849,316	)	$	13.71
Forfeited/Expired		(100,347	)	$	45.62
Outstanding at December 31, 2008		1,870,509		$	29.08
Granted		1,204,965		$	23.68
Exercised		(163,700	)	$	14.20
Forfeited/Expired		(58,832	)	$	30.55
Outstanding at December 31, 2009		2,852,942		$	27.62
Exercised		(85,784	)	$	15.04
Forfeited/Expired		(43,477	)	$	40.55
Outstanding at December 31, 2010		2,723,681		$	27.81

The grant-date fair value of stock options granted, the total pre-tax intrinsic value of stock options exercised and exercisable, and the proceeds to AE from stock option exercises in 2010, 2009 and 2008 are shown in the table below:

(in millions)	2010		2009		2008
Grant-date fair value of stock options granted		N/A	$	8.6	$	9.6
Total pre-tax intrinsic value of stock options exercised (a)	$	0.6	$	2.1	$	64.5
Total pre-tax intrinsic value of stock options exercisable at December 31 (b)	$	8.5	$	7.9	$	14.9
Proceeds to AE from stock option exercises	$	1.3	$	2.3	$	25.3

(a) Represents the total pre-tax intrinsic value based on the difference between the market value of AE’s common stock at exercise and the exercise price of the options.

(b) Represents the total pre-tax intrinsic value based on the difference between the exercise price of stock options exercisable (with an exercise price lower than AE’s closing stock price) and AE’s closing stock price of $24.24, $23.48, and $33.86, on December 31, 2010, 2009, and 2008, respectively.

AE issued new shares of its common stock to satisfy these stock option exercises. No cash tax benefit was realized from tax deductions on stock options exercised during 2010, 2009, and 2008 because of existing net operating loss carryforwards.

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The following table summarizes information about stock options outstanding and stock options exercisable at December 31, 2010:

Range of Exercise Prices	Options Outstanding and Exercisable
			Weighted-Average
	As of December 31, 2010		Remaining Contractual Term (in Years)		Exercise Price		Aggregate Intrinsic Value (in millions) (a)
$10.00 - $14.99		680,754		3.2	$	13.55	$	7.3
$15.00 - $19.99		79,522		4.1	$	18.90		0.4
$20.00 - $24.99		1,199,745		7.9	$	23.54		0.8
$25.00 - $29.99		71,243		6.2	$	27.77		0
$30.00 - $34.99		10,200		1.0	$	34.56		0
$35.00 - $39.99		61,800		5.2	$	35.97		0
$40.00 - $44.99		33,557		5.3	$	42.65		0
$45.00 - $49.99		85,570		6.6	$	46.10		0
$50.00 - $54.99		489,290		7.1	$	53.52		0
$55.00 - $59.99		12,000		6.5	$	55.96		0
Total		2,723,681		6.3	$	27.81	$	8.5

(a) Represents the total pre-tax intrinsic value based on stock options with an exercise price less than AE’s closing stock price of $24.24 as of December 31, 2010.

As of December 31, 2010, Allegheny had no unrecognized compensation cost related to stock options.

At December 31, 2010, Allegheny had approximately $64.3 million in excess tax benefits related to share based awards that had not yet been credited to other paid-in capital because of Allegheny’s federal income tax net operating loss carryforward position.

Performance Shares

In 2008 and 2009, AE granted equity-based performance shares to key employees pursuant to which award recipients could earn shares of AE common stock based on AE’s Total Shareholder Return (“TSR”) compared to the total return of the companies in the Dow Jones U.S. Electric Utilities Index over a three-year performance period beginning on the date of each grant. Upon stockholder approval of the proposed Merger with FirstEnergy, AE settled all 241,989 outstanding TSR performance shares through the issuance of 155,027 shares of its common stock, representing 100% of each participant’s target award less shares withheld to meet minimum income tax withholding requirements. Activity in target performance shares linked to TSR was as follows:

	Number of Shares
TSR Performance shares outstanding at December 31, 2007		0
Granted		83,653
Forfeited		(8,098	)
TSR Performance shares outstanding at December 31, 2008		75,555
Granted		172,075
Forfeited		(3,898	)
TSR Performance shares outstanding at December 31, 2009		243,732
TSR performance shares settled		(241,989	)
Forfeited		(1,743	)
TSR Performance shares outstanding at December 31, 2010		0

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The grant date fair value of performance shares linked to TSR granted during the twelve months ended December 31, 2009 was $4.6 million. The fair value was determined using a Monte Carlo simulation model, utilizing actual TSR information for the common shares of AE and its peers for the period from January 1, 2009 to the February 27, 2009 grant date and estimated future stock volatility and dividends of AE and its peers. The expected stock volatility assumptions for AE and its peer group was based on three-year historic stock volatility, and the annual dividend yield assumptions were based on current dividend yields at the grant date.

As of December 31, 2010, Allegheny had no unrecognized compensation cost related to performance shares linked to TSR.

Also, in 2008, 2009 and 2010, AE granted equity-based performance shares to key employees pursuant to which award recipients may earn shares of AE common stock based on AE’s performance over a three-year period compared to its Annual Incentive Plan (“AIP”) targets established at the beginning of each year. Upon stockholder approval of the proposed Merger with FirstEnergy, AE settled all 242,266 outstanding AIP performance shares awarded in 2008 and 2009 through the issuance of 154,771 shares of its common stock, representing 100% of each participant’s target award less shares withheld to meet minimum income tax withholding requirements.

For the 2010 performance shares linked to AIP targets, compensation expense is recognized over the shorter of the remaining portion of the three-year performance period or retirement eligible date in certain situations, as if the awards were separate annual awards each in the amount of one-third of the total 2010 grant, using an estimated annual forfeiture rate of 5%. The percentage of target shares earned can range from 0% to 200%. As of December 31, 2010, there was approximately $5.7 million of unrecognized compensation cost related to the 2010 grant of AIP performance share awards, which is expected to be recognized over a weighted average period of approximately 1 year. Activity in target performance shares linked to the AIP was as follows:

	Number of Shares
AIP Performance shares outstanding at December 31, 2007		0
Granted		83,796
Forfeited		(8,103	)
AIP Performance shares outstanding at December 31, 2008		75,693
Granted		172,220
Forfeited		(3,903	)
AIP Performance shares outstanding at December 31, 2009		244,010
Granted		764,049
AIP performance shares settled		(242,417	)
Forfeited		(8,223	)
AIP Performance shares outstanding at December 31, 2010		757,419

Stock Units

Allegheny’s Stock Unit Plan permitted the grant to Allegheny’s key executives, at the time of hire, of stock units representing up to 4.5 million shares of AE’s common stock. Upon vesting, each stock unit converted into one share of AE common stock. These stock units vested in annual tranches on a pro-rata basis over the vesting period. Stock unit awards granted prior to January 1, 2006 were expensed using the graded-vesting method. The fair value of each stock unit was equivalent to the market price of Allegheny’s stock on the date of grant. No stock units have been granted since 2005, and Allegheny had no unrecognized compensation cost related to stock units at December 31, 2010 and 2009.

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Stock unit activity for the last three years was as follows:

	Number of Stock Units			Weighted-Average Grant Date Fair Value		Aggregate Intrinsic Value (a) (in millions)
Outstanding at December 31, 2007		451,055		$	15.40	$	28.7
Units converted into 270,633 common shares		(447,640	)	$	15.53
Dividends on unvested grants		1,672		$	47.69
Outstanding at December 31, 2008		5,087		$	15.19	$	0.2
Units converted into 3,573 common shares		(5,147	)	$	15.31
Dividends on unvested grants		60		$	25.47
Outstanding at December 31, 2009 and 2010		0		$	0	$	0

(a) Represents the total pre-tax intrinsic value based on stock units outstanding multiplied by AE’s closing stock price on each respective date.

The total pre-tax intrinsic value of stock units converted to shares of AE common stock during 2009 and 2008 was $0.1 million and $23.1 million, respectively. Allegheny issued new shares of its common stock in connection with the stock unit conversions. The actual number of common shares issued upon conversion of stock units was net of shares withheld to meet minimum income tax withholding requirements.

Non-Employee Director Stock Awards

Under the Non-Employee Director Stock Plan, during 2010, 2009 and 2008, each non-employee member of AE’s Board of Directors received, on a quarterly basis, subject to his or her election to defer his or her receipt, shares of AE common stock with a value equivalent to the lesser of 1,000 shares or $30,000 of AE common stock as determined based on the closing price of AE common stock on the last business day of each calendar quarter for services performed. 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. The 2010, 2009 and 2008 compensation of each non-employee director was 4,000 shares, 4,000 shares and 2,895 shares, respectively, of AE’s common stock. The amount of expense relating to this plan for 2010, 2009 and 2008 was $0.8 million, $0.9 million and $1.1 million, respectively, representing the closing price of AE’s common stock on the date of grant multiplied by the number of shares granted.

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Non-employee director stock awards activity in the last three years was as follows:

	Number of Shares
Shares earned but not issued at December 31, 2007		65,177
Granted		26,055
Issued		(20,869	)
Dividends on earned but not issued shares		858
Shares earned but not issued at December 31, 2008		71,221
Granted		36,000
Issued		(22,201	)
Dividends on earned but not issued shares		1,669
Shares earned but not issued at December 31, 2009		86,689
Granted		36,000
Issued		(12,000	)
Dividends on earned but not issued shares		2,460
Shares earned but not issued at December 31, 2010		113,149

Restricted Shares

In the first quarter of 2009, AE granted 17,850 restricted shares with an aggregate fair value of $0.4 million and a three year vesting period.

	Number of Shares
Restricted shares outstanding at December 31, 2008		0
Granted		17,850
Shares vested		(5,950	)
Restricted shares outstanding at December 31, 2009		11,900
Shares vested		(11,900	)
Restricted shares outstanding at December 31, 2010		0

Upon shareholder approval of the proposed Merger in September 2010, all 11,900 outstanding shares of restricted stock vested, of which 3,642 shares were purchased as treasury stock to meet minimum income tax withholding requirements. As of December 31, 2010, Allegheny had no unrecognized compensation cost related to restricted shares.

NOTE 12:  PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s personnel, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains a Supplemental Executive Retirement Plan (the “SERP”) for certain senior executives.

Allegheny also provides subsidies for medical and life insurance plans for eligible retirees and dependents. Eligible retirees are charged premiums for medical coverage based on plan provisions, including age and years-of-service. Subsidized medical coverage is not provided in retirement to employees hired on or after

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January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006. The provisions of the postretirement health care plans and certain collective bargaining arrangements limit Allegheny’s 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 by Allegheny were as follows:

	Pension Benefits									Postretirement Benefits Other Than Pensions
(In millions)	2010			2009			2008			2010			2009			2008
Components of net periodic cost:
Service cost	$	26.2		$	22.3		$	21.2		$	4.2		$	4.4		$	4.4
Interest cost		71.6			70.9			68.5			15.7			17.2			17.2
Expected return on plan assets		(73.8	)		(74.2	)		(76.8	)		(6.0	)		(5.3	)		(7.3	)
Amortization of unrecognized transition obligation		0.5			0.5			0.5			5.7			5.7			5.7
Amortization of prior service cost		3.2			3.2			3.2			0			0			0
Recognized actuarial loss		18.2			11.1			7.2			0			1.9			0.7
Net periodic cost	$	45.9		$	33.8		$	23.8		$	19.6		$	23.9		$	20.7

For the years ended December 31, 2010, 2009 and 2008, Allegheny capitalized $19.4 million, $17.7 million and $13.2 million, respectively, of the above net periodic cost amounts to CWIP, a component of “Property, plant and equipment, net.”

During the first quarter of 2010, Allegheny determined that its benefit obligation of $264.2 million at December 31, 2009 for postretirement benefits other than pensions was understated by approximately $14.9 million. As a result, Allegheny increased its recorded benefit obligation during the first quarter of 2010, and recorded additional expense of approximately $10.4 million and a charge to CWIP in the amount of approximately $4.5 million. Also, in the third quarter of 2010, Allegheny made an adjustment to reduce its accrued liability for medical benefits by approximately $18.0 million, resulting in a credit to CWIP of approximately $1.5 million, a credit to benefits expense of approximately $3.5 million and a credit to accumulated other comprehensive income of approximately $13.0 million.

These adjustment amounts are not included in the preceding 2010 net periodic cost tables, but are presented as other adjustments in the change in benefit obligation table disclosed later in this note.

In 2008, as required by GAAP, Allegheny changed to a December 31 measurement date for its pension plans, postretirement benefits other than pension plans and long-term disability plan. Accordingly, Allegheny performed a measurement of plan assets and liabilities as of December 31, 2008. Allegheny’s prior measurement date for these plans was September 30, 2007. Twelve fifteenths of net periodic cost for the fifteen month period from September 30, 2007 to December 31, 2008 was recorded as current year benefit costs and three fifteenths of the total cost was charged to retained earnings as of December 31, 2008, net of tax. The adjustment to retained earnings in the amount of $6.8 million was comprised of $6.0 million of pension benefit costs less income tax effect of $2.4 million and $5.4 million of other benefit plan costs less income tax effect of $2.2 million.

Allegheny uses the market-related value of pension assets to determine the expected return on pension plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a

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straight line basis over a five-year period. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Allegheny uses the fair value of assets to determine the expected return on postretirement benefits other than pension assets.

The amounts in accumulated other comprehensive loss and regulatory assets that are expected to be recognized as components of net periodic cost during the next fiscal year are as follows:

(In millions)	Pension Benefits		Postretirement Benefits Other Than Pensions
Net actuarial loss	$	25.6	$	0
Net prior service cost		3.2		0
Net transition obligation		0.5		5.7
Total to be recognized in net periodic cost	$	29.3	$	5.7

The amounts accrued at December 31, using a measurement date of December 31, included the following components:

	Pension Benefits						Postretirement Benefits Other Than Pensions
(In millions)	2010			2009			2010			2009
Change in benefit obligation:
Benefit obligations at beginning of year	$	1,226.4		$	1,124.9		$	264.2		$	269.8
Service cost		26.2			22.3			4.2			4.4
Interest cost		71.6			70.9			15.7			17.2
Plan participants’ contributions		0			0			4.7			4.4
Actuarial (gain)/loss		67.9			76.0			(11.4	)		(9.3	)
Benefits paid from plan assets		(68.6	)		(67.2	)		(15.8	)		(19.0	)
Benefits paid from Allegheny assets		(0.5	)		(0.5	)		(4.7	)		(4.8	)
Medicare Part D subsidy		0			0			1.4			1.5
Other adjustments		0			0			14.9			0
Benefit obligation at end of year		1,323.0			1,226.4			273.2			264.2
Change in plan assets:
Fair value of plan assets at beginning of year		815.5			750.1			77.2			66.2
Actual return on plan assets		99.7			95.1			7.2			18.3
Plan participants’ contributions		0			0			4.7			4.4
Employer contribution		77.5			38.0			2.0			7.3
Benefits paid		(69.1	)		(67.7	)		(15.8	)		(19.0	)
Fair value of plan assets at end of year		923.6			815.5			75.3			77.2
Funded status at December 31	$	(399.4	)	$	(410.9	)	$	(197.9	)	$	(187.0	)

The SERP is a non-qualified pension plan, and Allegheny is therefore not obligated to fund the SERP obligation. The SERP obligation, which is included as a component of the pension benefit obligation shown in the table above, was $12.0 million and $10.1 million at December 31, 2010 and 2009, 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)	2010			2009			2010			2009
Current liabilities	$	(0.5	)	$	(0.5	)	$	0		$	0
Noncurrent liabilities		(398.9	)		(410.4	)		(197.9	)		(187.0	)
Net amounts recognized at December 31	$	(399.4	)	$	(410.9	)	$	(197.9	)	$	(187.0	)

Amounts recognized in “Accumulated other comprehensive loss,” pre-tax, at December 31, that have not yet been recognized as components of net periodic benefit cost, were as follows:

	Pension Benefits						Postretirement Benefits Other Than Pensions
(In millions)	2010			2009			2010			2009
Net actuarial loss	$	489.7		$	466.0		$	0.7		$	26.4
Net prior service cost		8.0			11.2			0			0
Net transition obligation		0.8			1.2			10.0			15.7
Amounts not yet recognized in net periodic benefit cost		498.5			478.4			10.7			42.1
Regulatory asset		(376.6	)		(362.9	)		(8.1	)		(33.6	)
Accumulated other comprehensive loss, pre-tax, at December 31	$	121.9		$	115.5		$	2.6		$	8.5

Allegheny has determined that a portion of the unfunded pension and postretirement benefit obligations represents an incurred cost that qualifies for regulatory asset treatment under GAAP. Because future recovery of these incurred costs are probable for certain of its state and federal jurisdictions, Allegheny has recorded regulatory assets in the amounts of $376.6 million and $362.9 million for pension benefits and $8.1 million and $33.6 million for postretirement benefits other than pensions at December 31, 2010 and 2009, respectively.

The accumulated benefit obligation for all defined benefit pension plans was $1.22 billion and $1.12 billion at December 31, 2010 and 2009, respectively. The portion of the total accumulated benefit obligation related to the SERP was $11.1 million and $9.0 million at December 31, 2010 and 2009, respectively.

Information for pension plans with a projected benefit obligation and an accumulated benefit obligation in excess of plan assets was as follows:

(In millions)	Pension Benefits
	2010		2009
Projected benefit obligation	$	1,323.0	$	1,226.4
Accumulated benefit obligation	$	1,221.6	$	1,122.4
Fair value of plan assets	$	923.6	$	815.5

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The assumptions used to determine net periodic benefit costs for the years ended December 31, 2010, 2009 and 2008 are shown in the table below.

	2010			2009			2008
Discount rate:
Pension (Qualified Plan)		6.00	%		6.50	%		6.40	%
SERP		6.00	%		6.40	%		6.40	%
Postretirement benefits other than pension		5.80	%		6.60	%		6.40	%
Expected long-term rate of return on plan assets, net of administrative expenses		8.00	%		8.25	%		8.25	%
Rate of compensation increase (a)		3.60	%		3.60	%		3.60	%

(a) Weighted-average rate for age graded scale.

The assumptions used to determine benefit obligations at December 31, 2010 and 2009 are shown in the table below:

	2010			2009
Discount rate:
Pension (Qualified Plan)		5.50	%		6.00	%
SERP		5.50	%		6.00	%
Postretirement benefits other than pension		5.20	%		5.80	%
Rate of compensation increase (a)		3.35	%		3.60	%

(a) Weighted-average rate for age graded scale.

Allegheny determines its discount rate assumptions through the use of a cash flow matching process in which the timing and amount of estimated benefit cash flows for each benefit plan are matched with an interest rate curve applicable to the returns of high quality corporate bonds over the expected benefit payment period to determine an overall effective discount rate.

Allegheny determines its expected long-term rate of return on plan assets based on historical and expected future asset returns for each plan investment category as well as the current and expected future allocation of plan assets by investment category. The expected long-term rates of return on plan assets used to develop net periodic pension costs and postretirement benefit costs other than pension costs for 2011 are 7.75% and 5.00%, respectively.

Assumed health care cost trend rates at December 31 were as follows:

	2010			2009
Health care cost trend rate assumed for next year		8.0	%		8.5	%
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		2017			2017

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For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 8.0% beginning in 2011 and decreasing by 0.5% each year thereafter to an ultimate rate of 5.0% in 2017, 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 service and interest cost components	$	0.8	$	(0.7	)
Effect on accumulated postretirement benefit obligation	$	11.3	$	(9.3	)

Under the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”), the federal government provides subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. The subsidy is 28% of eligible drug costs for retirees who are over age 65 and covered under Allegheny’s postretirement benefits other than pension plan.

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act were signed into law. The legislation effectively changes the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to prescription drug benefits provided under Medicare Part D. Beginning in 2013, an employer’s income tax deduction for the cost of providing Medicare Part D equivalent prescription drug benefits will be reduced by the amount of the federal subsidy. The impact of this change in tax treatment of the federal subsidy did not have a significant impact on Allegheny’s deferred income tax assets or income tax expense, because Allegheny expects that the majority of the prescription drug benefits provided under its health benefit plans will not be actuarially equivalent to Medicare Part D benefits for periods after 2012. Allegheny received a total subsidy of approximately $1.4 million for 2010, $1.5 million for 2009 and $1.6 million for 2008.

Plan Assets

The long-term target asset allocation of the defined benefit pension plan is 50% equity securities and 50% fixed income securities. The long-term target for the assets associated with the postretirement benefits other than pension plans vary based on the particular structure of each plan and range from 55% to 75% equity securities and from 25% to 45% fixed income securities. Equity securities primarily include investments in large-cap and mid-cap companies primarily located in the United States (“U.S.”) and in international large-cap companies. Fixed income securities include corporate bonds of companies from diversified industries. Under the plans’ investment policies, the actual allocations may vary from the long-term 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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The following table disaggregates by level within the fair value hierarchy described in Note 14, “Fair Value Measurements, Derivative Investments and Hedging Activities,” the fair value of the pension plan’s investments by class as of December 31, 2010 and December 31, 2009:

	2010 Fair Value Hierarchy Level								2009 Fair Value Hierarchy Level
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash equivalents (a)	$	0	$	31.5	$	0	$	31.5	$	0	$	3.3	$	0	$	3.3
Equity securities:
U.S. large-cap (b)		0		281.8		0		281.8		0		227.7		0		227.7
U.S. mid-cap growth (c)		0		50.7		0		50.7		0		42.4		0		42.4
International large-cap (d)		0		133.5		0		133.5		0		114.9		0		114.9
Domestic real estate (e)		0		23.2		0		23.2		0		18.0		0		18.0
Fixed income securities:
Corporate bonds (f)		0		53.4		0		53.4		0		24.9		0		24.9
Government securities (g)		0		19.9		0		19.9		0		53.6		0		53.6
Group annuity contract (h)		0		329.6		0		329.6		0		330.7		0		330.7
Total	$	0	$	923.6	$	0	$	923.6	$	0	$	815.5	$	0	$	815.5

(a) This class seeks to generate a reasonable rate of return by investing in securities that are either issued or guaranteed by the U.S. Treasury and/or U.S. Government Agencies.

(b) This class seeks to match the returns of the S&P 500 Index and the Russell 1000 Index. Approximately 72% of these assets are invested to match the Russell 1000 index and 28% are invested to match the S&P 500 Index.

(c) This class seeks to match the return of the Russell 2000 Index.

(d) This class seeks to match the performance of the Morgan Stanley Capital International EAFE Index while providing low cost, broadly diversified, non-U.S. exposure.

(e) This class seeks to match the return of the Dow Jones U.S. Select REIT Index.

(f) Approximately one-half of the investment in this class seeks to match the return of the High Yield $200 Million Very Liquid Index, a customized Barclays Capital Index. The other one-half of the investment seeks a return that approximates the performance of the Barclays Capital U.S. Long Credit Bond Index.

(g) This class seeks to match the return of the Barclays Capital U.S. Long Government Bond Index.

(h) An unallocated group annuity contract with Metropolitan Life Insurance Company. Valued at a price per unit that is based upon the underlying value of the domestic fixed income securities.

The following table disaggregates by level within the fair value hierarchy the fair value of the postretirement benefits other than pensions plan’s investments by asset class as of December 31, 2010 and December 31, 2009:

	2010 Fair Value Hierarchy Level								2009 Fair Value Hierarchy Level
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash equivalents (a)	$	0	$	0.8	$	0	$	0.8	$	0	$	1.4	$	0	$	1.4
Equity securities:
U.S. large-cap (b)		0		23.5		0		23.5		0		21.7		0		21.7
Trust owned life insurance (TOLI) (c)		0		0		0		0		0		38.2		0		38.2
Fixed income securities (d)		0		51.0		0		51.0		0		15.9		0		15.9
Total	$	0	$	75.3	$	0	$	75.3	$	0	$	77.2	$	0	$	77.2

(a) This class seeks to generate a reasonable rate of return by investing in high grade money market instruments.

(b) This class seeks to match the return of the S&P 500 Index.

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(c) The TOLI is an unallocated insurance contract that is valued based upon the underlying mutual funds and pooled investments and at the value of investments made at a London Interbank Offered Rate (LIBOR), which approximates the policy’s net cash surrender value. The underlying investments in 2009 were comprised of approximately 60% equities and 40% U.S. fixed income bonds.

(d) In this class, $16.7 million of the investment in 2010 and all of the 2009 investment seeks to match, as closely as possible, the performance of the Barclays Capital U.S. Aggregate Bond Index, by investing primarily in collateralized mortgage obligations, corporate bonds, and U.S. Treasury obligations. In 2010, the remaining $34.3 million of investment is allocated 53% to government securities and 47% to corporate bonds.

In 2009, a portion of the pension plan’s assets were invested in collective trust funds that participated in a securities lending program. These funds modified their withdrawal procedures as a result of liquidity issues affecting the funds’ ability to liquidate their securities lending collateral investment pools. At December 31, 2009, Allegheny’s pension plan participation in the collateral investment pool was approximately $56 million at cost, with a market value of approximately $55 million. At December 31, 2010, none of the pension plan’s assets were invested in collective trust funds that participate in a securities lending program.

Contributions

Allegheny makes cash contributions to its qualified pension plan to meet the minimum funding requirements of employee benefit and tax laws and may include additional discretionary contributions to increase the funded level of the plan. Allegheny has not yet determined the amount of future contributions, but expects to contribute approximately $140 million to its pension plan for the year 2011. The amount of future contributions to the plan will depend on the funded status of the plan, asset performance and other factors. Allegheny currently anticipates that it will contribute $2 million to $3 million during 2011 to fund postretirement benefits other than pensions.

The Pension Protection Act of 2006 (the “Pension Protection Act”) may affect the manner in which many companies, including Allegheny, administer their pension plans. Effective January 1, 2008, the Pension Protection Act will require many companies to more fully fund their pension plans according to new funding targets, potentially resulting in greater annual contributions. Allegheny has incorporated the Pension Protection Act funding targets and requirements into its future pension funding determination.

Estimated Future Benefit Payments

The following table shows estimated benefit payments to be made by Allegheny, and the estimated Medicare Part D subsidy to be received by Allegheny:

(In millions)	Pension Benefits		Postretirement Benefits Other Than Pensions
			Benefit Payments (a)		Medicare Part D Subsidy
2011	$	68.2	$	18.0	$	1.6
2012	$	69.4	$	18.1	$	1.3
2013	$	70.9	$	18.8	$	0.1
2014	$	72.4	$	19.3	$	0.1
2015	$	74.6	$	19.5	$	0.2
2016 – 2020	$	421.7	$	103.5	$	0.8

(a) Benefit payments are net of Medicare Part D subsidy.

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ESOSP 401(k) Savings Plan

The Allegheny Energy Employee Stock Ownership and Savings Plan (“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 may elect to have from 2% to 25% of his or her compensation contributed to the ESOSP on a pre-tax basis. Starting July 1, 2007, participants have been able to elect to make all or a portion of their respective contributions to a Roth 401(k). An additional 1% to 6% of compensation may be contributed on a post-tax basis. Allegheny matches 50% of an employee’s first 6% of pre-tax salary deferrals and Roth 401(k) contributions into the ESOSP. Participants direct the investment of all contributions to specified mutual funds or AE common stock.

In 2010, 2009 and 2008, Allegheny made ESOSP matching contributions in cash in the amount of $9.0 million, $9.0 million and $8.6 million, respectively. These contributions, less amounts capitalized in CWIP, were expensed. The capitalized portions of these costs were $2.6 million, $2.9 million and $2.5 million in 2010, 2009 and 2008, respectively.

Disability Benefits

Allegheny provides benefits to eligible employees who are unable to perform their work duties due to an injury or illness. These benefits include income replacement under the Allegheny Energy Long-Term Disability Plan and medical and life insurance benefits under Allegheny’s medical and life insurance plans. The benefits are paid in accordance with Allegheny’s established benefit practices and policies. The liability related to these disability benefits was $9.5 million at December 31, 2010 and $8.9 million at December 31, 2009 and 2008, respectively.

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NOTE 13:  SEGMENT INFORMATION

The following tables summarize the results of operations for Allegheny’s two reportable segments, the Merchant Generation segment and the Regulated Operations segment. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts. The information for the Regulated Operations segment includes the operations of the Virginia distribution business through the date of its sale on June 1, 2010. See Note 4, “Sale of Virginia Distribution Business,” for additional information.

(In millions)	Merchant Generation			Regulated Operations			Eliminations (a)			Total
2010
Operating revenues:
External operating revenues	$	467.9		$	3,435.0		$	0		$	3,902.9
Internal operating revenues		1,290.7			5.3			(1,296.0	)		0
Total operating revenues		1,758.6			3,440.3			(1,296.0	)		3,902.9
Operating expenses:
Fuel		876.0			316.6			0			1,192.6
Purchased power and transmission		38.4			1,755.2			(1,290.7	)		502.9
Deferred energy costs, net		0			38.1			0			38.1
Gain on sale of Virginia distribution business		0			(44.6	)		0			(44.6	)
Operations and maintenance		250.7			487.5			(5.3	)		732.9
Depreciation and amortization		129.7			195.5			(1.7	)		323.5
Taxes other than income taxes		51.2			174.8			0			226.0
Total operating expenses		1,346.0			2,923.1			(1,297.7	)		2,971.4
Operating income		412.6			517.2			1.7			931.5
Other income (expense), net		3.6			22.2			(12.5	)		13.3
Interest expense		145.8			173.7			(3.1	)		316.4
Income before income taxes		270.4			365.7			(7.7	)		628.4
Income tax expense		98.7			118.0			0			216.7
Net income		171.7			247.7			(7.7	)		411.7
Net income attributable to noncontrolling interests		(8.6	)		0			8.6			0
Net income attributable to Allegheny Energy, Inc.	$	163.1		$	247.7		$	0.9		$	411.7

(a) Represents elimination of transactions between reportable segments.

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(In millions)	Merchant Generation			Regulated Operations			Eliminations (a)			Total
2009
Operating revenues:
External operating revenues	$	383.1		$	3,043.7		$	0		$	3,426.8
Internal operating revenues		1,225.5			7.5			(1,233.0	)		0
Total operating revenues		1,608.6			3,051.2			(1,233.0	)		3,426.8
Operating expenses:
Fuel		675.5			211.1			0			886.6
Purchased power and transmission		26.4			1,702.8			(1,227.2	)		502.0
Deferred energy costs, net		0			(64.4	)		0			(64.4	)
Operations and maintenance		247.0			445.9			(5.8	)		687.1
Depreciation and amortization		106.8			177.1			(1.8	)		282.1
Taxes other than income taxes		47.2			166.4			0			213.6
Total operating expenses		1,102.9			2,638.9			(1,234.8	)		2,507.0
Operating income		505.7			412.3			1.8			919.8
Other income (expense), net		1.0			17.1			(11.1	)		7.0
Interest expense		134.9			157.4			(1.2	)		291.1
Income before income taxes		371.8			272.0			(8.1	)		635.7
Income tax expense		128.8			112.8			0			241.6
Net income		243.0			159.2			(8.1	)		394.1
Net income attributable to noncontrolling interests		(9.0	)		(1.3	)		9.0			(1.3	)
Net income attributable to Allegheny Energy, Inc.	$	234.0		$	157.9		$	0.9		$	392.8
2008
Operating revenues:
External operating revenues	$	554.9		$	2,831.0		$	0		$	3,385.9
Internal operating revenues		1,238.0			24.3			(1,262.3	)		0
Total operating revenues		1,792.9			2,855.3			(1,262.3	)		3,385.9
Operating expenses:
Fuel		793.4			287.5			0			1,080.9
Purchased power and transmission		30.3			1,622.3			(1,257.0	)		395.6
Deferred energy costs, net		0			(63.7	)		0			(63.7	)
Operations and maintenance		222.1			458.0			(5.3	)		674.8
Depreciation and amortization		94.1			181.9			(2.1	)		273.9
Taxes other than income taxes		47.6			167.3			0			214.9
Total operating expenses		1,187.5			2,653.3			(1,264.4	)		2,576.4
Operating income		605.4			202.0			2.1			809.5
Other income (expense), net		7.8			28.6			(14.1	)		22.3
Interest expense		99.7			135.6			(3.4	)		231.9
Income before income taxes		513.5			95.0			(8.6	)		599.9
Income tax expense		179.7			24.4			0			204.1
Net income		333.8			70.6			(8.6	)		395.8
Net income attributable to noncontrolling interests		(9.5	)		(0.4	)		9.5			(0.4	)
Net income attributable to Allegheny Energy, Inc.	$	324.3		$	70.2		$	0.9		$	395.4

(a) Represents elimination of transactions between reportable segments.

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Capital expenditures and identifiable assets by segment were as follows:

(In millions)	Merchant Generation		Regulated Operations		Other (b)		Eliminations (a)			Total
2010
Capital expenditures	$	141.6	$	808.9	$	0	$	0		$	950.5
Identifiable assets	$	4,482.5	$	7,537.2	$	76.4	$	(6.8	)	$	12,089.3
2009
Capital expenditures	$	233.4	$	932.8	$	0	$	0		$	1,166.2
Identifiable assets	$	4,284.6	$	7,286.7	$	74.7	$	(56.9	)	$	11,589.1
2008
Capital expenditures	$	347.2	$	646.9	$	0	$	0		$	994.1
Identifiable assets	$	4,268.8	$	6,567.0	$	91.3	$	(116.1	)	$	10,811.0

(a) Represents elimination transactions between reportable segments.

(b) Represents identifiable assets not directly attributable to segments.

NOTE 14:  FAIR VALUE MEASUREMENTS, DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Allegheny determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants and based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties and the impact of credit enhancements, but also the impact of Allegheny’s own nonperformance risk on its liabilities. Allegheny uses a fair value hierarchy based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company’s own assumptions about the assumptions that market participants would use. The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below.

Level 1	—	Quoted prices for identical instruments in active markets.
Level 2	—	Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations for which all significant inputs are observable market data.
Level 3	—	Unobservable inputs significant to the fair value measurement supported by little or no market activity.

In some cases, the inputs used to measure fair value may meet the definition of more than one level of fair value hierarchy. The lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.

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Allegheny’s assets and liabilities measured at fair value on a recurring basis at December 31, 2010 and 2009 consisted of the following:

	December 31, 2010					December 31, 2009
(In millions)	Assets		Liabilities			Assets		Liabilities
Cash equivalents (a)	$	338.8	$	0		$	194.2	$	0
Derivative instruments (b):
Current		134.3		(7.5	)		128.3		(24.5	)
Non-current		0		(12.4	)		0		(9.7	)
Total derivative instruments		134.3		(19.9	)		128.3		(34.2	)
Total recurring fair value measurements	$	473.1	$	(19.9	)	$	322.5	$	(34.2	)

(a) Cash equivalents represent amounts invested in money market mutual funds and are valued using Level 1 inputs.

(b) Before netting of cash collateral and FTR obligations.

See Note 12, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for information related to fair value measurements of pension and other postretirement benefit plan assets.

All derivatives, except those for which an exception applies, are recorded in Allegheny’s Consolidated Balance Sheets at fair value. Derivative contracts that have been designated as normal purchases or normal sales are not subject to mark to market accounting treatment, and their effects are included in earnings at the time of contract performance.

Certain derivative contracts that hedge an exposure to variability in expected future cash flows attributable to a particular risk or transaction have been designated as cash flow hedges. Allegheny’s hedge strategies include the use of derivative contracts to manage the variable price risk related to forecasted sales and forecasted purchases of electricity. These contracts held at December 31, 2010 expire at various dates through December 2012.

For cash flow hedges, changes in the fair value of the derivative contract are reported in accumulated other comprehensive income (loss), to the extent they are effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. Changes in any ineffective portion of the hedge are immediately recognized in earnings.

For derivative contracts that have not been designated as normal purchase or normal sales or designated as part of a hedging relationship, any unrealized and realized gains and losses are included in revenues or expenses on the Consolidated Statements of Income, depending on relevant facts and circumstances.

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The following table disaggregates the net fair values of derivative assets and liabilities by class, before netting of cash collateral and FTR obligation, based on their level within the fair value hierarchy at December 31, 2010. This table excludes derivatives that have been designated as normal purchases or normal sales.

	Fair Value at December 31, 2010
(In millions)	Level 1			Level 2			Level 3		Total
Derivative assets:
Power contracts	$	1.5		$	15.5		$	0	$	17.0
FTRs		0			0			117.3		117.3
Total derivative assets		1.5			15.5			117.3		134.3
Derivative liabilities:
Power contracts		(8.3	)		(9.5	)		0		(17.8	)
Interest rate swaps		0			(2.1	)		0		(2.1	)
Total derivative liabilities		(8.3	)		(11.6	)		0		(19.9	)
Net derivative assets (liabilities)	$	(6.8	)	$	3.9		$	117.3	$	114.4

The following table disaggregates the net fair values of derivative assets and liabilities by class, before netting of cash collateral and FTR obligation, based on their level within the fair value hierarchy at December 31, 2009. This table excludes derivatives that have been designated as normal purchases or normal sales.

	Fair Value at December 31, 2009
(In millions)	Level 1			Level 2			Level 3		Total
Derivative assets:
Power contracts	$	0		$	0		$	0	$	0
Gas contracts		31.9			0.2			0		32.1
FTRs		0			0			96.2		96.2
Total derivative assets		31.9			0.2			96.2		128.3
Derivative liabilities:
Power contracts		(4.7	)		(21.3	)		0		(26.0	)
Gas contracts		0			(0.1	)		0		(0.1	)
Interest rate swaps		0			(8.1	)		0		(8.1	)
Total derivative liabilities		(4.7	)		(29.5	)		0		(34.2	)
Net derivative assets (liabilities)	$	27.2		$	(29.3	)	$	96.2	$	94.1

Derivative assets and liabilities included in Level 1 primarily consist of exchange-traded futures and other exchange-traded transactions that are valued using closing prices for identical instruments in active markets. Derivative assets and liabilities included in Level 2 primarily consist of commodity forward contracts and interest rate swaps. Derivatives included in Level 2 are valued using a pricing model with inputs that are observable in the market, such as quoted forward prices of commodities, or that can be derived from or corroborated by observable market data. Derivative assets included in Level 3 consist of FTRs and are valued using an internal model based on data from PJM monthly and annual FTR auctions.

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The following table shows the expected settlement year for derivative assets and liabilities outstanding before netting of cash collateral and FTR obligation at December 31, 2010. This table excludes derivatives that have been designated as normal purchases or normal sales:

(In millions)	2011		2012			Total
Level 1	$	0	$	(6.8	)	$	(6.8	)
Level 2		9.5		(5.6	)		3.9
Level 3		117.3		0			117.3
Net derivative assets (liabilities)	$	126.8	$	(12.4	)	$	114.4

The following table shows the expected settlement year for derivative assets and liabilities outstanding before netting of cash collateral and FTR obligation at December 31, 2009. This table excludes derivatives that have been designated as normal purchases or normal sales:

(In millions)	2010			2011			2012			Total
Level 1	$	31.8		$	(1.0	)	$	(3.6	)	$	27.2
Level 2		(24.2	)		(4.1	)		(1.0	)		(29.3	)
Level 3		96.2			0			0			96.2
Net derivative assets (liabilities)	$	103.8		$	(5.1	)	$	(4.6	)	$	94.1

The following tables provide a reconciliation of the beginning and ending balance of FTR derivative assets measured at fair value (Level 3):

(In millions)	2010			2009
Balance at January 1	$	96.2		$	189.8
Total realized and unrealized gains (losses):
Included in earnings, in operating revenues		57.6			(164.2	)
Included in regulatory assets or liabilities		30.2			(82.9	)
Purchases, issuances and settlements		(66.7	)		153.5
Transfers in / out of Level 3		0			0
Balance at December 31	$	117.3		$	96.2
Amount of total gains (losses) included in earnings attributable to the change in unrealized gains (losses) related to Level 3 assets held at December 31	$	18.3		$	(3.6	)

There were no transfers between Level 1 and Level 2, and no transfers into or out of Level 3, of the fair value hierarchy for the years ended December 31, 2010 and 2009. To the extent that it has transfers between these levels, Allegheny accounts for the transfers at the end of the reporting period.

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The volume and expiration of Allegheny’s derivative contracts at December 31, 2010 that did not qualify for the normal purchase or normal sale exemption were as follows:

(In millions)	2011		2012		Total
Electricity contracts (MWhs):
Sales of power		15.2		2.6		17.8
Purchases of power		3.9		0.6		4.5
FTRs (MWhs)		26.7		0		26.7
Gas contracts (decatherms):
Sales of gas		0.1		0		0.1
Purchases of gas		0.1		0		0.1
Interest rate swaps (notional dollars):
Interest rate swap agreements (fixed rate to floating rate)	$	200	$	0	$	200
Interest rate swap agreements (floating rate to fixed rate)	$	200	$	0	$	200

Allegheny enters into derivative contracts for the sale or purchase of power to hedge the variable price risks related to forecasted sales or purchases of power. To the extent that such contracts qualify and are designated as cash flow hedging instruments, the effective portion of unrealized gain or loss on the derivative contract is reported as a component of other comprehensive income (“OCI”) and is subsequently reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. Allegheny had 7.2 million MWhs of derivative electricity contracts that qualify and were designated as cash flow hedging instruments at December 31, 2010. Changes in the fair value of derivative electricity contracts that are not qualifying cash flow hedge instruments are reported in revenues on a mark-to-market basis. Allegheny had 15.1 million MWhs of derivative electricity contracts that were not designated as cash flow hedge instruments at December 31, 2010.

Allegheny entered into derivative contracts for the forward purchase and sale of gas to hedge a portion of the value of a capacity contract related to the Kern River pipeline that did not qualify for cash flow hedge accounting. The contracts settled in January 2011. Interest rate swaps at December 31, 2010 include two interest rate swap agreements that expire during 2011 with an aggregate notional value of $200 million that were entered into during 2003 to substantially offset two existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting.

Allegheny also holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with its load obligations. These future obligations are not reflected on Allegheny’s Consolidated Balance Sheets, and the FTRs have not been designated as cash flow hedge instruments. As a result, the timing of recognition of gains or losses on FTRs will differ from the timing of power purchases, including incurred congestion charges. Allegheny acquires its FTRs in an annual auction through a self-scheduling process involving the use of auction revenue rights (“ARRs”) allocated to members of PJM that have load serving obligations. Allegheny initially records FTRs and a FTR obligation payable to PJM at the annual FTR auction price, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by Allegheny’s unregulated subsidiaries are included in operating revenues as unrealized gains or losses. Unrealized gains or losses on FTRs held by Allegheny’s regulated subsidiaries are recorded as regulatory assets or liabilities.

Derivative contracts that have been designated as normal purchases or normal sales are not subject to mark-to-market accounting treatment, and their effects are included in earnings at the time of contract performance.

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The recorded fair values of derivatives at December 31, 2010 were as follows:

	Power Contracts
In millions	Sales			Purchases			Interest Rate Swaps			FTRs		Gross Derivatives			Netting			Net Derivatives			FTR Obligation (a)			Collateral		Balance Sheet Derivatives
Derivatives designated as hedging instruments:
Derivative assets
Current	$	6.9		$	0		$	0		$	0	$	6.9		$	(6.9	)	$	0		$	0		$	0	$	0
Long-term		1.5			0			0			0		1.5			(1.5	)		0			0			0		0
Total derivative assets		8.4			0			0			0		8.4			(8.4	)		0			0			0		0
Derivative liabilities
Current		(5.1	)		0			0			0		(5.1	)		5.1			0			0			0		0
Long-term		(0.4	)		0			0			0		(0.4	)		0.4			0			0			0		0
Total derivative liabilities		(5.5	)		0			0			0		(5.5	)		5.5			0			0			0		0
Total designated		2.9			0			0			0		2.9			(2.9	)		0			0			0		0
Derivatives not designated as hedging instruments:
Derivative assets
Current		36.0			0			0			117.3		153.3			(19.0	)		134.3			(109.8	)		0		24.5
Long-term		(1.1	)		0			0			0		(1.1	)		1.1			0			0			0		0
Total derivative assets		34.9			0			0			117.3		152.2			(17.9	)		134.3			(109.8	)		0		24.5
Derivative liabilities
Current		(23.5	)		(2.7	)		(2.1	)		0		(28.3	)		20.8			(7.5	)		0			1.5		(6.0	)
Long-term		(4.2	)		(8.2	)		0			0		(12.4	)		0			(12.4	)		0			5.0		(7.4	)
Total derivative liabilities		(27.7	)		(10.9	)		(2.1	)		0		(40.7	)		20.8			(19.9	)		0			6.5		(13.4	)
Total not designated		7.2			(10.9	)		(2.1	)		117.3		111.5			2.9			114.4			(109.8	)		6.5		11.1
Total derivatives	$	10.1		$	(10.9	)	$	(2.1	)	$	117.3	$	114.4		$	0		$	114.4		$	(109.8	)	$	6.5	$	11.1

(a) The FTR obligation at December 31, 2010 was $109.8 million and was payable to PJM in approximately equal weekly amounts through the PJM planning year ending May 31, 2011. This obligation has been netted against the FTR derivative asset balance on the consolidated balance sheet.

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The recorded fair values of derivatives at December 31, 2009 were as follows:

	Power Contracts						Gas Contracts -Kern River			Interest Rate Swaps			FTRs		Gross Derivatives			Netting			Net Derivatives			FTR Obligation (a)			Collateral			Balance Sheet Derivatives
(In millions)	Sales			Purchases
Derivatives designated as hedging instruments:
Derivative assets:
Current	$	0.3		$	0		$	0		$	0		$	0	$	0.3		$	(0.3	)	$	0		$	0		$	0		$	0
Long-term		0.6			0			0			0			0		0.6			(0.6	)		0			0			0			0
Total derivative assets		0.9			0			0			0			0		0.9			(0.9	)		0			0			0			0
Derivative liabilities:
Current		(12.1	)		(4.8	)		0			0			0		(16.9	)		(1.4	)		(18.3	)		0			0.1			(18.2	)
Long-term		(1.5	)		(5.9	)		0			0			0		(7.4	)		(0.3	)		(7.7	)		0			3.0			(4.7	)
Total derivative liabilities		(13.6	)		(10.7	)		0			0			0		(24.3	)		(1.7	)		(26.0	)		0			3.1			(22.9	)
Total designated		(12.7	)		(10.7	)		0			0			0		(23.4	)		(2.6	)		(26.0	)		0			3.1			(22.9	)
Derivatives not designated as hedging instruments:
Derivative assets:
Current		0.9			0			44.4			0			96.2		141.5			(13.2	)		128.3			(96.2	)		(27.5	)		4.6
Long-term		0			0			0			0			0		0			0			0			0			0			0
Total derivative assets		0.9			0			44.4			0			96.2		141.5			(13.2	)		128.3			(96.2	)		(27.5	)		4.6
Derivative liabilities:
Current		(0.9	)		(1.7	)		(12.4	)		(6.1	)		0		(21.1	)		14.9			(6.2	)		0			0			(6.2	)
Long-term		0			(0.9	)		0			(2.0	)		0		(2.9	)		0.9			(2.0	)		0			0			(2.0	)
Total derivative liabilities		(0.9	)		(2.6	)		(12.4	)		(8.1	)		0		(24.0	)		15.8			(8.2	)		0			0			(8.2	)
Total not designated		0			(2.6	)		32.0			(8.1	)		96.2		117.5			2.6			120.1			(96.2	)		(27.5	)		(3.6	)
Total derivatives	$	(12.7	)	$	(13.3	)	$	32.0		$	(8.1	)	$	96.2	$	94.1		$	0		$	94.1		$	(96.2	)	$	(24.4	)	$	(26.5	)

(a) The FTR obligation at December 31, 2009 was $127.9 million and was payable to PJM in approximately equal weekly amounts through the PJM planning year ending May 31, 2010. Of this obligation, $96.2 million has been netted against the FTR derivative asset balance and the remaining $31.7 million is included in non-derivative current liabilities on the consolidated balance sheet.

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The following table provides details on the changes in accumulated OCI relating to derivative assets and liabilities that qualified for cash flow hedge accounting.

(In millions)	2010			2009			2008
Accumulated OCI derivative gain (loss) at January 1 (before tax effect of $(10.8) million, $17.8 million and $(2.7) million, respectively)	$	(27.6	)	$	45.8		$	(7.0	)
Effective portion of changes in fair value (before tax effect of $13.6 million, $13.2 million and $14.7 million, respectively)		35.2			34.4			37.8
Reclassifications of (gains) losses from accumulated OCI to earnings (before tax effect of $3.6 million, $(41.8) million and $5.8 million, respectively)		9.2			(107.8	)		15.0
Accumulated OCI derivative gain (loss) at December 31 (before tax effect of $6.5 million, $(10.8) million and $17.8 million, respectively)	$	16.8		$	(27.6	)	$	45.8

Derivative gains included in accumulated OCI in the amount of $18.1 million, before tax, are expected to be reclassified to earnings over the next twelve months.

The following table shows the location and amounts of gains (losses) on derivatives designated as cash flow hedges:

(In millions)	2010			2009		2008
Gain (loss) recognized in OCI (effective portion)	$	35.2		$	34.4	$	37.8
Gains (losses) reclassified from accumulated OCI into operating revenues (effective portion)	$	(9.2	)	$	107.8	$	(15.0	)
Gain or (loss) recognized in operating revenues (ineffective portion)	$	(13.9	)	$	1.1	$	3.2

Unrealized gains (losses) on derivative instruments not designated or qualifying as cash flow hedge instruments were as follows:

(In millions)	2010			2009			2008
Recorded in operating revenues:
Interest rate swaps	$	6.1		$	6.0		$	5.1
Mark-to-market power contracts		(5.2	)		(12.1	)		10.5
Gas contracts		(32.0	)		3.5			28.5
FTRs		21.9			33.2			(36.8	)
Recorded in fuel expense:
Coal purchase contracts—PRB		0			(8.2	)		8.2
Recorded in regulatory liabilities (assets):
FTRs		11.5			15.9			(17.8	)
Coal purchase contracts—PRB		0			(7.2	)		7.2
Total	$	2.3		$	31.1		$	4.9

Credit Related Contingent Features

Certain of Allegheny’s derivative contracts contain collateral posting requirements tied to its credit ratings that would require posting of additional collateral in the event of a credit rating downgrade. The aggregate fair

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value of these derivative contracts that were in a liability position, disregarding any contractual netting arrangements, at December 31, 2010 was $4.6 million, for which Allegheny had posted no collateral. A one level downgrade in AE Supply’s senior unsecured credit rating at December 31, 2010 would have required the posting of $1.3 million of collateral for such derivative contracts in a liability position. A downgrade in AE Supply’s senior unsecured credit rating at December 31, 2010 to below Standard & Poor’s BB- or Moody’s Ba3 would have required the posting of $2.4 million of collateral for such derivative contracts in a liability position.

Credit Exposure

Allegheny and its subsidiaries have credit exposure to energy trading counterparties. The majority of these exposures are the fair value of multi-year contracts for energy sales and purchases. If these counterparties fail to perform their obligations under such contracts, Allegheny and its subsidiaries would experience lower revenues or higher costs to the extent that replacement sales or purchases could not be made at the same prices as those under the defaulted contracts.

Allegheny’s wholesale credit risk is the replacement cost for outstanding contracts and amounts owed to or due from counterparties for completed transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses in circumstances in which Allegheny has a legally enforceable right of setoff. Allegheny and its subsidiaries have credit policies to manage credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the use of master netting agreements. These agreements include credit mitigation provisions, such as margin, prepayment or other form of collateral acceptable to the counterparty. Allegheny may request additional credit assurance in the event that a counterparty’s credit ratings fall below investment grade or its exposures exceed an established credit limit.

NOTE 15:  PURCHASE OF HYDROELECTRIC GENERATION FACILITIES

In December 2009, Allegheny purchased two hydroelectric generation facilities located at Allegheny Lock and Dam 5 and 6 in Freeport, Pennsylvania with a nominal maximum generation capacity of 13 MW. This purchase effectively settled existing power purchase agreements under which Allegheny purchased the power generated by these facilities through 2034. Accordingly, at the transaction closing date, Allegheny recorded a credit to purchased power expense in the amount of $10.6 million, representing the fair value of the power agreements at that date. The purchase of the facilities was accounted for as a business combination for which the total consideration was $12.6 million consisting of a cash payment of approximately $2.0 million plus the fair value of the power purchase agreements. The fair value of the net assets acquired exceeded the total consideration paid by $6.7 million, representing a bargain purchase that was credited to operations and maintenance expense.

NOTE 16:  JOINTLY OWNED BATH COUNTY GENERATION FACILITY

AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC records a prorated share of all expenditures related to its interest in the Bath County generation facility. AGC is consolidated with Allegheny through its subsidiary, AE Supply. AGC’s investment and accumulated depreciation in its 40% interest in the Bath County generation facility, at December 31 were as follows:

(In millions)	2010		2009
Property, plant and equipment	$	834.0	$	833.3
Accumulated depreciation	$	363.5	$	346.4

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NOTE 17:  FAIR VALUE OF FINANCIAL INSTRUMENTS

See Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for information regarding assets and liabilities that are recorded at fair value on Allegheny’s consolidated balance sheets.

As of December 31, 2010 and 2009, the carrying amounts of accounts receivable and accounts payable are representative of fair value because of their short-term nature. The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year, net of unamortized debt discounts of $7.5 million and $7.4 million at December 31, 2010 and 2009, respectively were as follows:

	December 31,
	2010				2009
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	4,701.5	$	4,873.2	$	4,557.8	$	4,729.1

The fair value of long-term debt was estimated based on actual market prices or market prices of similar debt issues.

Allegheny also has certain assets and liabilities that are recorded at fair value relating to pension plan assets and derivative instruments. See Note 12, “Pension Benefits and Postretirement Benefits Other Than Pensions” and Note 14, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for additional information.

NOTE 18:  GOODWILL AND INTANGIBLE ASSETS

Allegheny’s consolidated balance sheets at December 31, 2010 and 2009 included goodwill of $367.3 million, which was attributable to the unregulated generation operations of AE Supply, a reporting unit that substantially comprises Allegheny’s Merchant Generation segment.

Allegheny tests goodwill for possible impairment on an annual basis as of August 31 of each year and at any other time if events or changes in circumstances make it likely that the fair value of the reporting unit has decreased below its carrying amount.

Goodwill is tested for impairment using a fair value based approach. The first step of the test consists of comparing the reporting unit’s fair value to its carrying value, including the goodwill allocated to the reporting unit. If the reporting unit’s fair value exceeds its carrying amount, the reporting unit’s goodwill is considered not impaired. If the carrying amount of the reporting unit exceeds its fair value, a second step is performed to measure the amount of the impairment loss, if any. The second step requires a calculation of the implied fair value of the reporting unit’s goodwill determined in the same manner as the amount of goodwill recorded in a business combination. This implied fair value is then compared to the carrying amount of the goodwill. If the carrying amount of the goodwill exceeds its implied fair value, an impairment loss is recognized.

Allegheny performed its annual goodwill impairment test as of August 31, 2010. The estimated fair value of the reporting unit exceeded its carrying amount by a significant amount and, therefore, no goodwill impairment was indicated at that date. The fair value was estimated using a combination of a discounted cash flow analysis approach and a market based approach that estimates fair value based on market multiples of earnings before interest, taxes, depreciation and amortization for other merchant generators. Significant assumptions used in estimating the fair value of the reporting unit include, among others, discount and growth rates, future energy and capacity prices, plant performance, operating and capital expenditures, environmental regulations, and the selection of comparable companies used in the market based approach.

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Intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:

(In millions)	December 31, 2010				December 31, 2009
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Land easements, amortized	$	109.0	$	32.4	$	108.6	$	32.1
Land easements, unamortized		30.7		0		32.3		0
Software		70.1		38.7		70.3		31.1
Total	$	209.8	$	71.1	$	211.2	$	63.2

Amortization expense for intangible assets was $12.4 million in 2010, $12.6 million in 2009 and $12.2 million in 2008.

Future amortization expense for intangible assets at December 31, 2010 is estimated as follows:

(In millions)	2011		2012		2013		2014		2015
Annual amortization expense	$	12.1	$	11.1	$	9.6	$	3.2	$	2.0

NOTE 19:  ASSET RETIREMENT OBLIGATIONS (“ARO”)

Allegheny has AROs primarily related to ash landfills, underground and aboveground storage tanks, asbestos contained in its generation facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”).

The following table provides a reconciliation of the beginning and ending ARO liability for 2010, 2009 and 2008:

(In millions)	2010			2009			2008
Balance at January 1	$	55.2		$	48.9		$	61.0
Accretion of ARO liability		5.3			4.8			6.1
Liabilities incurred in the current period:
Ash disposal sites		6.1			3.5			0
Liabilities settled:
Storage tanks		(5.2	)		0			0
Asbestos removal		(2.1	)		(1.8	)		(0.5	)
Ash disposal sites		(0.1	)		(0.1	)		(0.1	)
Other		0			0			(0.1	)
Revision in estimated cash flows:
Ash disposal sites		0			0			(13.9	)
Wastewater treatment lagoons		0			0			(2.4	)
Asbestos		0			0			(1.2	)
Liability associated with assets held for sale		0			(0.1	)		0
Balance at December 31	$	59.2		$	55.2		$	48.9

Allegheny believes it is probable that it will recover the ARO costs incurred by its regulated companies in rates. Therefore, it records costs currently incurred for AROs as a reduction to the recorded regulatory liability or

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it establishes a regulatory asset depending on the rate recovery mechanism of the specific jurisdiction. See Note 7, “Regulatory Assets and Liabilities” for a discussion of the regulatory assets and liabilities associated with asset retirement and removal costs.

NOTE 20:  ADVERSE POWER PURCHASE COMMITMENT LIABILITY

In May 1998, 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 in November 1998. West Penn recorded an extraordinary charge in 1998 to reflect the disallowances of certain costs in the order. This charge included an estimated amount for an adverse power purchase commitment reflecting the commitment to purchase power at above-market prices. The adverse power purchase commitment liability is being amortized over the life of the commitment based on a schedule of estimated electricity purchases used to determine the amount of the charge.

As of December 31, 2010, Allegheny’s reserve for adverse power purchase commitments was $114.4 million, including a current liability of $18.1 million. Allegheny’s liability for adverse power purchase commitments decreased as follows:

(In millions)	2010		2009		2008
Amortization of liability for adverse power purchase commitments	$	17.9	$	17.5	$	17.1

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 Income.

NOTE 21:  OTHER INCOME (EXPENSE), NET

Other income (expense), net, consisted of the following:

(In millions)	2010		2009		2008
Interest and dividend income	$	2.3	$	1.8	$	7.3
Equity component of AFUDC		6.3		5.0		3.7
Income from equity investments		4.7		0.1		1.8
Cash received from a former trading executive’s forfeited assets		0		0		1.6
Other		0		0.1		7.9
Total other income (expense), net	$	13.3	$	7.0	$	22.3

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NOTE 22:  GUARANTEES AND LETTERS OF CREDIT

In connection with certain sales, acquisitions and financings, and in the normal course of business, AE and its subsidiaries enter into various agreements that may include guarantees or require the issuance of letters of credit. AE has a $250 million revolving credit facility, any unutilized portion of which is available to AE for the issuance of letters of credit.

(In millions)	December 31, 2010				December 31, 2009
	Amounts Recorded on the Consolidated Balance Sheet		Total Guarantees and Letters of Credit		Amounts Recorded on the Consolidated Balance Sheet		Total Guarantees and Letters of Credit
Guarantees:
Purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services (a)	$	0	$	84.2	$	0	$	95.2
Loans and other financing-related matters		0		5.9		0		6.4
Lease agreement (a)		0		5.0		0		5.0
Other		0		0		0.2		0.2
Total Guarantees	$	0	$	95.1	$	0.2	$	106.8
Letters of Credit:
Under AE’s Revolving Facility (b)	$	0	$	3.1	$	0	$	3.2
Total Letters of Credit	$	0	$	3.1	$	0	$	3.2
Total Guarantees and Letters of Credit	$	0	$	98.2	$	0.2	$	110.0

(a) Amounts represent AE guarantees on behalf of its subsidiaries.

(b) These amounts were comprised of a letter of credit issued in connection with a contractual obligation of Allegheny Ventures.

NOTE 23:  VARIABLE INTEREST ENTITIES

GAAP requires the primary beneficiary of a Variable Interest Entity (“VIE”) to consolidate the entity and also requires majority and significant variable interest investors to provide certain disclosures. A VIE is an entity in which the equity investors do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support, or as a group, the holders of the equity investment at risk lack any one of the following characteristics: a) the power, through voting rights or similar rights, to direct the activities of an entity that most significantly impact the entity’s economic performance, b) the obligation to absorb the expected losses of the entity or c) the right to receive the expected residual returns of the entity.

Independent Power Producer (“IPP”) contracts.  Potomac Edison and West Penn each have a long-term electricity purchase contract with unrelated IPPs. Allegheny periodically requests from these IPPs the information necessary to determine whether these entities are VIEs and whether Allegheny is the primary beneficiary. Allegheny has been unable to obtain the requested information, which was determined by the IPPs to be proprietary.

Potomac Edison purchased power from an IPP in the amounts of $116.7 million, $96.4 million and $113.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. West Penn purchased power from an IPP in the amounts of $42.7 million, $42.5 million and $40.8 million for the years ended December 31, 2010,

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2009 and 2008, respectively. Neither Potomac Edison nor West Penn is subject to any risk of loss associated with the applicable potential VIE, because neither 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.

APS Constellation, LLC (“APS Constellation”).  Allegheny Ventures, Inc., a non-utility subsidiary of AE, formed a partnership in 1995 with an unregulated business of Constellation Energy in a joint venture energy services company named APS Constellation. The business purpose of APS Constellation is the marketing, development, and implementation of energy conservation projects. APS Constellation, working under an Engineer/Procure/Construct agreement as a subcontractor for Potomac Edison, completed multiple energy conservation projects for Potomac Edison’s government customers at Ft. Detrick, Maryland. The projects resulted in performance payments and other fees remitted to APS Constellation. APS Constellation securitized the future revenue streams from the projects through several financings and made a partnership distribution of the proceeds. Some of the project financings required Potomac Edison to provide ongoing guarantees. In 2005, the joint venture operating agreement was amended to limit Allegheny’s obligations and participation in APS Constellation. The accounts of APS Constellation are not included in Allegheny’s Consolidated Financial Statements because Allegheny does not have the power to direct activities that most significantly impact APS Constellation’s economic performance.

At December 31 2010, Allegheny’s maximum exposure to loss related to APS Constellation consisted of a $0.7 million equity investment in APS Constellation, a letter of credit guarantee of $3.1 million and recourse guarantees of $5.9 million. At December 31, 2009, Allegheny’s maximum exposure to loss related to APS Constellation consisted of a $0.7 million equity investment in APS Constellation, a letter of credit guarantee of $3.2 million and recourse guarantees of $6.4 million. These guarantees are not recorded on Allegheny’s Consolidated Balance Sheet.

PATH-WV.  As described in Note 1, “Business, Basis of Presentation and Significant Accounting Policies,” PATH-WV is owned equally by Allegheny and AEP. As described in Note 3, “Recently Adopted and Recently Issued Accounting Standards,” Allegheny deconsolidated PATH-WV from its financial statements effective January 1, 2010, and accounts for its investment in PATH-WV under the equity method. Allegheny and AEP provide certain services to PATH-WV and make capital contributions to PATH-WV as needed. At December 31, 2010, Allegheny’s consolidated balance sheet included Allegheny’s investment in PATH-WV on the equity method of accounting in the amount of $23.6 million. At December 31, 2009, Allegheny’s consolidated balance sheet included property, plant and equipment of PATH-WV in the amount of approximately $35.8 million, cash and cash equivalents of $3.4 million and noncontrolling interest related to AEP’s ownership of approximately $14.9 million. Allegheny’s consolidated statement of income for the year ended December 31, 2010 included other income of $3.5 million, representing Allegheny’s 50% equity in the pre-tax earnings of PATH-WV. Allegheny’s consolidated statement of income for year ended December 31, 2009 included revenues of $10.8 million, operating income of $4.4 million and net income attributable to noncontrolling interest of $1.3 million.

Allegheny expects to make capital contributions to PATH-WV to support its construction projects. Because of the nature of PATH-WV’s operations and its FERC-approved rate mechanism, Allegheny’s maximum exposure to loss consists of its advances to, and investment in, PATH-WV, which were $0.5 million and $23.6 million, respectively, at December 31, 2010.

Energy Insurance Services, Inc.  Allegheny has entered into an insurance arrangement with Energy Insurance Services, Inc. (“EIS”). EIS has multiple protected cells and writes policies for Allegheny in one segregated cell, referred to as Mutual Business Program No. 2 (the “Program”). Neither Allegheny nor its subsidiaries have an equity investment in EIS. The Program is governed by a Participation Agreement that limits claims paid on policies that are not reinsured to premium payments made by Allegheny, contributions to surplus

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and any investment returns on those premiums less expenses. The accounts of EIS are included in Allegheny’s Consolidated Financial Statements because Allegheny has determined it has a controlling financial interest in EIS. Insurance premiums for the Program were $8.7 million and $9.8 million for the years ended December 31, 2010 and 2009, respectively. At December 31, 2010, total assets were $19.6 million, consisting primarily of investments, and total liabilities were $14.8 million, consisting primarily of claim reserves. At December 31, 2009, total assets were $18.5 million, consisting primarily of investments, and total liabilities were $13.7 million, consisting primarily of claim reserves At December 31, 2010 and 2009, Allegheny’s maximum exposure to loss related to EIS consisted of a $4.8 million equity investment in EIS recorded on its Consolidated Balance Sheet.

NOTE 24:  ACQUISITION OF NONCONTROLLING INTEREST IN AE SUPPLY

On January 25, 2008, Allegheny and Merrill Lynch entered into a settlement agreement that resolved litigation between the two parties related to a dispute regarding Allegheny’s purchase of Merrill Lynch’s energy marketing and trading business in 2001. As a result of this settlement, Allegheny reversed its previously recorded accrued interest liability of $54.7 million through a credit to interest expense during the fourth quarter of 2007.

On March 31, 2008, in accordance with the settlement agreement, Allegheny made a cash payment to Merrill Lynch in the amount of $50 million, and Merrill Lynch conveyed to Allegheny its approximately 1.5% equity interest in AE Supply. Allegheny recorded the acquisition of Merrill Lynch’s noncontrolling interest in AE Supply using the purchase method of accounting. Under the purchase method of accounting, the purchase price was allocated to individual assets acquired and liabilities assumed based on the fair values of such assets and liabilities. The purchase accounting adjustments will be amortized against income over the estimated lives of the individual assets and liabilities, ranging from 3 years to 30 years. No goodwill was recorded. The effects of the purchase accounting adjustments are not expected to materially impact Allegheny’s financial results for any period. Allegheny ceased recording expense relating to the noncontrolling interest in AE Supply as of January 1, 2008.

NOTE 25:  COMMITMENTS AND CONTINGENCIES

Allegheny is involved in a number of significant legal proceedings. In certain cases, plaintiffs seek to recover large and sometimes unspecified damages, and some matters may be unresolved for several years. Allegheny cannot currently determine the outcome of the proceedings described below or the ultimate amount of potential losses. Management provides for estimated losses to the extent that information becomes available indicating that losses are probable and that the amounts are reasonably estimable. Additional losses may have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Environmental Matters and Litigation

The operations of Allegheny’s owned facilities, including its generation facilities, are subject to various federal, state and local laws, rules and regulations as to air and water quality, hazardous and solid waste disposal and other environmental matters, some of which may be uncertain. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities.

Global Climate Change.  The United States relies on coal-fired power plants for more than 45% of its energy. However, coal-fired power plants have come under scrutiny due to their emission of gases implicated in climate change, primarily carbon dioxide, or “CO₂.”

Allegheny produces approximately 95% of its electricity at coal-fired facilities and currently produces approximately 45 million tons of CO₂ annually through its energy production. While there are many unknowns

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concerning the final regulation of greenhouse gases in the United States, federal and/or state legislation and implementing regulations addressing climate change, including limits on emissions of CO₂, likely will be adopted some time in the future. Thus, CO₂ legislation and regulation, if not reasonably designed, could have a significant impact on Allegheny’s operations. To date Congress has not passed any CO₂ –specific law.

The U.S. Environmental Protection Agency (the “EPA’) is moving to regulate greenhouse gas emissions under the Clean Air Act of 1970 (the “Clean Air Act”). On December 7, 2009, the EPA announced its Greenhouse Gas Endangerment Finding, stating that greenhouse gas emissions from cars and light trucks, when mixed in the atmosphere, endanger public health. The finding provides the EPA with a basis on which to regulate greenhouse gas emissions from vehicle tailpipes under the provisions of the Clean Air Act. Once a pollutant is regulated under the Clean Air Act for one source category, the EPA has authority to apply similar regulations to other source categories. On April 1, 2010, the EPA and the Department of Transportation’s National Highway Traffic Safety Administration (“NHTSA”) announced a joint final rule that applies to passenger cars, light-duty trucks and medium-duty passenger vehicles, covering model years 2012 through 2016. Under the Clean Air Act, regulation of greenhouse gas emissions from vehicles also triggers requirements for new and modified stationary sources to control greenhouse gas emissions under the Prevention of Significant Deterioration (“PSD”) program. Regulation of the stationary sources will be implemented through the final version of the “tailoring rule” issued on June 3, 2010. The tailoring rule became effective on January 2, 2011. For six months, only new and modified sources already required to control emissions of other air pollutants will be required to control greenhouse gas emissions. Beginning July 1, 2011, new sources above 100,000 tons per year and modified existing sources with emissions increases above 75,000 tons per year (which may include Allegheny’s facilities, but only to the extent any modifications to those facilities triggers application of the rule) will be required to control emissions.

There is a gap between the current capabilities of technology and the desired reduction levels contemplated by past legislative proposals; no current commercial-scale technology exists to enable many of the reduction levels discussed in past national, regional and state proposals. Such technology may not become available within a timeframe consistent with the implementation of any future climate control initiatives or at all. To the extent that such technology does become available, Allegheny can provide no assurance that it will be suitable for installation at Allegheny’s generation facilities on a cost effective basis or at all. Based on estimates from a 2007 Department of Energy National Electric Technology Laboratory report and recently announced projects by other entities, it could cost in the range of $4,800 to $5,500 per kW to replace existing coal-based power generation with fossil fuel stations capable of capturing and sequestering CO₂ emissions. However, exact estimates are difficult because of the lack of distinctive rules and the current lack of deployable technology.

Regardless of the eventual mechanism for limiting CO₂ emissions, compliance will be a major and costly challenge for Allegheny, its customers and the region in which it operates. Most notable will be the potential impact on customer bills and disproportionate increases in energy cost in areas that have built their energy and industrial infrastructure over the past century based on coal-fired electric generation.

Because the regulatory/legislative process and applicable technology each is in its infancy, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures until the exact nature and requirements of any regulation are known and the capabilities of control or reduction technologies are more fully understood. Allegheny’s current strategy in response to climate change initiatives focuses on:

• maintaining an accurate CO₂ emissions database;

• improving the efficiency of its existing coal-burning generation facilities;

• following developing technologies for clean-coal energy and for CO₂ emission controls at coal-fired power plants, including carbon sequestration;

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• analyzing options for future energy investment (e.g., renewables, clean-coal, etc.); and

• improving demand-side efficiency programs, as evidenced by customer conservation outreach plans and Allegheny’s Watt Watchers initiatives.

Allegheny’s energy portfolio also includes approximately 1,180 MWs of renewable hydroelectric and pumped storage power generation. Allegheny obtained a permit to allow for a limited use of bio-mass (wood chips and saw dust) at one of its coal-fired power stations in West Virginia and currently has approval to use waste-tire derived fuel at another of its coal-based power stations in West Virginia.

Allegheny is participating in the dialogue that will shape the regulatory landscape surrounding CO₂ emissions. Additionally, Allegheny intends to pursue proven and cost-effective measures to manage its emissions while maintaining an affordable and reliable supply of electricity for its customers.

Clean Air Act Compliance and State Air Quality Initiatives.   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 other means. 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’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install control technologies on many of its generation facilities at significant cost. The proposed Clean Air Transport Rule (“CATR”) released by the EPA on July 6, 2010 may accelerate the need to install this equipment by phasing out a portion of the currently available allowances, limiting trading and accelerating federal emission reduction goals. The proposed CATR replaces certain portions of the Clean Air Interstate Rule (“CAIR”). In June 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR, which would have required reductions of SO₂ and NO_X emissions in two phases beginning in 2010 and 2015. In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect until replaced by a new EPA rule.

Following the February 2008 vacature of EPA’s 2005 Clean Air Mercury Rule (“CAMR”) by the U.S. Court of Appeals for the District of Columbia, the EPA announced plans to propose a new maximum achievable control technology rule for hazardous air pollutant emissions from electric utility steam generating units in March 2011. The EPA plans to finalize the new rule by November 2011. Allegheny is monitoring the EPA’s efforts to promulgate hazardous air pollutant rules that will include, but will not be limited to, mercury limits. To establish these standards, the EPA must identify the best performing 12% of sources in each source category and, to that end, issued an information request to members of the fossil fuel-fired generating industry requiring extensive stack emissions testing on selected generating units. Allegheny completed stack testing for eight of its generating units identified by EPA and submitted all results by September 2010. Depending on the final hazardous air pollution limits set by the EPA, Allegheny could incur significant costs for additional control equipment.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NO_X, requires mercury emissions and mandates that Maryland join the Regional Greenhouse Gas Initiative (“RGGI”) and participate in that coalition’s regional efforts to reduce CO₂ emissions. On April 20, 2007, Maryland’s governor signed on to RGGI, as a result of which Maryland became the 10th state to join the Northeast regional climate change and energy efficiency program. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NO_X, SO₂ and mercury, based on a PJM declaration that the station is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) passed alternate NO_X and SO₂ limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory

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exemption does not extend to R. Paul Smith’s CO₂ emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances.

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. Allegheny continues to evaluate and implement options for compliance. It completed the elimination of a partial bypass of Scrubbers at its Pleasants generation facility in December 2007 and the construction of Scrubbers at its Hatfield’s Ferry and Fort Martin generating facilities in 2009. Allegheny now has Scrubbers installed and operating on all ten of the units at its four supercritical generating facilities and at Mitchell Unit 3.

Allegheny’s NO_X compliance plan functions on a system-wide basis, similar to its SO₂ compliance plan. Pending finalization of the CATR, AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NO_X allowances, if needed, to supplement their compliance strategies. Allegheny currently has installed selective non-catalytic reduction equipment at its Fort Martin and Hatfield’s Ferry generating stations and selective catalytic reduction equipment at its Harrison and Pleasants generating stations, together with other NO_X controls at these supercritical generating facilities, as well as its other generating facilities.

On January 8, 2010, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Notice of Violation for opacity emissions at Allegheny’s Pleasants generating facility. Allegheny will be installing a wet reagent injection system in 2011 to control the opacity.

Clean Water Act Compliance.  In 2004, the EPA issued a final rule requiring all existing power plants with once-through cooling water systems withdrawing more than 50 million gallons of water per day to meet certain standards to reduce mortality of aquatic organisms pinned against the water intake screens or, in some cases, drawn through the cooling water system. The standards varied based on the type and size of the water bodies from which the plants draw their cooling water.

In January 2007, the Second Circuit Court of Appeals issued a decision on appeal that remanded a significant portion of the rule to the EPA. As a result, the EPA suspended the rule, except for a requirement, which existed prior to the EPA’s adoption of the 2004 rule, that permitting agencies use best professional judgment (“BPJ”) to determine the best technology available for minimizing adverse environmental impacts for existing facility cooling water intakes. Pending re-issuance of the 2004 rule by the EPA, permitting agencies thus will rely on BPJ determinations during permit renewal at existing facilities.

On April 1, 2009, the U.S. Supreme Court reversed the appeals court decision and upheld the EPA’s authority to use cost/benefit analysis. EPA plans to issue a proposed rule addressing the issues remanded by the Court in 2011 and to issue a final rule in 2012. Depending on the standards set by the EPA when it reissues this rule, Allegheny could incur significant costs for additional control equipment.

Monongahela River Water Quality.  In late 2008, the PA DEP imposed water quality criteria for certain effluents, including total dissolved solid (“TDS”) and sulfate concentrations in the Monongahela River, on new and modified sources, including the Scrubber project at the Hatfield’s Ferry generation facility. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the Scrubbers as designed. Preliminary studies indicate an initial capital investment of approximately $62 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council who seek to impose more stringent

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technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin on September 13, 2011. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.

In parallel rulemaking, the PA DEP recommended an end-of-pipe limit TDS rule, and the Pennsylvania Environmental Quality Board issued the final rule on August 21, 2010. Allegheny could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

On December 23, 2010, PA DEP submitted its Clean Water Act 303(d) list to EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. EPA is reviewing PA DEP’s recommendation. If the designation is approved, Pennsylvania will then need to develop a Total Maximum Daily Load (“TMDL”) limit for the river, a process that will take about five years. Based on the stringency of the TMDL, Allegheny Energy may incur significant costs for controls on its national pollution discharge elimination system, or “NPDES,” discharges to the Monongahela River from Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia. Allegheny appealed the PA DEP’s proposed 303(d) designation to the Pennsylvania Environmental Hearing Board in January 2011 on the basis that the PA DEP failed to follow its own methodologies for concluding the river segments are impaired.

In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the Scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for Monongahela to meet certain of the effluent limits that are effective immediately under the terms of the permit. Monongahela appealed the Fort Martin permit and the administrative order. The appeal includes a request to stay certain of the conditions of the permit and order while the appeal is pending. The request to stay has been granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. Monongahela moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require Monongahela to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. Monongahela intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

Solid Waste.  The EPA is reviewing its waste regulations relating to coal combustion residuals (“CCR”) partly in response to a Tennessee Valley Authority ash spill in Kingston, Tennessee in December 2008. CCR includes bottom ash, boiler slag, fly ash and Scrubber byproducts including gypsum. CCR has historically been designated and managed as a non-hazardous waste, and the EPA has twice determined that it is not appropriate to regulate it as a hazardous waste under the Resource Conservation and Recovery Act (“RCRA”). The EPA is reconsidering those earlier determinations and intends to issue new regulations for the management and disposal of CCR in 2011. The EPA has not yet reached a final decision on whether to regulate CCR as a hazardous or

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special waste (RCRA Title C) or as a non-hazardous waste (RCRA Title D) and on May 4, 2010 released a draft proposed rule which contained both options for public comment. Should the EPA elect to designate CCR as hazardous or special waste at any point in its generation, storage, transportation or disposal cycle, it could significantly increase Allegheny’s cost of managing CCR materials and could also drive additional monitoring and corrective action at legacy disposal sites. In addition to potential additional management costs for CCR disposal, Allegheny might expect to see a reduction in options for beneficial reuse of CCR in applications such as mine reclamation, cement manufacture and agriculture, further increasing costs, as such materials will then enter landfills rather than beneficial reuse. While EPA’s proposed rule appears to attempt to protect beneficial CCR reuse whatever the CCR designation, we are still reviewing the rule and assessing its effect on Allegheny in that regard. The proposed rule also provides options for the management and closure of wet CCR storage and disposal impoundments. Even if EPA elects the non-hazardous CCR option in a final rule, reducing Allegheny’s potential waste management exposure, closure of wet disposal impoundments could be a source of significant costs. Allegheny is assessing the draft proposal and working with various trade groups and associations to determine potential costs and effects under either CCR option.

Potential Impact of Recent EPA and Climate Change Initiatives.  Implementation of the EPA’s current proposals with regard to air quality, water quality and CCR, as described above, would, together with potential climate change legislation, require extensive and costly changes to the nation’s electric generation fleet, including the installation of new pollution controls, retirement of many existing generating facilities and construction of new generating capacity. Several industry and industry-related assessments, while varying in their estimates and assumptions, estimate that if implementation of these initiatives proceeds according to currently proposed schedules, the combined national cost through 2015 associated with required retrofitting of existing facilities and construction of new facilities could be hundreds of billions of dollars. Additionally, it is estimated that the cost of complying with these initiatives may not be economically justified for many individual facilities and would therefore result in the retirement of a significant portion of the nation’s existing coal-fired generation capacity. While specific estimates involve complex models incorporating many variables and assumptions that are subject to individual interpretation and are highly subject to change, it is clear that timely compliance would be challenging and require significant investment, both at the industry level and for Allegheny, which could be required to install a variety of additional pollution controls at a number of its generating facilities and could be compelled to retire certain of its subcritical facilities.

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/or 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 under the Clean Air Act, which can require the installation of additional air emission 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.

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 emission control technology.

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 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

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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. On August 12, 2010, the Court granted the motion to dismiss, and the lawsuit has been concluded.

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. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. On November 18, 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case, who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. On April 18, 2010, the District Court issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. The non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law on December 23, 2010, and Allegheny must make its related filings on or before February 28, 2011. The District Court will issue its rulings after those filings have been made.

In addition to this lawsuit, on September 21, 2007, Allegheny received a Notice of Violation (“NOV”) from the EPA alleging NSR and PSD violations under the federal Clean Air Act, as well as Pennsylvania and West Virginia state laws. The NOV, which was directed to AE, Monongahela and West Penn, alleges violations at the Hatfield’s Ferry and Armstrong generation facilities in Pennsylvania and the Fort Martin and Willow Island generation facilities in West Virginia. The projects identified in the NOV are essentially the same as the projects at issue for these four facilities in the May 20, 2004 Notice and the PA Enforcement Action.

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

Global Warming Class Action.  On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by Hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. On December 6, 2006, AE

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filed a motion to dismiss plaintiffs’ complaint on jurisdictional grounds and then joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. At a hearing on August 30, 2007, the Court granted the motion to dismiss that AE had joined and dismissed all of the plaintiffs’ claims against all defendants. Plaintiffs appealed that ruling to the United States Court of Appeals for the Fifth Circuit. On October 6, 2009, the assigned panel of the appellate court issued a written opinion that reversed the judgment entered by the District Court in favor of the defendants with respect to certain of the plaintiffs’ claims and remanded the case to the District Court for further proceedings. On November 25, 2009, AE and others filed a petition to have all of the judges of the Fifth Circuit rehear the issues addressed in the panel’s October 6, 2009 opinion. That petition was granted and oral argument was set for May 24, 2010. However, the parties were notified on April 30, 2010 that the Court was unable to empanel the necessary nine judges to hear the merits of the appeal due to recusals. The Court then entered an order on May 28, 2010, reinstating the ruling of the lower court that entered judgment in favor of the defendants and dismissing plaintiffs’ appeal. Plaintiffs filed a Petition for Mandamus with the United States Supreme Court on August 26, 2010, and Defendants subsequently filed their response to the petition. The Supreme Court denied Plaintiffs’ petition on or about January 20, 2011.

Other Litigation and Contingencies

Shareholder Actions.  In connection with AE’s proposed Merger with a subsidiary of FirstEnergy, purported AE shareholders filed in the first quarter of 2010 several separate putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the United States District Court for the Western District of Pennsylvania against AE, its directors and certain of its officers (the “AE Defendants”), FirstEnergy and Merger Sub. The lawsuits alleged, among other things, that the AE directors breached their fiduciary duties by approving the Merger Agreement and that AE, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The lawsuits also alleged that the Merger consideration was unfair, that certain other terms in the Merger Agreement were unfair, and that certain individual defendants were financially interested in the Merger. Among other remedies, the lawsuits sought to enjoin the Merger, or in the event that an injunction was not awarded, money damages. While AE believed the lawsuits were without merit and defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants agreed to a disclosure-based settlement of the lawsuits.

In exchange for AE’s agreement with plaintiffs’ counsel to include additional disclosure in the joint proxy statement/prospectus mailed to AE’s and FirstEnergy’s shareholders in connection with the Merger, and subject to court approval, plaintiffs’ counsel agreed to, among other things, the dismissal of all claims asserted in the lawsuits and a release of claims related to the Merger on behalf of the putative class of AE shareholders. On December 13, 2010, the Maryland Circuit Court for Baltimore City approved the settlement and signed an order dismissing all claims. The Maryland court’s approval of the settlement is final and no longer subject to appeal, and the actions filed in Pennsylvania state court and the United States District Court for the Western District of Pennsylvania were also dismissed.

PJM Calculation Error.  In March 2010, the Midwest ISO filed two complaints at FERC against PJM relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and the Midwest ISO since April 2005. The Midwest ISO claimed that this error resulted in PJM underpaying the Midwest ISO by approximately $130 million over the time period in question. Additionally, the Midwest ISO alleged that PJM did not properly trigger market-to-market settlements between PJM and the Midwest ISO during times when it was required to do so, which the Midwest ISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and Monongahela may be liable for a portion of any refunds ordered in this case. PJM, Allegheny and other PJM market participants filed responses to the Midwest ISO complaints and PJM filed a related complaint at FERC

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against the Midwest ISO claiming that the Midwest ISO improperly called for market-to-market settlements several times during the same time period covered by the two Midwest ISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues in the dispute. The Offer of Settlement calls for the withdrawal of all pending complaints with no payments being made by any parties. Initial comments on the Offer of Settlement were filed at FERC on January 24, 2011.

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, NPC and other parties filed petitions for review of FERC’s June 26, 2003 order with the United States Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 19, 2006, the Ninth Circuit issued an opinion remanding the case to FERC to determine, in accordance with the guidance set forth in the Ninth Circuit’s opinion, whether FERC utilized the appropriate standard of review in deciding various claims, including NPC’s complaint. On May 3, 2007, AE Supply and others filed a petition to appeal the Ninth Circuit’s ruling to the United States Supreme Court. On June 26, 2008, the United States Supreme Court issued an opinion that rejected the Ninth Circuit’s reasoning, with instructions that the case be remanded to FERC for amplification or clarification of its findings on two issues set forth in the opinion. The case was remanded to FERC, and FERC issued an order on December 18, 2008 that provides for a paper hearing on the two issues identified by the United States Supreme Court, with initial filings due within 90 days and reply submissions within 90 days thereafter. However, the order holds those deadlines in abeyance, contingent upon settlement discussions between the parties, and a subsequent order lifting that stay has not been entered. On December 1, 2010, the parties filed with FERC a Joint Offer of Settlement that fully resolves all claims against AE Supply in this matter in exchange for a payment made by Merrill Lynch. By order dated January 31, 2011, FERC approved the settlement and terminated the docket.

Claims by California Parties.  On October 5, 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (“CDWR”) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers have filed motions to dismiss the Lockyer case. On March 18, 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On April 19, 2010, the California parties filed exceptions to the judge’s ruling with FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from FERC on the exceptions.

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On June 2, 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their 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 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. Certain insurers have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. As of December 31, 2010, Allegheny is involved in three asbestos and/or environmental 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.), 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.) and Allegheny Energy, Inc., et al. v. Hartford Accident & Indemnity Company, Civil Action No. 10-CV-3142 WY (United States District Court, Eastern District of Pennsylvania). The parties are seeking a declaration of coverage under the policies for asbestos-related and environmental claims.

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. As of December 31, 2010, Allegheny’s total number of claims alleging exposure to asbestos was 886 in West Virginia, 11 in Pennsylvania and two in Illinois. Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

Ordinary Course of Business.  AE and its subsidiaries are from time to time involved in litigation and other legal disputes in the ordinary course of business.

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 $21.5 million, $18.6 million and $19.1 million were recorded as rent expense in 2010, 2009 and 2008, 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)	2011		2012		2013		2014		2015		Thereafter		Total		Less: amount representing interest and fees		Present value of net minimum capital lease payments
Capital Leases	$	14.8	$	11.7	$	10.3	$	8.4	$	6.5	$	7.9	$	59.6	$	14.4	$	45.2
Operating Leases	$	6.4	$	5.7	$	5.5	$	5.4	$	5.3	$	3.2	$	31.5	$	0	$	0

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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)	2010		2009
Equipment	$	45.0	$	40.6
Building		0.2		0.2
Property held under capital leases	$	45.2	$	40.8

PURPA

The Energy Policy Act of 2005 (the “Energy Policy Act”) 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 466 MWs of qualifying PURPA capacity. PURPA expense pursuant to these contracts in 2010, 2009 and 2008 was $223.0 million, $213.2 million and $222.2 million, respectively. The average cost of these power purchases was approximately 7.2, 6.8 and 6.3 cents per kilowatt-hour (“kWh”) in 2010, 2009 and 2008, respectively.

The table below reflects Allegheny’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2010. The commitments were calculated based on expected PURPA purchased power prices at December 31, 2010, without giving effect to possible price changes that could occur as a result of any future emissions regulation or legislation. Actual values can vary substantially depending upon future conditions.

(In millions)	kWhs		Amount
2011		3,564		257.0
2012		3,745		270.0
2013		3,735		275.3
2014		3,642		274.0
2015		3,735		286.6
Thereafter		42,992		3,410.4
Total		61,413	$	4,773.3

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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 expense was $1,192.6 million, $886.6 million and $1,080.9 million in 2010, 2009 and 2008, respectively, of which, $1,062.7 million, $783.8 million and $958.9 million, respectively, related to coal and lime expense. In 2009, Allegheny purchased approximately 25.9% of its coal from one vendor. Total estimated long-term fuel purchase and transportation commitments at December 31, 2010 were as follows:

(In millions)	Total
2011	$	1,069.1
2012		766.7
2013		715.1
2014		722.9
2015		392.0
Thereafter		1,509.7
Total	$	5,175.5

Other Purchase Obligations

AE has a Professional Service Agreement with Electronic Data Systems Corporation and EDS Information Services, LLC related to certain of Allegheny’s technology functions that will expire on December 31, 2012. Expected cash payments relating to the Professional Service Agreement are as follows:

(In millions)	2011		2012		Total
Other purchase obligations	$	23.8	$	22.9	$	46.7

NOTE 26:  QUARTERLY FINANCIAL INFORMATION (Unaudited)

(In millions, except per share amounts)	2010 Quarter Ended (a)									2009 Quarter Ended (a)
	March 31		June 30			September 30		December 31		March 31		June 30		September 30		December 31
Operating revenues	$	1,048.9	$	945.7		$	1,043.7	$	864.6	$	957.2	$	814.7	$	793.7	$	861.1
Gain on sale of Virginia distribution business	$	0	$	(45.1	)	$	0	$	0.5	$	0	$	0	$	0	$	0
Operating income	$	218.5	$	270.7		$	252.6	$	189.8	$	289.8	$	179.1	$	205.9	$	245.0
Net income	$	88.2	$	120.2		$	115.1	$	88.2	$	134.1	$	72.9	$	77.4	$	109.8
Net income attributable to Allegheny Energy, Inc.	$	88.2	$	120.2		$	115.1	$	88.2	$	133.9	$	72.6	$	77.0	$	109.3
Basic earnings per common share attributable to Allegheny Energy, Inc.	$	0.52	$	0.71		$	0.68	$	0.52	$	0.79	$	0.43	$	0.45	$	0.64
Diluted earnings per common share attributable to Allegheny Energy, Inc.	$	0.52	$	0.71		$	0.68	$	0.52	$	0.79	$	0.43	$	0.45	$	0.64

a) Quarterly amounts may not total to full-year results due to rounding.

179

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Allegheny Energy, Inc.

Greensburg, PA

We have audited the accompanying consolidated balance sheets of Allegheny Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedules listed in the Index at Item 8. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits.

We conducted our audits 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Allegheny Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 23, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Pittsburgh, PA

February 23, 2011

180

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Allegheny Energy, Inc.

Greensburg, PA

We have audited the internal control over financial reporting of Allegheny Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2010 of the Company and our report dated February 23, 2011 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.

/s/ Deloitte & Touche LLP

Pittsburgh, PA

February 23, 2011

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.     CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.  AE maintains disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the chief executive officer (“CEO”) and chief financial officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosures.

As of the end of the period covered by this report, our management, with the participation of our CEO and CFO, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13(a)-15(e) and 15(d)-15(e) of the Exchange Act. This evaluation included consideration of the various processes carried out under the direction of our disclosure committee. Based on this evaluation, our CEO and CFO concluded that AE’s disclosure controls and procedures were effective, at the reasonable assurance level, to ensure that material information relating to AE is (a) accumulated and made known to its management, including our CEO and CFO, to allow timely decisions regarding required disclosure and (b) recorded, processed, summarized and reported within the time periods specified in the 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.

Changes in Internal Control over Financial Reporting:  During the quarter ended December 31, 2010, there have been no changes in AE’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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, 2010. 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.”

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Based on this assessment, management concluded that, as of December 31, 2010, AE’s internal control over financial reporting is effective based on those criteria.

The effectiveness of AE’s internal control over financial reporting as of December 31, 2010 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which appears herein.

ITEM 9B.    OTHER INFORMATION

Not Applicable.

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S-1

SCHEDULE I

ALLEGHENY ENERGY, INC. (Parent Company)

Condensed Financial Statements

Statements of Income:

(In millions)	Year ended December 31,
	2010			2009			2008
Operating revenues	$	0		$	0		$	0
Operating expenses		5.6			5.8			6.1
Operating loss		(5.6	)		(5.8	)		(6.1	)
Equity in earnings of subsidiaries		417.3			402.8			399.1
Other income		4.5			0.8			2.9
Interest expense		4.6			2.2			3.1
Income before income taxes		411.6			395.6			392.8
Income tax expense (benefit)		(0.1	)		2.8			(2.6	)
Net income	$	411.7		$	392.8		$	395.4
Statements of Cash Flows:
(In millions)	Year ended December 31,
	2010			2009			2008
Net cash provided by operating activities	$	283.0		$	117.9		$	197.9
Cash flows from investing activities:
Investment in Allegheny Energy Money Pool, net		11.1			18.4			(40.2	)
Notes receivable from subsidiaries		79.5			(76.6	)		81.1
Contributions to subsidiaries		(266.5	)		(25.0	)		(123.8	)
Other		0			0			(50.0	)
Net cash used in investing activities		(175.9	)		(83.2	)		(132.9	)
Cash flows from financing activities:
Notes payable to subsidiaries		(50.0	)		50.0			0
Issuance of long term debt		127.7			120.0			0
Repayment of long term debt		(130.1	)		(120.0	)		0
Return of parent company contribution		25.9			0			6.0
Stock units and restricted shares		0.3			0.1			(7.4	)
Performance shares and stock options		19.7			14.6			12.2
Proceeds from stock option exercises		1.3			2.3			25.3
Cash dividends paid on common stock		(101.8	)		(101.7	)		(101.1	)
Other		(0.1	)		0			0
Net cash provided by (used in) financing activities		(107.1	)		(34.7	)		(65.0	)
Net increase (decrease) in cash and cash equivalents		0			0			0
Cash and cash equivalents at beginning of period		0			0			0
Cash and cash equivalents at end of period	$	0		$	0		$	0
Cash dividends received from subsidiaries	$	285.4		$	94.9		$	205.3

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Balance Sheets:

(In millions)	As of December 31,
	2010			2009
ASSETS
Investment in Allegheny Energy Money Pool	$	29.5		$	40.6
Other current assets		19.9			133.5
Investment in subsidiaries		3,549.7			3,149.6
Other noncurrent assets		2.5			2.1
Total assets	$	3,601.6		$	3,325.8
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	175.5		$	220.0
Deferred credits and other liabilities		(15.6	)		(7.4	)
Stockholders’ equity		3,441.7			3,113.2
Total liabilities and stockholders’ equity	$	3,601.6		$	3,325.8

See accompanying Note to Condensed Financial Statements.

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ALLEGHENY ENERGY, INC. (Parent Company)

NOTES TO CONDENSED FINANCIAL STATEMENTS

NOTE 1: BASIS OF PRESENTATION

Pursuant to rules and regulations of the Securities and Exchange Commission (SEC), the unconsolidated condensed financial statements of Allegheny Energy, Inc. (AE) 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 of America. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Form 10-K.

AE has accounted for the earnings of its subsidiaries under the equity method in these unconsolidated condensed financial statements. Stockholders’ equity reflects accumulated other comprehensive loss of $63.7 million and $89.9 million at December 31, 2010 and 2009, respectively.

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S-2

SCHEDULE II

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

For Years Ended December 31, 2010, 2009 and 2008

Description	Balance at Beginning of Period		Additions				Deductions (c)		Balance at End of Period
			Charged to Costs and Expenses (a)		Charged to Other Accounts (b)
Allowance for uncollectible accounts:
Year Ended December 31, 2010	$	14,040,670	$	16,799,428	$	4,046,591	$	19,163,003	$	15,723,686
Year Ended December 31, 2009	$	13,279,774	$	15,663,668	$	3,870,943	$	18,773,715	$	14,040,670
Year Ended December 31, 2008	$	14,252,059	$	16,770,586	$	3,744,337	$	21,487,208	$	13,279,774

(a) Amount charged to bad debt expense.

(b) Collection of accounts previously written off.

(c) Uncollectible accounts written off during the year.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Board of Directors

The members of AE’s Board of Directors, their ages, committee membership, principal occupations or other business experience, other directorships, certain other information, and Board and Committee meeting attendance appear below. All directors serve a one-year term that expires at AE’s Annual Meeting of Stockholders.

Name	Age		Director of AE since
H. Furlong Baldwin		79	2003
Eleanor Baum		71	1988
Paul J. Evanson		69	2003
Cyrus F. Freidheim, Jr.		75	2003
Julia L. Johnson		48	2003
Ted J. Kleisner		66	2001
Christopher D. Pappas		55	2008
Steven H. Rice		67	1986
Gunnar E. Sarsten		74	1992
Michael H. Sutton		70	2004

H. Furlong Baldwin is a member of the Management Compensation and Development and Executive Committees. He is the non-executive Chairman and director of the Board of The NASDAQ OMX Group; and a director of W.R. Grace & Co. and Platinum Underwriters Holdings, Ltd. Mr. Baldwin is also an honorary member (emeritus) and former Chairman of the Johns Hopkins Medicine Board of Trustees and a member (emeritus) of the Johns Hopkins University Board of Trustees. Previously, Mr. Baldwin was the Chairman, President and CEO of the Mercantile Bankshares Corp. and the Mercantile Safe Deposit & Trust Co.; a director of Constellation Energy Group, CSX Corp. and The St. Paul Companies, Inc.; and a Governor of the National Association of Securities Dealers, Inc. The Nominating and Governance Committee (the “Governance Committee”) and AE’s Board believe that Mr. Baldwin’s executive and board experience provide him with key skills in working with directors, understanding board processes and functions, and overseeing management. Further, the diversity of Mr. Baldwin’s experience – from The NASDAQ OMX Group to the Johns Hopkins boards – provides him with a collection of practices and strategies to assist AE’s Board in its decision-making and analyses regarding executive compensation and other matters. The Governance Committee and AE’s Board believe that Mr. Baldwin’s executive and Board experience qualifies him to serve as a member of the Board and the committees on which he serves. During 2010, Mr. Baldwin attended 15 of 15 meetings of AE’s Board and committees on which he served.

Eleanor Baum is a member of the Management Compensation and Development and Governance Committees. Dr. Baum was the Dean of the Albert Nerken School of Engineering of The Cooper Union for the Advancement of Science and Art (1987-2010). She is a director of Avnet, Inc. and a former director of United States Trust Company (1989-2007). Dr. Baum is also a trustee of Embry Riddle University, a member of the Board of the New York Building Congress and Institute of Electrical and Electronic Engineers Foundation, and a Fellow of the Institute of Electrical and Electronic Engineers. Previously, Dr. Baum was a Chair of the Engineering Workforce Commission; a Chair of the Board of Governors, New York Academy of Sciences; a President of Accreditation Board for Engineering and Technology; a President of the American Society for Engineering Education; and a former Trustee of the Webb Institute. The Governance Committee and AE’s Board believe that Dr. Baum’s experience in engineering, particularly electrical engineering, provides her with a unique and valuable perspective on the operations of an electric utility. Additionally, Dr. Baum’s extended service on AE’s Board has allowed her the opportunity to gain institutional knowledge about AE and its operations. The Governance Committee and AE’s Board believe that Dr. Baum’s insights, her Board experience and related knowledge qualifies her to serve as a member of the Board and the committees on which she serves. During 2010, Dr. Baum attended 18 of 18 meetings of AE’s Board and committees on which she served.

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Paul J. Evanson has been Chairman of AE’s Board, and President and Chief Executive Officer of AE since June 2003. He is the Chair of the Executive Committee. He has also been Chairman, Chief Executive Officer and a director AE’s principal subsidiaries since June 2003. He is an attorney and a former director of Lynch Interactive Corporation (1999-2006). Mr. Evanson is a director of the Edison Electric Institute, and a member of the Board of Trustees at St. John’s University and the Westmoreland Museum of American Art in Pennsylvania. Prior to joining AE in 2003, Mr. Evanson was President of Florida Power & Light Company, the principal subsidiary of FPL Group, Inc., and a director of FPL Group, Inc. He is also a former President of Lynch Interactive Corporation. The Governance Committee and AE’s Board believe that Mr. Evanson’s extensive executive and board experience in the electric industry provides him with great insight into the operations and management of AE. As President and Chief Executive Officer, Mr. Evanson also brings valuable insight to AE’s Board concerning the opportunities and challenges facing AE. The Governance Committee and AE’s Board believe that Mr. Evanson’s legal background, executive and board experience, demonstrated past performance and position at AE qualifies him to serve as Chairman of the Board and as a member of the Executive Committee. During 2010, Mr. Evanson attended 12 of 12 meetings of AE’s Board and the committee on which he served.

Cyrus F. Freidheim, Jr. is a member of the Governance and Executive Committees and currently serves as Presiding Director of AE’s Board. He is a former Chief Executive Officer of the Sun-Times Media Group Inc., a newspaper publisher (2006-2009). On March 31, 2009, the Sun-Times Media Group, Inc. and its domestic subsidiaries filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware. Mr. Freidheim is also a director of Virgin America, a privately-held domestic airline, and a former director of Hollinger International Inc. (2005-2009), HSBC Finance Corporation (1991-2008) and Sitel Corp. (2005-2007). Mr. Freidheim is also an honorary trustee of the Brookings Institution, a trustee of the Rush University Medical Center, and a life trustee of both the Chicago Council on Global Affairs and the Chicago Symphony Orchestra Association. Previously, Mr. Freidheim was a Chairman and Chief Executive Officer of Chiquita Brands International, Inc., a Vice Chairman of Booz Allen Hamilton, Inc., and a director of Household International, Inc., Security Capital Group and MicroAge, Inc., Elger Industries and five other non-public corporations. The Governance Committee and AE’s Board believe that Mr. Freidheim’s service as a chief executive officer at various companies provides him with experience in strategically responding to operational and financial challenges and overseeing complex organizations. Mr. Freidheim’s extensive board experience also provides him with knowledge of board processes and functions, and the oversight of management. The Governance Committee and AE’s Board believe that Mr. Freidheim’s executive and Board experience qualifies him to serve as a member of the Board and the committees on which he serves. During 2010, Mr. Freidheim attended 15 of 15 meetings of AE’s Board and committees on which he served.

Julia L. Johnson is a member of the Audit, and Governance Committees. She is an attorney and the President of NetCommunications, LLC, a strategic consulting firm (2000-Present). She is a director of American Water Works Company, Inc., MasTec, Inc. and NorthWestern Corporation. Ms. Johnson is also a member of the Department of Energy/National Association of Regulatory Utility Commissioners Energy Market Access Board. She is also the chairperson of both the Emerging Issues Policy Forum and the Florida African American Educational Alliance. Previously, Ms. Johnson was the Senior Vice President of Communications and Marketing, Milcom Technologies; the Chairman and Commissioner of the Florida Public Service Commission; and a Member of the Florida State Board of Education. The Governance Committee and AE’s Board believe that Ms. Johnson’s legal background and other experiences have provided her with key skills in implementing corporate strategies and evaluating the electric industry. As President of NetCommunications, LLC, Ms. Johnson develops strategies for achieving objectives through advocacy directed at critical decision makers, including the FERC, and Ms. Johnson brings that expertise to AE’s Board as well. Additionally, Ms. Johnson’s service as a chairman and commissioner of a public utility commission provides her with valuable insight into an electric utility. The Governance Committee and AE’s Board believe that Ms. Johnson’s background and Board experience qualifies her to serve as a member of the Board and the committees on which she serves. During 2010, Ms. Johnson attended 24 of 26 meetings of AE’s Board and committees on which she served.

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Ted J. Kleisner is the Chair of the Management Compensation and Development Committee and is a member of the Executive Committee. Mr. Kleisner is the President and Chief Executive Officer of Hershey Entertainment and Resorts Company, an entertainment and hospitality company (2007-Present). He is also a director of Hershey Entertainment and Resorts Company. Mr. Kleisner is a former President of CSX Hotels, Inc. (1987-2006) and a former President of The Greenbrier Resort and Club Management Company, a resort management company (1989-2006). Mr. Kleisner is a director of the Keystone Area Council Boy Scouts of America, WITF, Inc. (Central Pennsylvania Public Broadcasting) and Pennsylvania Chamber of Business & Industry. He is a member of the Executive Advisory Board for the Daniels College of Business at the University of Denver and of the Board of Trustees of the Culinary Institute of America. Previously, Mr. Kleisner was also a director of the following organizations: American Hotel and Lodging Association, Discover the Real West Virginia Foundation, Forward Southern West Virginia, Greenbrier Valley Economic Development Authority, Harrisburg Symphony Orchestra, West Virginia Chamber of Commerce, West Virginia Foundation for Independent Colleges and the West Virginia Roundtable. He is also a former member of the Board of Trustees for the Virginia Episcopal School. The Governance Committee and AE’s Board believe that Mr. Kleisner’s senior executive positions provide him with experience in developing and implementing corporate strategy and setting executive compensation and benefits. Further, Mr. Kleisner’s executive and board experience has prepared him to respond to financial and operational challenges, and his extended service on AE’s Board has allowed him the opportunity to gain institutional knowledge about AE and its operations. The Governance Committee and AE’s Board believe that Mr. Kleisner’s executive and Board experience qualifies him to serve as a member of the Board and the committees on which he serves. During 2010, Mr. Kleisner attended 15 of 15 meetings of AE’s Board and committees on which he served.

Christopher D. Pappas is a member of the Management Compensation and Development, and Governance Committees. Mr. Pappas is the President and Chief Executive Officer of Styron LLC, a producer of plastics, latex and rubber (2010-Present). He is a former President and Chief Executive Officer of NOVA Chemicals Corporation (“Nova Chemicals”), a commodity chemicals company (2009). Prior to this position, he was the President and Chief Operating Officer (2008-2009), Chief Operating Officer (2006-2008), and Senior Vice President & President, Styrenics (2000-2006) for Nova Chemicals. He was a member of the Board of Directors of Nova Chemicals (2007-2009) and INEOS NOVA (2005-2009). Mr. Pappas is also a trustee at Sewickley Academy. Previously, Mr. Pappas served in various leadership capacities at Dow Chemical and Dupont Dow Elastomers, and was a director of Methanex Corporation. The Governance Committee and AE’s Board believe that Mr. Pappas’s executive and board experience has equipped him with leadership skills and the knowledge of board processes and functions. Additionally, Mr. Pappas’s general corporate decision-making and senior executive experience with a commodity-based business provides a useful background for understanding AE’s operations. The Governance Committee and AE’s Board believe that Mr. Pappas’s executive and Board experience qualifies him to serve as a member of AE’s Board and the committee on which he serves. During 2010, Mr. Pappas attended 17 of 17 meetings of AE’s Board and the committee on which he served.

Steven H. Rice is a member of the Audit and Executive Committees. Mr. Rice is an attorney and is a senior advisor to private equity funds and national and regional banking institutions. He is a former Managing Director-New York of Gibraltar Private Bank & Trust (2006-2007) and a senior advisor to banking institutions (2004-2006). Mr. Rice serves as a director of the National Association of Corporate Directors-New York Chapter and is a member of the New York Bar. Previously, Mr. Rice was the former President, Chief Executive Officer and director of the Stamford (CT) Federal Savings Bank; a former President and director of the Seamen’s Bank for Savings in New York City and a former director of the Royal Insurance Group, Inc. in the United States. Also, he previously served in New York State government, first as Assistant Counsel to Governor Nelson A. Rockefeller and later as Deputy Superintendent and Special Counsel of the New York State Banking Department. The Governance Committee and AE’s Board believe that Mr. Rice’s banking, finance and legal experience provides him a unique and valuable perspective on AE’s operations. Additionally, Mr. Rice’s extensive service on AE’s Board has allowed him the opportunity to gain institutional knowledge about AE and its operations. The Governance Committee and AE’s Board believe that Mr. Rice’s financial, legal and Board experience qualifies him to serve as a member of the Board and the committees on which he serves. During 2010, Mr. Rice attended 23 of 23 meetings of AE’s Board and committees on which he served.

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Gunnar E. Sarsten is a member of the Audit, and Nominating and Governance Committees. He is a consulting professional engineer and a court recognized expert in matters of engineering, construction, and project management related to the execution of large industrial projects. He is a former Chairman and Chief Executive Officer of MK International (1994-1997). Mr. Sarsten is also registered as a Professional Engineer in various states, and maintains membership in numerous engineering societies including the American Nuclear Society and the American Society of Mechanical Engineers. Previously, Mr. Sarsten was the President and Chief Operating Officer of Morrison Knudsen Corporation; director of the Morrison Knudsen Corporation; President and Chief Executive Officer of United Engineers & Constructors International, Inc.; and Deputy Chairman of the Third District Federal Reserve Bank in Philadelphia. The Governance Committee and AE’s Board believe that Mr. Sarsten’s experience in engineering and project management brings a valuable perspective on AE’s operations to AE’s Board. Mr. Sarsten’s executive experience and service on the Third District Federal Reserve Bank also provides him with the skills to oversee management and review AE’s financial plans. Additionally, Mr. Sarsten’s extended service on AE’s Board has allowed him the opportunity to gain institutional knowledge about AE and its operations. The Governance Committee and AE’s Board believe that Mr. Sarsten’s engineering, project management and Board experience qualifies him for continued service as a member of the Board and the committees on which he serves. During 2010, Mr. Sarsten attended 26 of 26 meetings of AE’s Board and committees on which he served.

Michael H. Sutton is the Chair of the Audit Committee. Mr. Sutton is an independent consultant on accounting and auditing regulation. He is a director of Krispy Kreme Doughnuts, Inc. Previously, Mr. Sutton was a Chief Accountant for the SEC; senior partner and National Director of Accounting and Auditing Professional Practice for Deloitte & Touche LLP; and a director of American International Group, Inc. (2005-2009). The Governance Committee and AE’s Board believe that Mr. Sutton’s accounting and auditing expertise, with both the SEC and a national accounting firm provides valuable insight with respect to financial reporting. Further, Mr. Sutton’s service on the boards of large public corporations provides him with experience in board processes and function, the oversight of management and general corporate decision-making. The Governance Committee and AE’s Board believe that Mr. Sutton’s accounting, auditing and Board experience qualifies him as an audit committee financial expert and for continued service as a member of the Board and as a member of the Audit Committee. During 2010, Mr. Sutton attended 23 of 23 meetings of AE’s Board and the committee on which he served.

Executive Officers

The names of AE’s executive officers, their ages, the positions they hold, and their business experience during the past five years appear below. All of AE’s officers are elected annually.

Name	Age		Title
Paul J. Evanson		69	Chairman, President, Chief Executive Officer and Director
Curtis H. Davis		58	Chief Operating Officer, Generation
Rodney L. Dickens		53	Vice President
Edward Dudzinski		58	Vice President
David M. Feinberg		41	Vice President, General Counsel and Secretary
Eric S. Gleason		44	Vice President, Corporate Development and Quality
Kirk R. Oliver		53	Senior Vice President and Chief Financial Officer
William F. Wahl, III		51	Vice President, Controller and Chief Accounting Officer

Paul J. Evanson has been Chairman of the Board, President, Chief Executive Officer and a director of AE since June 2003. He is the Chair of the Executive Committee. 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.

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Curtis H. Davis has been Chief Operating Officer, Generation, of AE since March 2008. Prior to joining Allegheny, Mr. Davis served as Senior Vice President for Duke Energy Corporation’s non-regulated generation fleet from January 2003 to February 2008. Prior to that, he served in various senior operational positions at Duke Energy Corporation.

Rodney L. Dickens has been Vice President of AE since joining Allegheny in June 2009 and also serves as President of Allegheny’s T&D business. Prior to joining Allegheny, Mr. Dickens was most recently Vice President, Asset Management and Centralized Services with Public Service Electric & Gas Company, where he worked in various capacities for the preceding 32 years.

Edward Dudzinski has been Vice President, Human Resources and Security, of AE 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 E. I. DuPont de Nemours and Company (“DuPont”). Prior to that, he served in various other executive and leadership positions at DuPont.

David M. Feinberg has been Vice President, General Counsel and Secretary of AE since October 2006. Mr. Feinberg joined Allegheny in August 2004 and served as Deputy General Counsel until October 2006. Prior to joining Allegheny, Mr. Feinberg was a partner with the law firm of Jenner & Block LLP in its Chicago office.

Eric S. Gleason has been Vice President, Corporate Development and Quality, of AE since October 2009. Mr. Gleason joined Allegheny in August 2008 and served as Vice President, Corporate Development until October 2009. Prior to joining Allegheny, Mr. Gleason was employed by JPMorgan Chase & Co. since 2002, and served as Executive Director, Natural Resources Investment Banking from 2005 to 2008. Prior to that, he served as Vice President in the Investment Banking Division of Goldman, Sachs & Co.

Kirk R. Oliver has been Senior Vice President and Chief Financial Officer of AE since October 2008. Prior to joining Allegheny, Mr. Oliver was employed by Hunt Power since June 2006 and served as a senior executive from June 2007 to October 2008. Prior to that, Mr. Oliver spent eight years at TXU Corp, starting as Treasurer and then serving as Executive Vice President and Chief Financial Officer.

William F. Wahl, III has been Vice President, Controller and Chief Accounting Officer of AE since May 2007. He joined Allegheny in 2003 and served as Assistant Controller, Corporate Accounting from February 2005 to May 2007. From 2002 to 2003, Mr. Wahl was employed by PNC Financial Services Group, Inc. Prior to that, he was employed by Dominion Resources, Inc.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires AE’s directors, executive officers and persons who own more than 10% of a registered class of AE’s equity securities to file reports with the SEC concerning their ownership of AE’s common stock and other equity securities of AE. Based on a review of these filings, AE believes that all of its directors, executive officers and stockholders who are subject to Section 16(a) filed such reports with respect to AE’s common stock on a timely basis in 2010.

Code of Business Conduct and Ethics

Allegheny maintains a 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. The Code of Business Conduct and Ethics is available free of charge on Allegheny’s website at www.alleghenyenergy.com. Allegheny intends to satisfy the disclosure requirements of the SEC regarding amendments to, or waivers from, the Code of Conduct and Business Ethics by posting such information on the website listed above.

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Security Holders Nomination to Board

There have been no material changes to the procedures by which security holders may recommend nominees to AE’s Board. These procedures were described in AE’s definitive proxy statement filed with the SEC on March 19, 2010.

Audit Committee

AE’s Board has a standing Audit Committee whose members consist of Michael H. Sutton (Chair), Julia L. Johnson, Steven H. Rice and Gunnar E. Sarsten. The Audit Committee, which is composed solely of independent directors, is responsible for, among other things, assisting AE’s Board in its oversight of the integrity of AE’s financial statements, compliance with legal and regulatory requirements, the independent auditors’ qualifications and independence, and the performance of the independent auditors and AE’s internal audit function, including the appointment, compensation, retention, and oversight of any independent auditor. The Audit Committee operates pursuant to a written charter consistent with the applicable standards of the NYSE and the SEC. A more detailed discussion of the purposes, duties and powers of the Audit Committee is found in the charter of the Audit Committee, which is available on Allegheny’s website, www.alleghenyenergy.com, in the Corporate Governance section. The Board has determined that each member of the Audit Committee is independent under both Rule 10A-3 under the Exchange Act and the applicable independence standards of the NYSE. AE’s Board also has determined that Mr. Sutton is an audit committee financial expert in accordance with the applicable rules and regulations of the SEC. Each member of the Audit Committee is financially literate and one or more members of the Audit Committee possess accounting or related financial management expertise, as determined by AE’s Board in its business judgment. The Audit Committee met eleven times in 2010.

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Executive Summary

Following is a brief overview of the “Compensation Discussion and Analysis” that follows:

• AE provides its executive officers with the following types of compensation: salary, annual cash incentives, stock-based long-term incentives and other benefits;

• AE’s executive compensation program provides that a significant portion of AE’s executive officers’ overall compensation is performance-based and is linked directly to AE’s achievement of measurable performance objectives and stockholder returns;

• AE’s 2010 annual incentive plan performance was on average approximately 131% of target for AE’s Chief Executive Officer (the “CEO”), Chief Financial Officer (the “CFO”) and other most highly paid executive officers named in the Summary Compensation Table below (collectively with the CEO and CFO, the “Named Executive Officers”), reflecting performance directly attributable to meeting AE’s financial and operational objectives and excluding any changes based on individual performance;

• AE uses stock-based compensation as a means to align the interests of its executives with those of its stockholders;

• AE does not backdate or reprice stock options or time stock award grants based on the release of material non-public information;

• Upon approval of the Merger Agreement and the proposed Merger with FirstEnergy by AE’s stockholders on September 14, 2010, stock awards, that were granted before the execution of the Merger Agreement in February 2010, vested and became exercisable or payable;

• AE maintains a recoupment policy (often referred to as a “clawback policy”) regarding short-term incentives in the event of certain misconduct resulting in the need for a restatement of its financial results;

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• The Named Executive Officers must build and maintain a significant and continuing equity interest in AE;

• The compensation program’s combination of base salary, long- and short-term incentives, and use of stock compensation awards, along with AE’s stock ownership guidelines, encourage executives to take prudent but not excessive risks;

• AE provides its executive officers with a limited number of personal benefits;

• AE will provide certain payments and benefits to its executive officers under certain change in control and termination conditions;

• The Management Compensation and Development Committee of AE’s Board (the “Compensation Committee”) uses a compensation consultant to compare AE’s executive compensation to other companies in its peer group to ensure that the salary structure and total compensation continue to be competitive, yet not excessive.

Overall Philosophy and Objectives of AE’s Executive Compensation Program

AE’s executive officer compensation program is directed by the Compensation Committee of AE’s Board. The Compensation Committee determines compensation based upon AE’s overall compensation philosophy, which is comprised of the following key objectives and principles:

• Alignment with Stockholder Interests.  Create a strong link between executive compensation and total return to AE’s stockholders to support the creation of long-term stockholder value;

• Attract and Retain.  Attract and retain key executives critical to AE’s success. A highly qualified and skilled workforce can differentiate AE and provide a competitive advantage in the marketplace;

• Business and Individual Performance Accountability.  Offer performance-based compensation that is competitive with other companies that compete with AE for talented executives, with increased compensation for a higher level of performance and lower compensation for a lower level of performance; and

• Balanced Relationship.  Maintain a balanced relationship among the compensation levels of AE’s executive officers, taking into account the duties and responsibilities of each executive position.

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Overview and Mix of Compensation Elements

In General

AE believes that it is necessary to provide competitive compensation and benefit programs to motivate, retain and reward talented executives in achieving financial results that are aligned with AE’s stockholders’ best interests. To achieve the objectives of AE’s compensation program and to be competitive with its peer group, AE provides a compensation program that rewards both short-term and long-term performance in the form of both cash and non-cash compensation. The elements of AE’s total compensation for its executive officers are illustrated below:

In determining the 2010 compensation mix for the executive officers, the Board and Compensation Committee, as applicable, considered the compensation elements individually and as a whole in relation to various factors, including the compensation elements offered by AE’s peer group, existing employment arrangements, individual performance, level of responsibility, internal pay equity among the executive officers and the need to attract specific candidates. AE generally does not adhere to specific formulas or target specific ratios in determining the mix of compensation elements.

Mr. Evanson’s mix of the above compensation elements for 2010 was set when AE entered into his employment agreement in July 2009. The compensation mix for all other Named Executive Officers in the aggregate for 2010 was generally consistent with AE’s peer group.

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Performance-based Compensation

In addition to their fixed salaries, the executive officers receive annual incentive and long-term incentive compensation opportunities, both of which are performance-based. Compensation is considered performance-based when payment amounts vary based on achievement of AE goals or are subject to stock price changes. As a result, a high percentage of AE’s executive officers’ compensation is in the form of variable incentive compensation and, therefore, is “at-risk.” AE’s executive compensation program is also designed so that as the level of an executive officer’s responsibility increases, the amount of at-risk compensation also generally increases. The following pie charts illustrate the compensation mix for the CEO and all other Named Executive Officers in 2010.

2010 CEO Compensation Mix (At Target)	2010 All Other Named Executive Officers (Average At Target)
At Risk Compensation: 89%	At Risk Compensation: 65.5%

The pie charts above show the percentages of compensation relating to 2010 salary and target annual and long-term incentive compensation. The at-risk compensation includes the target annual and long-term stock incentives granted in 2010.

Compensation Elements for Named Executive Officers

The following discusses each of the respective compensation elements as applied to the Named Executive Officers.

Base Salary

Base salaries are typically reviewed annually and adjusted to take into account individual performance, promotions, level of responsibility and competitive compensation levels. In considering base salaries, AE gives most weight to the peer group data discussed below and the performance of each executive officer. Also taken into consideration are AE’s financial results and condition, and operating performance, including such factors as safety and customer satisfaction.

Analysis

Mr. Evanson received a base salary increase in June 2010 pursuant to his employment agreement. The other Named Executive Officers received merit increases in April 2010. In 2009, no changes were made to the salaries of the Named Executive Officers.

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The goal is to have base salaries that are generally consistent with the median of AE’s peer group. Mr. Evanson’s base salary is slightly higher than the median of AE’s peer group.

Annual Incentives

Under AE’s Annual Incentive Plan (the “Annual Plan”), AE provides award opportunities as an incentive to achieve AE objectives. At the beginning of each year, the independent directors of the Board and Compensation Committee, as applicable, establish (1) financial and operational objectives and (2) weightings and targets for each objective. After the end of the year, the independent directors of the Board and Compensation Committee, as applicable, (3) measure performance against predetermined targets. These three steps are described below. For additional information on how the objectives are established and measured, see “Annual Incentives –Analysis” section below.

Step 1 —Establishing Financial and Operational Objectives.

In February 2010, AE’s financial and operational objectives were set. These objectives included “Corporate Objectives” representing company-wide goals and “Key Performance Factors” reflecting measurable corporate and business unit goals. The Key Performance Factors can differ for each executive because they are based on specific (business unit) areas of responsibility.

Step 2 —Establishing Weightings and Targets for Objectives.

After the Corporate Objectives and Key Performance Factors are set, AE establishes the weightings and targets for each objective. Table 1 below describes each of the Corporate Objectives and Key Performance Factors for 2010 and their respective weightings. The weightings represent the percentage of the Corporate Objectives and Key Performance allocated to each of the objectives.

Table 1—2010 Financial and Operational Objectives and Weightings ¹

	Corporate		Generation
Corporate Objectives/Weighting
Maintain schedule for TrAIL transmission project to meet the June 2011 in-service date.		25%		—
Obtain regulatory approval and complete sale of AE’s Virginia distribution business.		25%		—
Maintain continuity of business operations, including the retention of key employees.		25%		—
Maintain schedule to close Merger transaction.		25%		—
Total		100%		—
Key Performance Factors/Weighting
Adjusted net income 2		25%		—
Power station availability 3		25%		25%
Operation & Maintenance (“O&M”) expense 4		25%		25%
Customer service unavailability 5		25%		—
Adjusted earnings before income taxes (EBIT) 6		—		25%
Occupation Safety & Health Administration (“OSHA”) recordable incident rate 7		—		25%
Total		100%		100%

⁽¹⁾ Generation refers to AE’s power generation and marketing operations, including certain regulated generation. Allegheny Power refers to a portion of our business that operates our electric public utility systems. The Allegheny Power Key Performance Factor related to customer service unavailability is included in the overall Corporate Key Performance Factors; however, the remaining Allegheny Power Key Performance Factors are not provided because they do not apply to the Named Executive Officers.

⁽²⁾ Adjusted net income means the consolidated net income of AE and its subsidiaries, as determined in accordance with GAAP, adjusted to exclude the impact of changes in accounting principles, extraordinary items, non-recurring charges or gains, unrealized gains or losses relating to FTRS and derivative hedge activities that do not receive hedge accounting treatment, discontinued operations, regulatory and/or legislative changes, labor union disruptions and acts of God such as hurricanes and appropriate adjustments to reflect AE’s core results and underlying trends.

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³ Power station availability is the percentage of time that our super-critical power plants were available to generate power during 2010. The super-critical power plants include approximately 80% of the capacity of our coal-fired power plants.

⁴ This O&M expense goal includes the expenses of non-fuel operations and maintenance, including general and administration expenses. For Corporate, this excludes incremental merger-related expenses and certain expenses that are recovered in rates on a formulaic basis. For Generation, only its expenses were taken into account.

⁵ The customer service unavailability goal is the number of minutes the average customer was without power during 2010, excluding major events, as defined by state reliability reporting requirements.

⁶ The EBIT goal is adjusted earnings before interest and taxes. For Generation, only its adjusted EBIT was taken into account.

⁷ The rate includes Generation’s incidents recordable under regulations of OSHA for 2010.

Table 2 below provides information regarding the overall individual weighting applied to the 2010 Corporate Objectives and Key Performance Factors for each Named Executive Officer. The weighting can differ for each executive because it is based on specific areas of responsibility.

Table 2—Weighting Applied to 2010 Objectives for Each Executive Officer

Named Executive Officer	Corporate Objectives			Key Performance Factors
					Corporate		Generation
All Named Executive Officers (except Mr. Davis)		50	%		50	%	—
Curtis H. Davis		20	%		20	%	60	%

In February 2010, the Board also set the targets for each Key Performance Factor as illustrated in Table 3 below.

In addition to the Corporate Objectives and Key Performance Factors, to satisfy the requirements for deductibility under Section 162(m) of the Internal Revenue Code, as amended (the “Code”), the Board and Compensation Committee set a performance threshold for 2010 of $120 million of adjusted net income. No annual incentive award would have been paid if this threshold was not achieved in 2010, regardless of the achievement of any other objectives. This adjusted net income threshold was met for 2010.

Step 3 —Measuring Performance Against Predetermined Targets.

In determining the actual award for each Named Executive Officer, at its February 2011 meeting, the Compensation Committee first assessed the actual results for each objective and assigned a level of achievement from zero to 200%. The Compensation Committee or the independent directors have discretion in determining the level of achievement of each Corporate Objective between zero and 200%. For any Key Performance Factors that are achieved, that factor typically is assessed at 100%. The Compensation Committee or the independent directors have discretion in determining the level of achievement for each Key Performance Factor between zero and 100% if the target is not achieved and between 100% and 200% if the target is exceeded.

In assessing performance against the objectives, the Board or Compensation Committee, as applicable, considered actual results against the specific goals, the expected difficulty of achieving the objective, and whether any significant unforeseen obstacles or favorable circumstances altered the expected difficulty of achieving the objective. The actual results for each Corporate Objective and Key Performance Factor are shown below.

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Table 3—2010 Financial and Operational Objectives Target and Actual Results

Corporate Objectives/Actual Results
	Actual
Maintain schedule for TrAIL transmission project to meet the June 2011 in-service date.		Achieved
Obtain regulatory approval and complete sale of AE’s Virginia distribution business.		Achieved
Maintain continuity of business operations, including the retention of key employees.		Achieved
Maintain schedule to close Merger transaction.		Achieved

Key Performance Factors/Target and Actual Results

	Corporate						Generation
	Target			Actual			Target			Actual
Adjusted net income (millions)	$	384.4		$	430.6			—			—
Power station availability		86.8	%		83.1	%		86.8	%		83.1	%
O&M expense (millions)	$	666.8		$	651.6		$	262.6		$	252.2
Customer service unavailability (minutes)		195			184			—			—
Adjusted earnings before income taxes (EBIT) (millions)		—			—		$	508.3		$	548.3
OSHA recordable incident rate		—			—			.75			.96

The level of achievement for each Corporate Objective and Key Performance Factor was multiplied by the applicable weighting in Table 1 to determine the result for each objective. The result for all objectives was then multiplied by the individual weightings in Table 2. The preliminary annual incentive award was then determined by multiplying this percentage by the target award shown in Table 4 below. The process used to determine the preliminary annual incentive award is generally illustrated below.

Level of Achievement for all Applicable
Objectives in Table 1 (as a percentage from 0-200%) × Individual Weighting
for each Executive
(Table 2) × Target
Award ($)
(Table
4) = Preliminary
Annual Incentive
Award

The Compensation Committee has the discretion to increase or decrease the preliminary annual incentive awards. When determining the actual awards for each Named Executive Officer, the Compensation Committee considered individual performance, including contributions to achieving the pre-established 2010 objectives described above and performance that was not specifically measured through the objectives. Adjustments for 2010 are discussed further below.

Analysis

The 2010 annual incentive awards for the Named Executive Officers are set forth below in Table 4. The annual incentive awards are also shown in the Summary Compensation Table below under the column headed “Non-Equity Incentive Plan Compensation” to the extent directly attributable to meeting the performance objectives, and in the column headed “Bonus” to the extent awards were increased based on individual performance, including performance not specifically measured through the objectives under the Annual Plan.

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Table 4—2010 Annual Incentive Target and Awards

Named Executive Officer	2010 Target Award ($)		Target Award as a Percentage of Salary			2010 Actual Award ($)		2010 Actual Award as a Percentage of Target
Paul J. Evanson		1,530,000		125	%	$	2,290,000		149.7	%
Kirk R. Oliver		393,750		75	%	$	348,000		88.4	%
David M. Feinberg		203,695		50	%	$	379,000		186.1	%
Curtis H. Davis		203,695		50	%	$	324,000		159.1	%
Eric S. Gleason		203,695		50	%	$	299,000		146.8	%

The 2010 target award of 125% for Mr. Evanson was pursuant to his employment agreement. For 2010, the target award for all other Named Executive Officers was comparable to AE’s peer group and ranged from 50% to 75% of base salary. The Named Executive Officers could earn from zero to 200% of their target award. In setting the target award percentages, the Compensation Committee considers the compensation targets of the peer group, the executive officer’s existing employment arrangements, level of responsibility, internal pay equity between the executive officers and the need to attract and retain specific candidates.

As a general principle, the Compensation Committee seeks to set performance targets that are challenging yet achievable: that is, they should be set at levels that represent excellent performance, superior to the results of typical companies in the utility industry. The Compensation Committee generally tries to set targets in the top quartile of relevant competitive performance, based on reviews of publicly-available information, benchmarks provided by consultants and practices in the electric industry. In setting targets, the Compensation Committee also considers AE’s past performance.

The Corporate Objectives were selected because they represent significant milestones tied to supporting future growth strategies and increasing the total return to stockholders. The Key Performance Factors were selected because they involve key financial and operational objectives that are integral to measuring the performance of AE. The weighting between the Corporate Objectives and the Key Performance Factors for each Named Executive Officer is based primarily on the impact that the Named Executive Officer is expected to have on determining the results.

In February 2011, the Compensation Committee determined the level of achievement with respect to the Corporate Objectives and Key Performance Factors and calculated the preliminary annual incentive awards based on AE’s achievement of such objectives as described in Step 3 above. Lastly, in determining the final 2010 annual incentive awards, the Board or the Compensation Committee, as applicable, evaluated each Named Executive Officer’s individual performance. As shown in Table 4 above and in the Summary Compensation Table below, the awards for Messrs. Davis, Evanson, Feinberg, Gleason and Oliver were adjusted based on their individual performance, particularly with respect to specific business matters. There were no other material changes to the preliminary annual incentive awards.

Long-Term Incentive Awards

Overview

Long-term incentive awards are made available to executives and key management employees who can significantly affect the long-term success of AE. AE believes that long-term incentive compensation is an important component of its program, because it has the effect of attracting and retaining talented executives, aligning executives’ financial interests with the interests of stockholders and rewarding the achievement of its long-term strategic goals. To permit flexibility, AE’s Long-Term Incentive Plan (the “Long-Term Plan”) provides for different forms of stock awards including performance shares, stock options and restricted stock.

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Upon approval of the Merger Agreement and the Merger by AE’s stockholders on September 14, 2010, stock awards outstanding at that time that were granted before the execution of the Merger Agreement with FirstEnergy in February 2010 vested and became exercisable or payable at target.

Performance Shares

In 2010, AE granted performance shares to the Named Executive Officers. The shares are linked to the average three-year corporate performance under AE’s annual incentive plan. The corporate performance is equal to the average of the actual results of the Corporate Objectives and Corporate Key Performance Factors. The percent of target award earned can vary from zero to 200%, depending on AE’s performance.

The performance criteria used to determine the awards will be the same used for the 2010 through 2012 Corporate Objectives and Corporate Key Performance Factors. The 2010 Corporate Objectives and 2010 Corporate Key Performance Factors are described above under “Compensation Elements for Named Executive Officers—Annual Incentives.” The 2011 Corporate Objectives relate to electric transmission projects and regulatory issues. The 2011 Corporate Key Performance Factors are adjusted net income, power station availability, O&M expense and customer service unavailability. The Corporate Objectives and Corporate Key Performance Factors for 2012 have not yet been established.

In addition, for the performance shares linked to the Annual Plan, to satisfy the requirements for deductibility under Section 162(m) of the Code, the independent directors of the Board set a performance formula for any 2010 grants. Accordingly, the aggregate value of all awards earned cannot exceed 3% of AE’s three-year cumulative total adjusted earnings before interest, taxes, depreciation, and amortization for 2010 through 2012, regardless of the level of achievement of the Corporate Objectives and Corporate Key Performance Factors.

Performance shares align well with stockholders’ interests because they provide incentive for executives to manage AE in the long-term interests of AE and its stockholders and encourage executives to stay with AE. Performance shares also provide an opportunity for employees to obtain a stock ownership stake in AE.

If the proposed Merger with FirstEnergy (or any other change in control) is consummated, the payment of any performance shares will be pursuant to the applicable agreement. The agreements generally provide that the shares are payable on the earlier of an executive’s involuntary termination from AE or FirstEnergy or the end of the award period and that the performance metrics will be deemed met at the target level for the year in which the change in control occurs and each subsequent year.

Analysis

The 2010 target grant award of $8.4 million for Mr. Evanson was pursuant to his employment agreement. The actual value realized from this grant award may vary based on the performance of AE over a three-year period. The 2010 target award for all other Named Executive Officers was comparable to AE’s peer group and ranged from 130% to 150% of base salary. In setting the target award percentages, the Compensation Committee considered the compensation targets of the peer group, the executive officer’s existing employment arrangements, level of responsibility, internal pay equity between the executive officers and the need to attract and retain specific candidates.

For the 2010 performance share grants, the performance period runs through December 31, 2012. Accordingly, the three-year performance results will be determined and any performance shares will vest on December 31, 2012. The ultimate value of the performance shares, which vest at the end of the 3-year performance period, will depend on continued progress in AE’s business performance and stock price when the shares are received.

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Prior to 2010, AE granted stock compensation to its executive officers in the form of stock options and performance shares. With respect to performance shares, in 2009, approximately 50% of the performance shares were linked to the average three-year corporate performance under AE’s annual incentive plan and the remaining 50% were linked to the three-year total stockholder return as compared to a peer index of companies. The long-term incentive program was revised in 2010 to grant only performance shares that were tied to AE’s annual incentive plan. This change was primarily made to encourage each participant’s focus on AE’s business fundamentals during the pendency of the proposed Merger with FirstEnergy and in recognition of the link between AE’s and FirstEnergy’s stock prices during that time period. This change was also made for retentive purposes.

AE believes that it is important to deliver a significant portion of compensation in the form of shares of stock (as compared to cash). The grant date fair value of the 2010 long-term incentive awards accounted for approximately 75% of total direct compensation for AE’s CEO and approximately 46% of total direct compensation, on average, for all other Named Executive Officers. This is generally consistent with AE’s peer group, although the CEO received proportionally more of his total compensation in long-term incentives as compared to AE’s peer group.

Other Benefits

As part of AE’s overall compensation package, AE offers benefits to all of its employees. These benefits are comparable to those typically offered by companies of similar size, and include medical and disability benefits, life insurance, tax-qualified retirement benefits, and matching contributions to a tax-qualified savings plan. These benefits are generally available to the Named Executive Officers on the same basis as for other employees. The limited number of additional benefits that AE provides to the Named Executive Officers is discussed below. AE reports the compensation associated with these programs as required in the appropriate column of the Summary Compensation Table below.

The Compensation Committee regularly reviews the additional benefits provided by AE to ensure that they are efficient and an effective use of AE’s resources. The Compensation Committee decided to provide these benefits because they are generally consistent in form and amount to those offered to executives at similar levels at companies with whom AE competes for talented executives and because these benefits advance AE’s business objectives.

Supplemental Executive Retirement Plan

AE offers a SERP to the Named Executive Officers and other senior executives. The amount of compensation that can be taken into account under AE’s tax-qualified retirement plan (the “Retirement Plan”) was limited under the Code to $245,000 for 2010, and the Code also places limits on the total amount of benefits that can be provided under the Retirement Plan. The Retirement Plan benefits provided to the Named Executive Officers generally constitute a smaller percentage of final pay than is typically the case for other AE employees. The SERP provides a payment to restore benefits to the level at which they otherwise would have been if it were not for these compensation and benefit limits established by federal tax law.

All Named Executive Officers, except Mr. Evanson, are participants in the SERP. In lieu of benefits under the SERP and pursuant to his employment agreement, Mr. Evanson is entitled to a lump sum cash payment of $66,667 for each month he is employed by AE, which will be paid to him upon the termination of his employment.

Under the SERP, each participating employee will receive a supplemental retirement benefit equal to their 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 participating employee retires prior to his or her 60^th birthday. Therefore, an

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employee’s maximum benefits under the SERP are 60% of average compensation. Average compensation under the SERP is defined as 12 times an employee’s average monthly compensation, plus any award paid under the Annual Plan 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 during the employee’s employment.

Except as described below, 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 AE and has reached his or her 55^th birthday. AE approved accelerated vesting under the SERP for Mr. Davis following five years of service. By offering this additional benefit, AE was able to attract him by making up for his loss of certain pension benefits resulting from leaving his prior employment. In addition, some of the Named Executive Officers would be vested in the SERP and credited additional years of service under change in control or termination circumstances, as further described in the “Potential Payments Upon Termination or Change in Control” section below.

The change in the pension value for the Named Executive Officers in 2010 under the Retirement Plan, SERP, and in the case of Mr. Evanson, his employment agreement, is shown below in the Summary Compensation Table under the “Change in Pension Value and Nonqualified Deferred Compensation Earnings” column. The accumulated pension benefits for the Named Executive Officers under the Retirement Plan, SERP, and in the case of Mr. Evanson, his employment agreement, are shown in the Pension Benefits table below.

The Compensation Committee believes that these plans are an important part of the compensation program for the Named Executive Officers. These plans are key to the recruitment of talented executives in the competitive market, as companies in AE’s peer group typically offer their executives these types of supplemental plans. These plans serve a critically important role in the retention of AE’s senior executives, as benefits from these plans increase for each year that the executives remain employed by AE. The plans are designed to encourage AE’s most experienced executives to remain employed by AE and continue their work on behalf of AE.

Personal Benefits

AE provides a limited number of benefits to the Named Executive Officers that generally help its executives conduct AE business more effectively but may also benefit the executives personally as well. AE reports the incremental cost of these personal benefits as required in the “All Other Compensation” column of the 2010 Summary Compensation Table below. As reported, these personal benefits make up a small percentage of total compensation (approximately 2.1% on average) for the Named Executive Officers.

These personal benefits generally are provided to the Named Executive Officers because they advance AE’s business objectives and are available at many of AE’s peer group companies. The cost or value of these personal benefits are imputed to the Named Executive Officer as income to the extent required by applicable tax law, and the officer is responsible for satisfying such taxes. These personal benefits for some of the Named Executive Officers included annual physical examinations and the reimbursement of certain relocation expenses as further described below. In addition, the CEO and his immediate family members may use AE’s aircraft for personal travel on a limited basis, and the vast majority of such use has been for commuting purposes by the CEO himself. This arrangement was a key driver in AE’s ability to hire its CEO in 2003, and its continuation has been a key driver in AE being able to retain his services. In addition, the other Named Executive Officers and their immediate family members may use the aircraft for personal travel on a limited basis, with the approval of the CEO. On certain occasions, an executive officer’s spouse or other immediate family member has accompanied the executive on flights if seating is available on the aircraft, and typically there is no additional incremental cost to AE in this circumstance. AE’s policy with respect to personal use of the aircraft requires the CEO to lease the aircraft from AE for any personal use in excess of $325,000 and to pay the incremental costs of such personal flights, up to the maximum established under Federal Aviation Administration rules. The Compensation Committee believes, with respect to travel-related expenses, that enhancing the work efficiency of the executive officer during otherwise personal travel benefits AE.

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AE typically provides relocation benefits to newly hired employees, including newly hired executive officers, when their primary residence changes a substantial distance from their previous employment. AE provides relocation assistance that includes travel costs, costs associated with the purchase and sale of a home, temporary living expenses and the taxes on these amounts. AE’s executive relocation program, which was originally established in 2005, is market competitive and necessary to obtain high quality candidates for such assignments.

Termination or Change in Control Payments

AE maintains severance plans that provide for a cash payment to most of its employees, including the executive officers, if their employment is terminated under certain conditions. AE also offers the Named Executive Officers a competitive change in control plan or arrangement that provides for specified benefits. In addition, under the Long-Term Plan, all participants, including the Named Executive Officers, are entitled to receive any outstanding and unvested stock grants under certain conditions. For more information regarding the plans or arrangements discussed in this section, along with the potential payments under some hypothetical situations, see the “Potential Payments Upon Termination or Change in Control” section below.

For the Named Executive Officers to be eligible for any benefits under the severance and change in control plans or arrangements, they are subject to additional restrictions not common to other AE employees, including a non-competition obligation for one year and a non-solicitation obligation for two years following any termination of employment.

For Mr. Evanson, the non-change in control termination conditions involving payments include termination due to death or disability and retirement. For all Named Executive Officers, the non-change in control termination conditions involving payments include termination without cause or for good reason. These provisions are generally designed to attract and retain executive officers by making up for the potential loss if the executives are terminated. AE believes that these arrangements are important recruitment and retention devices, as most companies with which it competes for talented executives have similar protections in place for their executive officers.

AE also believes that competitive change in control arrangements for its executive officers are necessary to retain senior leadership and maintain management’s objectivity where AE becomes engaged in a change in control situation. The occurrence, or potential occurrence, of a change in control transaction can often create uncertainty regarding the continued employment of executive officers. This uncertainty results from the fact that many change in control transactions result in significant organizational changes, particularly at the executive officer level. If a change in control transaction occurs, an executive officer would receive certain benefits under AE’s change in control plan or employment agreement, as applicable, such as cash payments and certain benefits. The payment of such benefits is triggered only if a Named Executive Officer leaves employment under certain qualifying circumstances (commonly referred to as a “double trigger”). Also, AE has not included excise tax gross-up payment provisions in any new change in control agreement or arrangement with its officers entered into after May 5, 2009.

Deferred Compensation

Under AE’s Nonqualified Deferred Compensation Plan, executive officers can elect to defer between zero and 100% of their Annual Plan payout. The deferred compensation plan is intended to provide a long-term savings opportunity on a tax-efficient basis. None of the Named Executive Officers has any deferred compensation.

Role of Compensation Committee in the Compensation Process

The Compensation Committee oversees AE’s compensation programs and policies relating to its executive officers. The Compensation Committee also administers incentive compensation plans, evaluates the CEO’s

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performance and reviews executive management succession planning and development. The Compensation Committee submits its recommendations regarding compensation, employment arrangements, and any severance agreements and termination payments for the CEO and the CFO to the independent directors of the Board for approval. The Compensation Committee approves the compensation, and any employment arrangements, severance agreements and termination payments for other executive officers. As described below, when making compensation decisions, the Compensation Committee often considers input from its compensation consultant and, as applicable, the CEO and certain other executive officers and human resources personnel.

Role of Consultants

For executive officer compensation matters, the Board or the Compensation Committee, as applicable, has the sole authority to engage or terminate the services of outside advisors. Accordingly, the Compensation Committee has hired Meridian Compensation Partners to provide independent advice and analysis on executive officer compensation matters and to perform specific tasks as requested by the Compensation Committee. This independent compensation consultant was retained by and reports directly to the Compensation Committee, which approves its scope of work.

During 2010, the consultant analyzed information about the compensation practices at companies with which AE competes for talented executives, counseled the Compensation Committee regarding the CEO’s employment agreement, potential impacts on executive compensation related to the proposed Merger with FirstEnergy, and provided information regarding market, regulatory and governance issues surrounding executive compensation. Representatives from Meridian Compensation Partners attended Compensation Committee meetings to present their findings and views to the Compensation Committee for consideration in setting executive officer compensation. Neither Meridian Compensation Partners nor any of its affiliates provided any other consulting services (as defined by the applicable disclosure rule) to AE or to management in 2010.

Role of Executive Officers

AE’s CEO assists the Compensation Committee in reaching compensation decisions with respect to other executive officers. The CEO discusses his own performance and his performance assessment of each other executive officer with the Compensation Committee and, within the framework of the compensation programs approved by the Board or Compensation Committee, provides the Compensation Committee with specific recommendations on base salary, annual incentives and long-term incentives for each executive officer (other than himself). The CEO also reviews and recommends performance metrics used in AE’s annual and long-term incentive plans. While the Compensation Committee gives appropriate consideration to the CEO’s observations, the ultimate decisions regarding executive officer compensation are made by the independent directors of the Board or the Compensation Committee, as applicable.

The independent directors determine the compensation of AE’s CEO and CFO after considering the recommendations of the Compensation Committee. Other than discussing his performance with the Compensation Committee and the independent directors of the Board, the CEO does not participate in the decisions relating to his own level of compensation. The other Named Executive Officers similarly do not play a role in their own compensation determination, other than discussing their own individual performance objectives and accomplishments with the CEO. The Board has delegated authority to the CEO to establish the compensation of certain other members of senior management who are not executive officers and whose compensation is not determined by the Compensation Committee or the independent directors of the Board.

As directed by the Compensation Committee, certain executive officers (including the Vice President responsible for human resources) and various human resources personnel also support the Compensation Committee in its work, including providing AE-specific data and information. In addition, the compensation consultant works from time to time with the CEO and certain other executive officers at the request of the Compensation Committee in formulating materials and proposals for consideration by the Compensation

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Committee. Although the consultant may share with the appropriate executive officers information regarding trends, peer group analysis and other matters relating to AE’s executive compensation programs, the consultant reports directly to the Compensation Committee.

The CEO and certain other executive officers generally participate in the early stages of the design and evaluation of compensation programs and policies. Executive officers participate in the process primarily because many of the compensation programs and policies apply to numerous employees, not just the executive officers, and those officers have an interest in ensuring that those programs and policies provide incentives for employees to achieve AE’s objectives. Certain executive officers therefore have discussed design changes to compensation programs and policies applicable to the Named Executive Officers with the Compensation Committee.

Peer Group and Benchmarking

To ensure that the compensation program is competitive and aligned with AE’s compensation philosophy and objectives, the Compensation Committee compares the compensation program for the Named Executive Officers to programs of companies in AE’s compensation peer group. Information regarding compensation practices at these companies was provided to AE by the Compensation Committee’s independent compensation consultant. The companies included in the peer group were approved by the Compensation Committee based on the recommendations of the consultant. AE’s 2010 peer group included the following 24 energy sector companies.

ALLETE, Inc.	DTE Energy Company	PG&E Corporation
Ameren Corporation	Duke Energy Corporation	Portland General Electric Company
American Electric Power Company, Inc.	Dynegy Inc.	Pennsylvania Power & Light Company (PPL)
Centerpoint Energy, Inc.	Edison International	Pinnacle West Capital
Cleco Corporation	Energy Future Holdings Corporation	Progress Energy, Inc.
CMS Energy Corporation	Entergy Corporation	Reliant Energy, Inc.
Constellation Energy	FirstEnergy Corporation	Sempra Energy
Dominion Resources, Inc.	Mirant Corporation	Southern Company

Changes from the prior year’s peer group included the addition of Pinnacle West Capital and the exclusion of Public Service Enterprise Group, Incorporated, primarily due to changes in the data available in the compensation consultant’s database.

AE is an energy business that owns and operates electric generation facilities and delivers electric services to customers in four states. The nature of AE’s operations was taken into consideration when developing the peer group by including similarly structured companies. Because the median revenues of the peer group companies were higher than AE’s revenues, the compensation data of the peer group was size-adjusted to reflect the revenues of AE. This adjusted data, along with the actual median compensation data for the peer group, was presented to the Compensation Committee by the consultant.

In setting executive officer compensation, the Compensation Committee’s philosophy is that the median compensation of similar positions within the peer group generally provides a reasonable starting reference point. The Compensation Committee then adjusts the Named Executive Officers’ compensation based on the reference point, performance and experience of the individual, the ability of the individual to contribute to the long-term success of AE and other factors. The other factors may include existing employment arrangements, level of responsibility, tenure, internal pay equity between the executive officers, AE’s performance and the need to attract specific candidates.

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Review of Total Compensation

When determining the executive officers’ 2010 compensation, the Compensation Committee reviewed a comprehensive summary of all components of each executive officer’s compensation (sometimes referred to as a “tally sheet”). The Compensation Committee also reviewed the circumstances that would trigger any payments and benefits, and a summary of the estimated amount of these payments and benefits in different termination scenarios. Based on this review, the Board and Compensation Committee, as applicable, concluded that the total compensation was reasonable and that there were no unintended disparities in compensation among the executive officers.

The Compensation Committee and the Board, as applicable, reviewed current compensation and amounts realized or potentially realizable from prior compensation awards (including stock awards) for the Named Executive Officers when determining their 2010 compensation. Although the Compensation Committee reviewed the compensation previously paid to the Named Executive Officers, the Compensation Committee did not make its compensation decisions for 2010 based on the value of past compensation. This reflects the Compensation Committee’s view that an executive officer’s compensation should reflect primarily his or her performance and the market value of the executive officer’s services (rather than the value of past compensation) in order to enable AE to attract and retain talented executives.

A benchmarking review of Mr. Evanson’s compensation was performed when AE entered into his employment agreement in July 2009. In connection with a review of total compensation, the Compensation Committee recognized that Mr. Evanson’s 2010 base salary and total cash compensation were above the comparable median compensation of AE’s peer group, while his total direct compensation (which includes stock compensation) was approximately 73% above the median of the actual compensation of the peer group. The 2010 base salary, total cash compensation and total direct compensation for all other Named Executive Officers were, in the aggregate, below the median compensation of AE’s peer group.

Employment Agreement

AE is a party to an agreement with Mr. Evanson that provides for his continued employment as Chairman, President and CEO through June 15, 2011, and for payments and benefits in the case of termination of his employment under certain conditions. The employment agreement sets Mr. Evanson’s base salary at $1.2 million until June 15, 2011, subject to an annual inflation adjustment. Mr. Evanson is eligible under the agreement to receive annual incentives. His annual incentive bonus is 125% of his base salary with a maximum bonus opportunity of 250% of his base salary.

The agreement entitles Mr. Evanson to receive annual stock awards with a target grant date value of $8.4 million each no later than February 28^th of each year, with the actual value realized based on the performance of AE. In consideration of the potential timing of the Merger closing and the timing of the annual stock grant under the agreement, in February 2011 the independent non-employee directors of AE’s Board approved a performance share award for Mr. Evanson based on certain corporate performance measures over the two-year period ending December 31, 2012 with a target value of $3 million. This award was made in full satisfaction of any otherwise applicable stock incentive grant requirement in 2011 under Mr. Evanson’s employment agreement.

The agreement also entitles Mr. Evanson to receive a lump sum payment in lieu of supplemental executive retirement benefits, which is described above under “Compensation Elements for Named Executive Officers—Other Benefits—Supplemental Executive Retirement Plan.” The provisions under Mr. Evanson’s employment agreement if his employment is terminated also continue and are described in the “Termination or Change in Control Payments” section above and the “Potential Payments Upon Termination or Change in Control” section below. The termination-related provisions that allow for stock options to be exercisable for the remaining term of the applicable grant are also described in the “Potential Payments Upon Termination or Change in Control” section below.

No other executive officers have employment agreements with AE.

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Accounting and Tax Treatment Implications for Executive Compensation

Section 162(m) of the Code

Section 162(m) of the Code generally precludes a public corporation from taking a federal income tax deduction for compensation in excess of $1 million for its chief executive officer or any of its three other highest paid executive officers (other than the chief financial officer) unless certain criteria are satisfied. The Long-Term Plan contains provisions intended to ensure that certain restricted share awards and performance awards to these employees are exempt from the $1 million deduction. Mr. Evanson’s base salary in excess of $1 million per year is not exempt from the $1 million deduction limit under Section 162(m) of the Code.

AE has attempted to qualify substantial components of its incentive compensation to executive officers to meet the performance-based exception under Section 162(m). While AE seeks to preserve deductibility where feasible, it may develop compensation elements and approve, in the future, additional compensation that in some instances is not fully deductible. Accordingly, in some circumstances, it may be necessary or appropriate to pay compensation or make stock awards that do not meet the performance-based exception under Section 162(m) in order to achieve the desired compensation objectives.

Section 280G and 4999 of the Code

Under Section 4999 of the Code, there is a substantial excise tax imposed on the executive officer if the present value of any benefits due, as a result of a change in control, are equal to or greater than a threshold amount, which is three times the executive’s five-year average income. This provision can sometimes render arbitrary results, due to the mechanical nature of the calculation and the effect of one-time items such as relocation reimbursements. Accordingly, if a change in control occurs, AE will make a gross-up payment to the Named Executive Officer (except for Mr. Evanson), such that the executive officer would retain the same amount, net of all taxes, that the executive officer would have retained had the excise tax not been triggered. However, the applicable plan is structured to avoid gross-up payments by reducing the change in control payments to be less than the threshold amount if the amount otherwise payable to the executive is not more than 110% of the threshold. Mr. Evanson is not eligible for any such gross-up payment under his employment agreement. This gross-up provision applies to any payments or distributions resulting from a change in control as discussed in the “Potential Payments Upon Termination or Change in Control” section below. AE does not provide for excise tax gross-up payment provisions in any new agreement or arrangements with its officers after May 5, 2009 that contain change in control provisions.

Certain Tax and Accounting Considerations

AE considers material tax and accounting impacts of its compensation programs on AE as well as on the executive officers. For example, the Compensation Committee reviewed the effects of the applicable tax and accounting rules when considering the design of AE’s current long-term incentive program. The Compensation Committee, however, believes that decisions regarding executive compensation should be primarily based on whether they result in positive long-term value for AE’s stockholders, customers, employees and other important stakeholders.

Executive Compensation Related Policies and Practices

Performance-based Compensation

The Board has adopted a formal policy to require that a significant portion of stock compensation granted to AE’s executive officers be “performance-based.” Under the policy, the vesting of such performance-based stock awards will depend on the satisfaction of pre-established performance criteria approved by the Board or Compensation Committee and disclosed to AE’s stockholders.

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For purposes of this policy, performance-based stock awards shall include one or more of the following types of grants:

• Indexed stock options;

• Premium-priced stock options;

• Other long-term incentive compensation that is performance-based, such as performance shares, performance units, performance-vesting options or performance-vesting restricted stock.

Recovery of Compensation Due to Financial Restatement

The Board has adopted a policy providing it with sole and absolute authority within governing law to seek reimbursement of annual incentive payments paid to any Named Executive Officer or other specified officer who engages in fraud or intentional misconduct that causes or partially causes the need for a restatement of AE’s financial results (often referred to as a “recoupment” or “claw-back” policy).

The policy also requires the forfeiture of bonuses and other compensation if the Board determines that knowing misconduct by the CEO or CFO has occurred and caused AE’s financial results to be restated. In this situation, the Board will take steps to secure reimbursement from the responsible CEO or CFO of certain bonus, incentive-based or stock-based compensation and net profits realized by the responsible officer from the sale of AE’s securities.

Equity Compensation Awards Policy and Policy for Determining the Timing of Equity Based Awards

AE’s equity compensation awards policy requires the Compensation Committee or the independent directors of the Board to approve any stock award to an executive officer in advance of or on the grant date. Stock grants to executive officers, other than grants to newly-hired or promoted executives, are to be approved annually at a regularly scheduled Board or Compensation Committee meeting, except when special circumstances require otherwise. The executive officers do not influence the timing of their individual awards. Rather, the timing of such awards is driven by a predetermined date for the applicable Board or Compensation Committee meeting or by the date of hire or promotion of an executive officer. AE does not time stock grants based on information, either positive or negative, about AE that has not been publicly disseminated.

Under the equity compensation awards policy, the exercise price of all stock option grants is equal to, or greater than, the closing price of AE’s underlying common stock on the date of the grant. AE does not backdate or reprice stock options granted under the Long-Term Plan or any similar plan. Also, AE does not grant discounted options and AE’s Long-Term Plan requires that options may not be repriced without stockholder approval.

Executive Stock Ownership Requirements and Hedging Arrangements

AE believes that direct ownership of AE stock facilitates continued commitment to the Company and supports one of the key objectives of AE’s executive compensation program—to create a strong link between executive compensation and total return to stockholders. Therefore, AE expects its CEO and the other executive officers reporting to the CEO to acquire and hold a significant equity interest in the Company in accordance with AE’s stock ownership guidelines as shown below:

Position	Value of Stock as Multiple of Annual Salary
Chief Executive Officer		300	%
Chief Financial Officer		200	%
Other executive officers reporting to CEO		100	%

Unexercised stock options do not count toward meeting these guidelines. Executive officers are ordinarily expected to meet or exceed the guidelines within five years following hire or promotion.

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Under AE’s insider trading policy, insiders, including AE’s executive officers, may not engage in hedging of its stock. Under the policy, the term “hedging” includes any transaction involving AE’s common stock that allows the owner to lock in much of the value of the stock generally in exchange for all or part of the potential for upside appreciation in the stock.

Compensation Committee Report

The Compensation Committee has reviewed and discussed the foregoing Compensation Discussion and Analysis with management and, based on the review and discussions, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

TED J. KLEISNER, Chair

H. FURLONG BALDWIN

ELEANOR BAUM

CHRISTOPHER D. PAPPAS

Compensation Committee Interlocks and Insider Participation

None of the members of the Compensation Committee, during fiscal year 2010 or as of the date of this annual report on Form 10-K, is or has been an officer or employee of the Company, and no executive officer of AE served on the compensation committee or board of any Company that employed any member of the Compensation Committee or the Board.

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EXECUTIVE COMPENSATION

The table below provides information regarding compensation for AE’s Chief Executive Officer, Chief Financial Officer, and the other three most highly paid executive officers serving as such at December 31, 2010.

2010 Summary Compensation Table ⁽¹⁾

Name and Principal Position	Year		Salary		Bonus (2)		Stock Awards (3)		Option Awards (3)		Non-Equity Incentive Plan Compensation (4)		Change in Pension Value and Nonqualified Deferred Compensation Earnings (5)		All Other Compensation (6)		Total
Paul J. Evanson Chairman, President and Chief Executive Officer		2010	$	1,213,151	$	224,000	$	8,249,056	$	0	$	2,066,000	$	841,289	$	380,783	$	12,974,279
		2009	$	1,200,000	$	0	$	4,178,352	$	4,153,403	$	1,918,500	$	834,131	$	305,345	$	12,589,731
		2008	$	1,121,343	$	0	$	3,884,982	$	4,144,044	$	1,230,000	$	817,184	$	360,510	$	11,558,063
Kirk R. Oliver Senior Vice President and Chief Financial Officer		2010	$	525,000	$	0	$	773,369	$	0	$	348,000	$	160,063	$	29,177	$	1,835,609
		2009	$	525,000	$	0	$	391,723	$	389,384	$	350,000	$	88,630	$	62,265	$	1,807,002
		2008	$	113,630	$	0	$	65,878	$	70,766	$	60,000	$	10,948	$	223,299	$	544,521
David M. Feinberg Vice President, General Counsel & Secretary		2010	$	407,534	$	101,000	$	523,444	$	0	$	278,000	$	151,625	$	10,071	$	1,471,674
		2009	$	400,000	$	90,000	$	680,649	$	257,122	$	265,500	$	95,769	$	10,071	$	1,799,111
		2008	$	384,890	$	40,000	$	240,531	$	256,544	$	175,000	$	48,392	$	9,471	$	1,154,828
Curtis H. Davis Chief Operating Officer, Generation		2010	$	407,534	$	98,000	$	523,444	$	0	$	226,000	$	161,547	$	10,071	$	1,426,596
		2009	$	400,000	$	0	$	258,675	$	257,122	$	240,000	$	109,236	$	35,175	$	1,300,208
		2008	$	335,342	$	0	$	240,531	$	235,426	$	110,000	$	54,588	$	520,568	$	1,496,455
Eric S. Gleason		2010	$	407,534	$	21,000	$	523,444	$	0	$	278,000	$	87,176	$	10,071	$	1,327,225
Vice President, Corporate Development and Quality		2009	$	400,000	$	50,000	$	258,675	$	257,122	$	265,500	$	44,295	$	12,284	$	1,287,876

(1) The compensation shown is for all services in all capacities to AE and its subsidiaries. All salaries and annual and long-term incentives are paid by Allegheny Energy Service Corporation, a subsidiary of AE. For a description of the material terms of Mr. Evanson’s employment agreement, and other arrangements and compensation elements, including salary, annual and long-term incentive, and other benefits for the Named Executive Officers, see the “Compensation Discussion and Analysis” section above.

(2) The bonus awards for 2010, 2009 and 2008 were based upon the respective year’s performance and were paid in 2011, 2010 and 2009, respectively. The amounts in this column represent the increases in awards under the Annual Plan attributable to individual performance, including performance not specifically measured through the objectives and performance factors under the Annual Plan.

(3) The amounts in the “Stock Awards” and “Option Awards” represent the aggregate compensation cost to be recognized over the service period as of the grant date under Financial Accounting Standards Board Accounting Standards Codification Topic 718, excluding the effect of estimated forfeitures. The compensation cost of stock awards to be recognized over the service period as of the grant date assuming achievement at the highest level of performance using the closing price of AE’s common stock on the date of the grant for 2010, 2009 and 2008 is as follows: Mr. Evanson, $16,498,112, $9,461,261 and $8,717,814; Mr. Oliver, $1,546,738, $886,994 and $147,822; Mr. Feinberg, $1,046,887, $1,007,706 and $539,747; Mr. Davis, $1,046,887, $585,732 and $539,747; and Mr. Gleason for 2010 and 2009, $1,046,887 and $585,732.

Assumptions used in the calculation of these amounts are reflected in Notes 11, 10 and 9 to AE’s consolidated financial statements for the years ended December 31, 2010, December 31, 2009 and December 31, 2008, respectively, and are included in AE’s Annual Report on Form 10-K filed with the SEC on February 23, 2011, March 1, 2010 and February 27, 2009, respectively.

(4) Incentive awards for 2010, 2009 and 2008 are based upon the respective year’s performance and were paid in 2011, 2010 and 2009, respectively. The amounts in this column represent awards paid under the Annual Plan, excluding any amounts reflected in the “Bonus” column.

(5) The amounts in this column reflect the increase in the actuarial present value of the Named Executive Officer’s accumulated benefit under all defined benefit and pension plans. These amounts include amounts attributable to (i) the Retirement Plan and (ii) the SERP for all Named Executive Officers, except for Mr. Evanson. For Mr. Evanson, and pursuant to his employment agreement, the amount includes amounts attributable to the obligation to make a lump sum cash payment of $66,667 upon his termination of employment for each month that he is employed by AE. The amounts are valued at December 31, 2010, December 31, 2009 and December 31, 2008 for the respective years, which is the same pension plan measurement date used for financial reporting purposes.

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The Named Executive Officers did not have any reportable earnings attributed to nonqualified deferred compensation plans or any nonqualified deferred compensation contributions, earnings, withdrawals, distributions or balances.

(6) The amounts in this column include, as required, the aggregate incremental cost to AE of providing personal benefits. For Mr. Evanson, the figure in this column for 2010 includes reimbursement for certain legal fees and $358,982 for the personal use of AE’s aircraft, which includes the costs associated with travel to outside board meetings. For Mr. Oliver, the figure in this column for 2010 includes the cost for his executive physical, and $17,296 for relocation expenses which includes $6,849 in related taxes on this amount.

AE valued the personal use of the aircraft as summarized below.

AE’s Aircraft—Valued based on the variable cost per flight hour, as well as other direct out of pocket expenses. Variable costs included fuel, maintenance, weather monitoring, on-board catering and other miscellaneous variable costs. Direct out of pocket expenses included landing, parking and certain hangar storage expenses, crew travel expenses and passenger ground transportation. Certain applicable deadhead and other positioning costs are allocated to the executive officers. On certain occasions, the executive officer’s spouse or other immediate family member may accompany the executive on a flight. Typically, there are no additional incremental costs associated with such spousal or family travel, as there is no additional variable cost or increased direct out of pocket expenses. The amount shown also includes any expenditure related to the personal use of a chartered aircraft when the aircraft was unavailable. The following costs were not included in the calculation of incremental cost: fixed costs that do not change based on usage, such as the operator’s management fee and the cost of maintenance not related to trips, and the amount of any related disallowed tax deduction.

2010 Grants of Plan-Based Awards

The following table sets forth information concerning estimated future payouts under the Annual Plan and the Long-Term Plan at specified levels of achievement. No other grants or awards were provided to the Named Executive Officers during the fiscal year ended December 31, 2010.

Name	Grant Date		Estimated Future Payouts Under Non-Equity Incentive Plan Awards (1)						Estimated Future Payouts Under Equity Incentive Plan Awards (2)						All Other Stock Awards: Number of Shares of Stock or Units		All Other Option Awards: Number of Securities Underlying Options		Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Stock and Option Awards (3)
			Threshold		Target		Maximum		Threshold (#)		Target (#)		Maximum (#)
Paul J. Evanson		2/25/10	$	0	$	1,530,000	$	3,060,000		0		359,436		718,872		—		—		—	$	8,249,056
Kirk R. Oliver		2/25/10	$	0	$	393,750	$	787,500		0		33,698		67,396		—		—		—	$	773,369
David M. Feinberg		2/25/10	$	0	$	203,767	$	407,534		0		22,808		45,616		—		—		—	$	523,444
Curtis H. Davis		2/25/10	$	0	$	203,767	$	407,534		0		22,808		45,616		—		—		—	$	523,444
Eric S. Gleason		2/25/10	$	0	$	203,767	$	407,534		0		22,808		45,616		—		—		—	$	523,444

(1) The Named Executive Officers may earn from zero to 200% of their respective target awards for 2010 under the Annual Plan. For Mr. Evanson, if his actual award for any year exceeds the maximum amount of $2.4 million under the existing Annual Plan, any excess amount will be awarded pursuant to a separate arrangement. Targets are based on a percentage of base salary. See “Compensation Discussion and Analysis – Compensation Elements for Named Executive Officers – Annual Incentives,” for information regarding material conditions and the criteria applied in determining the amounts payable under award opportunities provided in 2010. The actual amounts paid with respect to these awards are included in the “Bonus” and “Non-Equity Incentive Plan Compensation” columns in the Summary Compensation Table.

(2) The number of shares is based on a percentage of base salary divided by the closing price of AE’s common stock on February 22, 2010. For 2010, these performance shares were linked to the average three-year corporate performance under AE’s annual incentive plan. See “Compensation Discussion and Analysis – Compensation Elements for Named Executive Officers – Long-Term Incentive Awards,” for information regarding the material conditions applicable to the awards provided in 2010.

(3) The amounts in this column represent the aggregate compensation cost to be recognized over the service period as of the grant date under Financial Accounting Standards Board Accounting Standards Codification Topic 718, excluding the effect of estimated forfeitures.

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Outstanding Equity Awards at 2010 Fiscal Year-End

The following table sets forth information concerning stock awards held by the Named Executive Officers at December 31, 2010:

	Option Awards												Stock Awards
Name	Number of Securities Underlying Unexercised Options Exercisable		Number of Securities Underlying Unexercised Options Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options		Option Exercise Price		Option Expiration Date		Market Value of Options Exercisable (1)		Number of Shares or Units of Stock That Have Not Vested		Market Value of Shares or Units of Stock That Have Not Vested		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (2)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (2)
Paul J. Evanson		150,000		—		—	$	13.35		2/18/2014	$	1,633,500		—		—		—		—
		266,498		—		—	$	53.67		2/22/2018	$	0		—		—		—		—
		582,524		—		—	$	23.64		2/27/2019	$	349,515		—		—		359,436	$	8,712,729
Kirk R. Oliver		7,667		—		—	$	27.30		11/6/2018	$	0		—		—		—		—
		54,612		—		—	$	23.64		2/27/2019	$	32,767		—		—		33,698	$	816,840
David M. Feinberg		10,000		—		—	$	14.70		8/9/2014	$	95,400		—		—		—		—
		20,000		—		—	$	19.36		1/3/2015	$	97,600		—		—		—		—
		20,000		—		—	$	42.00		10/18/2016	$	0		—		—		—		—
		16,498		—		—	$	53.67		2/22/2018	$	0		—		—		—		—
		36,062		—		—	$	23.64		2/27/2019	$	21,637		—		—		22,808	$	552,866
Curtis H. Davis		16,498		—		—	$	50.67		3/1/2018	$	0		—		—		—		—
		36,062		—		—	$	23.64		2/27/2019	$	21,637		—		—		22,808	$	552,866
Eric S. Gleason		16,498		—		—	$	45.86		8/7/2018	$	0		—		—		—		—
		50,000		—		—	$	45.86		8/7/2018	$	0		—		—		—		—
		36,062		—		—	$	23.64		2/27/2019		21,637		—		—		22,808	$	552,866

(1) Market value of the exercisable options represents the extent to which the closing price of AE’s common stock on December 31, 2010 is over the option exercise price times the number of shares subject to the option.

(2) With respect to any performance shares, the number of shares and associated value is based on the target results and the closing price of AE’s common stock on December 31, 2010. Shares vest on December 31, 2012.

2010 Option Exercises and Stock Vested

The following table sets forth information concerning the exercises of stock options and the vesting of stock awards by the Named Executive Officers during 2010:

	Option Awards				Stock Awards (1)
Name	Number of Shares Acquired  on Exercise		Value Realized on Exercise		Number of Shares  Acquired on Vesting		Value Realized on Vesting  (2)
Paul J. Evanson		—		—		244,872	$	5,660,216
Kirk R. Oliver		—		—		18,090	$	418,150
David M. Feinberg		—		—		27,060	$	625,492
Curtis H. Davis		—		—		15,160	$	350,423
Eric S. Gleason		—		—		15,160	$	350,423

(1) Upon approval of the Merger Agreement and the proposed Merger with FirstEnergy by AE’s stockholders on September 14, 2010, stock awards that were granted before the execution of the Merger Agreement in February 2010 vested and became exercisable or payable.

(2) The value is determined based on the average of the high and low trading prices of AE’s common stock on the date of vesting.

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2010 Pension Benefits ⁽¹⁾

The following table provides information regarding benefits available to the Named Executive Officers under the Retirement Plan and SERP and, in the case of Mr. Evanson, his employment agreement:

Name	Plan Name	Number of Years Credited Service		Present Value of Accumulated Benefit (3)		Payments During Last Fiscal Year
Paul J. Evanson	Retirement Plan		7.50	$	230,605	$	0
	Payment in lieu of SERP  (2)		7.50	$	6,000,030	$	0
Kirk R. Oliver	Retirement Plan		2.25	$	53,916	$	0
	SERP		2.25	$	205,725	$	0
David M. Feinberg	Retirement Plan		6.42	$	77,927	$	0
	SERP		6.42	$	288,184	$	0
Curtis H. Davis	Retirement Plan		2.83	$	91,277	$	0
	SERP		2.83	$	234,094	$	0
Eric S. Gleason	Retirement Plan		2.42	$	37,777	$	0
	SERP		2.42	$	104,392	$	0

(1) Pension benefits are valued at December 31, 2010, which is the same pension plan measurement date used for financial reporting purposes as of the last completed fiscal year. See “Compensation Discussion and Analysis—Compensation Elements for Named Executive Officers—Other Benefits—Supplemental Executive Retirement Plan” above for a discussion of the material elements of the SERP.

The Retirement Plan is a noncontributory, trusteed pension plan designed to meet the requirements of Section 401(a) of the Code. These Retirement Plan benefits are available to the Named Executive Officers on the same basis as for other employees. Each covered employee is eligible for retirement at his or her normal retirement date (age 65), with early retirement permitted. The benefit payable under the Retirement Plan is a function of the participant’s compensation and credited years of service. The normal form of benefit is a life annuity for unmarried participants and a joint 50% survivor annuity for married participants. While the plan does not provide lump sum options, actuarially-equivalent alternative annuity options are available to all participants. A participant has a fully vested benefit under the plan upon completing five years of service or attainment of age 55. A participant may elect early retirement on or after age 55, subject to reduction of the retirement benefit to reflect the early commencement of the benefit prior to age 62. Mr. Davis is the only Named Executive Officer who is eligible for early retirement under the Retirement Plan.

(2) In lieu of benefits under the SERP and pursuant to his employment agreement, Mr. Evanson is entitled to a lump sum cash payment of $66,667 for each month that he is employed by AE, to be paid on the termination of his employment with AE.

(3) For the Retirement Plan and SERP, the amount represents the present value of a single life annuity payable at the later of the earliest age eligible for an unreduced benefit under each plan or the age of the executive officer as of December 31, 2010, which is the same pension plan measurement date used for financial reporting purposes for last completed fiscal year. The earliest age eligible for an unreduced benefit is 62 for the Retirement Plan and 60 for the SERP. The present value amounts were calculated using 5.5% interest rates for the Retirement Plan and the SERP, and the mortality assumption is based on the Retirement Plans—2000 Mortality Table (male) projected to 2007. These are the same assumptions applied with respect to the Retirement Plan and SERP as reflected in Note 12 to AE’s consolidated financial statements for the year ended December 31, 2010, and is included in this annual report on Form 10-K. For the Retirement Plan and SERP, all amounts shown are estimates since the actual payments and benefits can only be determined at the time of the executive officer’s separation from AE.

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Potential Payments Upon Termination or Change In Control

For the reasons discussed in the “Compensation Discussion and Analysis—Compensation Elements for Named Executive Officers—Other Benefits—Termination or Change in Control Payments” section above, AE has entered into arrangements with its Named Executive Officers that provide certain payments and benefits upon a change in control of AE or a termination of employment in some circumstances. This section describes the circumstances that would trigger any payments and benefits and quantifies the estimated amount of these payments and benefits in different scenarios. If a triggering event were to occur, actual payments summarized below would likely be different from those presented here since the actual payments and benefits can only be determined at the time of the executive officer’s separation from AE.

Upon approval of the Merger Agreement and the Merger by AE’s stockholders on September 14, 2010, stock awards outstanding at that time that were granted before the execution of the Merger Agreement with FirstEnergy in February 2010 vested and became exercisable or payable at target. Details related to the change of control payments that may be made to the Named Executive Officers in connection with the proposed Merger with FirstEnergy were provided in a joint proxy statement/prospectus in connection with the September 14, 2010 special meeting of stockholders. The amounts reflected below do not specifically contemplate the proposed Merger with FirstEnergy, but rather reflect the payments and benefits that would have been made to the Named Executive Officers upon a change in control of AE if such a change in control had occurred on December 31, 2010 and the executive officer’s employment had terminated at December 31, 2010.

The agreements and plans summarized below are complex legal documents with terms and conditions having precise meanings, which are designed to address many possible but currently hypothetical situations. It is not possible to reduce them to simple explanations without some loss of precision. The following discussion covers only some of the more likely circumstances that could cause them to come into play, and the possible consequences.

Overview

AE maintains plans that provide for a cash severance payment to most of its employees, including the executive officers, if their employment is terminated under certain conditions. Under the Long-Term Plan, all participants, including the Named Executive Officers, are entitled to receive all or a portion of any outstanding and unvested stock grants under certain conditions such as change in control, death, disability, or retirement. For the Named Executive Officers, AE also offers a change in control plan and other arrangements that provide specified benefits. In addition, the employment agreement with Mr. Evanson and the plans with the Named Executive Officers subject the executive officers to additional restrictions not common to other AE employees.

Restrictive Covenants

As outlined in their respective arrangements, the Named Executive Officers are subject to a non-competition obligation for one year, and a non-solicitation obligation for two years, following the termination of the officer’s employment. The Named Executive Officers are also subject to confidentiality obligations, and Messrs. Davis, Feinberg, Gleason and Oliver are subject to customary non-disparagement obligations.

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Change in Control

Termination Following Change in Control

If a change in control occurs, and if other triggering events occur within a certain period of time following a change in control (including termination of employment by AE without cause (as described below) or the executive leaving employment for good reason (as described below)), the Named Executive Officer is entitled to receive the following:

• Mr. Evanson will receive a payment equal to the sum of (i) his base salary and (ii) his target annual incentive payment for the year in which termination occurs. All other Named Executive Officers will receive a payment equal to the sum of (i) three times the executive’s base salary and (ii) three times the executive’s target annual incentive payment for the year in which termination occurs.

• Payment equal to the executive’s target annual incentive for the year of termination, which is prorated for the number of days he was employed by AE during the year of termination.

• Outstanding and unvested performance shares held by the executives will accelerate, vest and become payable.

• Mr. Evanson will receive one year of continued coverage for medical, dental, disability and life insurance benefits for himself and his dependents. All other Named Executive Officers will receive a lump sum payment of $60,000 with respect to health and welfare benefit coverage.

• Mr. Evanson will receive a lump sum cash payment equal to $66,667 for each remaining month in the term of his employment agreement. Mr. Evanson will also receive a previously earned amount in a lump sum cash payment equal to $66,667 for each month of employment with AE at the time of a change in control.

• Named Executive Officers participating in the SERP will be vested in their SERP benefit and each executive will be credited with an additional three years of service for purposes of determining his SERP benefit.

• Named Executive Officers (other than Mr. Evanson) will not be required to repay any relocation payments or benefits and will be entitled to receive any other amounts due in respect of any relocation benefits.

Under Section 4999 of the Code, there is a substantial excise tax imposed on the executive officer if the net present values of any benefits due, as a result of a change in control, are equal to or greater than a threshold amount, which is three times the executive officer’s five-year average income. This provision can sometimes render arbitrary results, due to the mechanical nature of the calculation and the effect of one time items such as relocation reimbursements. Accordingly, except for Mr. Evanson who is not eligible for any such gross-up payment, if a change in control occurs, AE will make a gross-up payment to the Named Executive Officer, such that the executive officer would retain the same amount, net of all taxes, that the executive officer would have retained had the excise tax not been triggered. However, the applicable plan is structured to avoid gross-up payments by reducing the change in control payments to be less than the threshold amount if the amount otherwise payable to the executive officer is not more than 110% of the threshold. The final structure and specifics of any payment will dictate whether any excise taxes will be due on these payments. In addition, AE does not provide for excise tax gross-up payment provisions in any new agreement or arrangements with its officers after May 5, 2009 that contain change in control provisions.

In connection with the Merger, FirstEnergy and Paul J. Evanson have entered into an employment agreement, dated as of March 19, 2010, pursuant to which, upon completion of the Merger, Mr. Evanson will serve as executive vice chairman of FirstEnergy reporting to and working at the discretion of Mr. Anthony J. Alexander, FirstEnergy’s chief executive officer. The agreement is to commence upon the completion of the Merger and is for a two year term.

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Termination Without Cause or Termination for Good Reason with No Change in Control

If AE terminates Mr. Evanson’s employment without cause, or if he terminates his employment for good reason, Mr. Evanson is entitled to receive the same payments and benefits as in a change in control as described above, except that any 2011 stock award will vest on the same basis as if Mr. Evanson had remained employed through June 30, 2011 and in accordance with the pro-rata retirement vesting provisions in the award agreement.

For all other Named Executive Officers, if AE terminates their employment without cause or if they terminate their employment for good reason, the executive officer is entitled to receive the following:

• Payment equal to the sum of (i) two times their base salary, and (ii) two times the average annual incentive payments for the prior three years or since they were employed by AE, whichever is shorter.

• Payment equal to their average annual incentive payments for the prior three years or since they were employed by AE, whichever is shorter, which is prorated for the number of days they were employed by AE during the year of termination.

• A prorated portion of performance shares held by the executive officers will accelerate, vest and become payable at the end of the applicable award period (dependent on the actual underlying performance).

• A lump sum payment of $30,000 with respect to health and welfare benefit coverage.

• If the executive officer has five or more years of service with AE as of the termination date, he will be vested in the SERP.

Termination of Employment Due To Death or Disability

If a Named Executive Officer’s employment is terminated due to the executive officer’s death or disability, the executive officer or his estate is entitled to receive the following:

• For Mr. Evanson, a payment equal to his annual incentive for the year of termination prorated for the number of days that he was employed by AE. Any of his unvested performance shares vest and become payable. Mr. Evanson or his estate will also receive a previously earned amount in a lump sum cash payment equal to $66,667 for each month of employment with AE at the time of death or disability.

• For all other Named Executive Officers, a prorated portion of performance shares will accelerate, vest and become payable (dependent on the actual underlying performance to the date of termination).

Termination of Employment Due to a Qualifying Retirement

If Mr. Evanson retires and terminates his employment for other than good reason, he is entitled to receive the following:

• A payment equal to his annual incentive for the year of termination prorated for the number of days that he was employed by AE. He will also receive a previously earned amount in a lump sum cash payment equal to $66,667 for each month of employment with AE at the time of retirement.

• Performance shares granted to him in 2010 will become vested as to 50% of the shares if his retirement is on or after December 15, 2010, 75% of the shares if his retirement is on or after March 15, 2011, and 100% of the shares if his retirement is on or after June 15, 2011 and any awards granted after 2010 will vest on a pro-rata basis consistent with AE’s ordinary retirement provision.

• Any vested stock options will be exercisable until the original expiration date of the option.

If Messrs. Davis, Feinberg, Gleason or Oliver retire (after age 55 and with five or more years of service), a prorated portion of performance shares held by the executive officers will accelerate, vest and become payable at the end of the applicable award period (dependent on the actual underlying performance).

Additional information about vested retirement benefits of the Named Executive Officers is provided in the Pension Benefits table above, and the related notes.

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Termination Following Expiration of the Employment Agreement Term

If Mr. Evanson’s employment is terminated for any reason following the expiration of his employment agreement term on June 15, 2011, AE will pay a lump sum cash payment equal to his target incentive amount prorated for the year in which his termination occurs and a lump sum cash payment equal to $66,667 for each month of employment with AE. Also, if the termination is other than for cause, any unvested performance shares will accelerate, vest and become payable at the end of the applicable award period (dependent on the actual underlying performance). Any performance shares, stock options or other stock award granted to him in 2011 will become vested on a pro-rata basis consistent with the pro-rata retirement vesting provisions in the award agreement. The stock options will be exercisable until the original expiration date of the option.

Description of Certain Terms

The term “change in control” (as further defined in the relevant plan or agreement and in the Long-Term Plan) generally includes the occurrence of any of the following events:

Beneficial Owner of AE’s Securities

• Any person is or becomes the beneficial owner of AE’s securities representing more than 20% (25% as it relates to the treatment of any outstanding stock grants) of the combined voting power of the then outstanding securities.

Board Membership

• As it relates to the treatment of any outstanding stock grants, during any period of not more than two years, individuals who constitute the Board as of the beginning of the period and any new director whose election or nomination for election was approved by a vote of at least two-thirds of the current Board members, cease to constitute a majority of the Board.

• Otherwise, a majority of the Board is replaced without approval of at least two-thirds of the current Board members.

Reorganization, Merger, Sale and Certain Related Actions

• A reorganization, merger, consolidation or sale of AE or other disposition of all or substantially all of AE’s assets is consummated and results in a change of ownership of more than 40% (except that, in the case of stock grants made after December 31, 2009 to Named Executive Officers other than Mr. Evanson, the ownership change must be of more than 50%) of AE’s outstanding voting securities.

Liquidation or Dissolution

• As it relates to the treatment of any outstanding stock grants, AE’s stockholders approve a plan of complete liquidation of AE.

• Otherwise, AE’s stockholders approve a plan of complete liquidation or dissolution of AE.

For Mr. Evanson, the term “cause” (as further defined in his employment agreement) includes Mr. Evanson engaging in willful gross misconduct or willful gross neglect in bad faith or unreasonably and which causes AE material economic harm or Mr. Evanson’s conviction for certain felonies. For all other Named Executive Officers the term “cause” (as further defined in the relevant plan) includes the executive officer engaging in willful misconduct, fraud, failing to perform a substantial part of his duties or the conviction for certain crimes.

For Mr. Evanson, the term “good reason” (as further defined in his employment agreement) includes a reduction in pay, responsibilities, duties or authority or a requirement that he relocate. For all other Named Executive Officers, the term “good reason” (as further defined in the relevant plan) includes a reduction in pay, and, in connection with a change in control, also includes a reduction in responsibilities, duties or authority or a requirement that the executive officer relocate.

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Potential Payments Upon Termination or Change in Control Table

The table below sets forth potential benefits that each Named Executive Officer would be entitled to receive in the situations outlined above. Unless otherwise specified, the amounts shown in the table are the amounts that could be payable under existing plans and arrangements if the Named Executive Officer’s employment had terminated at December 31, 2010.

Consistent with SEC instructions, the amounts shown in the table below exclude obligations due from AE following a triggering event for (i) any earned but unpaid base salary, annual incentive compensation and long-term incentive compensation through the date of termination; (ii) vested benefits under AE’s retirement plans and Employee Stock Ownership and Savings Plan; (iii) accrued vacation pay; (iv) reimbursement of reasonable business expenses incurred prior to the date of termination; and (v) any other compensation or benefits to which the Named Executive Officer may be entitled that are available generally to AE’s salaried employees and provide for the same method of allocation of benefits. For the SERP, the amounts provided below represent the present value of a single life annuity payable at the later of the earliest retirement age or December 31, 2010. The values for the stock grants are based on the closing price of $24.24 on December 31, 2010. The amounts shown in the table below assume the annual incentive was paid out at 100% performance at target. The Named Executive Officers are subject to non-competition and non-solicitation obligations following any termination of employment. For purposes of the hypothetical Change in Control, no value or payments have been assigned to these obligations. Additional information about vested retirement benefits is provided in the Pension Benefits table above.

Name	Severance Amount  (1)		Accelerated Vesting of Stock Options		Accelerated Vesting of Stock		Benefit Continuation  (2)		Estimated Tax Gross-Up  (3)		Total
Paul J. Evanson (4)
Change in Control (5)	$	4,284,000	$	0	$	8,712,729	$	429,690	$	0	$	13,426,419
Good Reason/Without Cause	$	4,284,000	$	0	$	8,712,729	$	429,690	$	0	$	13,426,419
For Cause	$	0	$	0	$	0	$	0	$	0	$	0
Retirement	$	1,530,000	$	0	$	4,356,364	$	0	$	0	$	5,886,364
Death/Disability	$	1,530,000	$	0	$	8,712,729	$	0	$	0	$	10,242,729
Kirk R. Oliver
Change in Control (5)	$	3,150,000	$	0	$	816,840	$	862,754	$	2,388,502	$	7,218,096
Good Reason/Without Cause	$	2,097,000	$	0	$	272,008	$	30,000	$	0	$	2,399,008
For Cause	$	0	$	0	$	0	$	0	$	0	$	0
Retirement	$	0	$	0	$	272,008	$	0	$	0	$	272,008
Death/Disability	$	0	$	0	$	272,008	$	0	$	0	$	272,008
David M. Feinberg
Change in Control (5)	$	2,050,000	$	0	$	552,866	$	707,027	$	2,058,334	$	5,368,227
Good Reason/Without Cause	$	1,769,500	$	0	$	184,270	$	450,067	$	0	$	2,403,837
For Cause	$	0	$	0	$	0	$	0	$	0	$	0
Retirement	$	0	$	0	$	184,270	$	0	$	0	$	184,270
Death/Disability	$	0	$	0	$	184,270	$	0	$	0	$	184,270
Curtis H. Davis
Change in Control (5)	$	2,050,000	$	0	$	552,866	$	708,807	$	1,404,199	$	4,715,872
Good Reason/Without Cause	$	1,666,000	$	0	$	184,270	$	30,000	$	0	$	1,880,270
For Cause	$	0	$	0	$	0	$	0	$	0	$	0
Retirement	$	0	$	0	$	184,270	$	0	$	0	$	184,270
Death/Disability	$	0	$	0	$	184,270	$	0	$	0	$	184,270
Eric S. Gleason
Change in Control (5)	$	2,050,000	$	0	$	552,866	$	484,795	$	1,728,412	$	4,816,073
Good Reason/Without Cause	$	1,741,750	$	0	$	184,270	$	30,000	$	0	$	1,956,020
For Cause	$	0	$	0	$	0	$	0	$	0	$	0
Retirement	$	0	$	0	$	184,270	$	0	$	0	$	184,270
Death/Disability	$	0	$	0	$	184,270	$	0	$	0	$	184,270

⁽¹⁾ Includes appropriate multiples of base salary and annual incentives as outlined in their respective arrangements.

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⁽²⁾ Includes payments with respect to health and welfare and retirement benefits as outlined in the respective arrangements.

⁽³⁾ With respect to tax gross-ups, AE assumed an excise tax rate under Section 4999 of the Internal Revenue Code of 20% and an individual tax rate of 40.52% (a 35% federal income tax rate, a 1.45% Medicare tax rate and a 4.07% state and local income tax rate), with such rate reduced by assumed deductions for state and local taxes as required by their respective arrangement. For purposes of this disclosure, included in this calculation is the value of the stock awards that were granted before the execution of the Merger Agreement in February 2010, which vested and became exercisable or payable on September 14, 2010.

⁽⁴⁾ As described above, Mr. Evanson is entitled to receive certain compensation if his employment is terminated following the June 15, 2011 expiration of his employment agreement. Any such compensation is not reflected in the table above because this provision was not applicable at December 31, 2010.

⁽⁵⁾ For purposes of this disclosure, AE assumed any annual incentive awards were not earned at December 31, 2010. However, upon any actual transaction, all or part of any annual incentive awards may be earned and thus not subject to 280G.

Non-Employee Director Compensation

As further described below, AE uses a combination of cash and stock-based compensation to attract and retain qualified directors to serve on the Board. In setting non-employee director compensation, AE considers the significant amount of time that AE’s non-employee directors expend in fulfilling their duties to AE, as well as the high skill level required of members of the Board.

Cash Compensation.  In 2010, each non-employee director received:

• $50,000 in annual cash retainer fees;

• $1,250 for each Board meeting attended; and

• $1,250 for each committee meeting attended, except that each member of the Audit Committee received $1,500 for each of the Audit Committee meetings attended.

In 2010, the Chair of the Audit Committee also received an additional annual fee of $12,500 and the Chairs of the Compensation Committee and Governance Committee each received an additional annual fee of $8,000. Also, the Presiding Director received an additional annual fee of $8,000 until May 20, 2010, which was increased to an annual fee of $15,000 after May 20, 2010.

Stock Compensation.  Each non-employee director is entitled to receive shares of AE’s common stock quarterly equivalent to the lesser of (i) the value of 1,000 shares or (ii) $30,000 of AE’s common stock, rounded to the nearest whole share, as determined based on the closing price of AE’s common stock on the last business day of each calendar quarter. For 2010, each non-employee director received 1,000 shares of AE’s common stock each quarter. AE also will issue the same number of shares of AE’s common stock to any non-employee director whose services are terminated during a quarter as a result of death or disability.

Nonqualified Deferred Compensation.  Each non-employee director may elect to defer receipt of all or part of his or her director’s compensation (whether payable in cash or stock) under an unfunded deferred compensation plan maintained on his or her behalf. Any deferred stock is credited with additional shares (referred to as “dividend equivalents”) in respect of each dividend paid by AE. All deferred stock compensation and any related dividend equivalents are payable in stock at the time distributable in accordance with the terms of the plan. The deferred compensation plan also permits each non-employee director to direct the investment of any deferred cash compensation into either an interest bearing account, or a phantom stock fund that constitutes a notional investment in AE’s common stock. Amounts credited to the phantom stock fund are further credited or debited over time depending on the performance of AE’s common stock and also are credited with dividend equivalents in respect of each dividend paid by AE. All deferred cash compensation and any related dividend equivalents are payable in cash at the time distributable in accordance with the terms of the plan.

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Non-Employee Director Stock Ownership Requirements.  Members of the Board are expected to own a significant equity interest in AE in accordance with AE’s stock ownership guidelines. Under the stock ownership guidelines, non-employee directors must hold six times their annual cash retainer in AE common stock, including shares and phantom stock held in the deferred compensation plan. Any previously issued stock options that remain unexercised do not count toward meeting these guidelines. Directors are ordinarily expected to meet or exceed these guidelines within two years following election to the Board.

2010 Director Compensation Table

The following table describes the compensation arrangements with AE’s non-employee directors for the 2010 fiscal year.

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)  (1)		Option Awards ($) (2)		Total ($)
H. Furlong Baldwin	$	71,825	$	92,440	$	0	$	164,265
Eleanor Baum	$	77,425	$	92,440	$	0	$	169,865
Cyrus F. Freidheim, Jr.	$	81,059	$	92,440	$	0	$	173,499
Julia L. Johnson	$	82,500	$	92,440	$	0	$	174,940
Ted J. Kleisner	$	73,675	$	92,440	$	0	$	166,115
Christopher D. Pappas	$	71,250	$	92,440	$	0	$	163,690
Steven H. Rice	$	84,575	$	92,440	$	0	$	177,015
Gunnar E. Sarsten	$	85,250	$	92,440	$	0	$	177,690
Michael H. Sutton	$	94,000	$	92,440	$	0	$	186,440

(1) The amounts in this column represent the aggregate grant date fair value of all stock awards made during 2010 determined in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718. The grant date fair values for the quarterly stock awards were $23.00, $20.68, $24.52 and $24.24 for the March 31, June 30, September 30 and December 31, 2010 grants, respectively. See Note 11 to AE’s consolidated financial statements for the year ended December 31, 2010 included in this Annual Report on Form 10-K for additional information.

As of December 31, 2010, the following directors were credited with the following number of vested shares under an unfunded deferred compensation plan, including any additional shares of AE’s common stock credited as a result of reinvestment of dividends: Mr. Baldwin, 21,387; Mr. Freidheim, 20,769; Ms. Johnson, 21,387 Mr. Kleisner, 11,234; Mr. Pappas, 11,234; Mr. Rice, 4,037; and Mr. Sutton, 23,097.

Between 1995 and 1999, AE granted restricted shares to its non-employee directors. As of December 31, 2010, the following directors had restricted shares of AE common stock, including any additional shares of AE’s common stock credited as a result of reinvestment of dividends: Dr. Baum, 1,000; Mr. Rice, 1,293; and Mr. Sarsten, 1,000.

As of December 31, 2010, the following directors had deferred cash compensation credited as shares in a phantom stock fund: Mr. Baldwin, 10,163; Mr. Freidheim, 1,303; Ms. Johnson, 9,962; Mr. Kleisner, 635; Mr. Pappas, 1,495; and Mr. Rice, 2,603. Any distribution related to the phantom stock fund will be paid in cash based on the market value of the applicable common stock as of the distribution date.

(2) Between 1999 and 2001, AE granted stock options to its non-employee directors. In connection with these stock option grants, Mr. Sarsten held options to purchase 20,000 shares with an exercise price of $42.3125 per share that expired on December 7, 2010.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Equity Compensation Plan Information

This table provides certain information as of December 31, 2010 with respect to AE’s equity compensation plans:

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 (1)		3,594,249	(2)	$	21.08		2,824,088
Equity compensation plans not approved by security holders		0			N/A		0
Total		3,594,249		$	21.08		2,824,088

(1) Includes the Allegheny Energy, Inc. 2008 Long-Term Incentive Plan and the Allegheny Energy, Inc. Non-Employee Director Stock Plan.

(2) Includes shares granted to directors under the Allegheny Energy, Inc. Non-Employee Director Stock Plan that were deferred and stock options previously granted under the former Allegheny Energy, Inc. 1998 Long-Term Incentive Plan.

AE previously granted equity awards under AE’s former 1998 Long-Term Incentive Plan (the “1998 Plan”). Upon stockholder approval on May 15, 2008, the Allegheny Energy, Inc. 2008 Long-Term Incentive Plan became effective and no further awards were made under the 1998 Plan and any awards granted under the 1998 Plan remained outstanding in accordance with their terms.

For more information regarding AE’s current equity compensation plans, see “Compensation Discussion and Analysis” and “Non-Employee Director Compensation” above.

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Security Ownership of Certain Beneficial Owners and Management

The table below shows the number of shares of AE’s common stock that are beneficially owned, directly or indirectly, by each of its directors and Named Executive Officers, and all of AE’s directors and executive officers as a group as of February 1, 2011, and each beneficial owner of more than 5% of AE’s common stock. Based on a review of filings made under Section 13(d) and Section 13(g) of the Exchange Act, as of February 10, 2011, AE is aware of three holders of more than 5% of the outstanding shares of AE’s common stock.

Name (1)	Shares of AE’s Common Stock (2)	Percent of Class
Paul J. Evanson	2,478,809	1.5
H. Furlong Baldwin	34,588	*
Eleanor Baum	28,227	*
Cyrus F. Freidheim, Jr.	34,769	*
Julia L. Johnson	26,588	*
Ted J. Kleisner	25,648	*
Christopher D. Pappas	11,369	*
Steven H. Rice	17,208	*
Gunnar E. Sarsten	27,858	*
Michael H. Sutton	26,697	*
Curtis H. Davis	63,075	*
David M. Feinberg	126,021	*
Eric S. Gleason	112,773	*
Kirk R. Oliver	76,012	*
All of AE’s current directors and current executive officers as a group (17 persons)	3,265,078	1.9
BlackRock, Inc. (3)	9,424,728	5.5
T. Rowe Price Associates, Inc. (4)	10,213,726	6.0
The Vanguard Group, Inc. (5)	8,608,643	5.1

* Indicates less than one percent.

(1) Other than BlackRock, Inc., T. Rowe Price Associates, Inc. (“T. Rowe Price”) and The Vanguard Group, Inc. (“Vanguard”), the address for each stockholder listed is: c/o Allegheny Energy, Inc., 800 Cabin Hill Drive, Greensburg, Pennsylvania 15601.

(2) Includes the following options exercisable within 60 days of February 1, 2011: Mr. Evanson—999,023; Mr. Davis—52,560; Mr. Feinberg—102,560; Mr. Gleason—102,560; and Mr. Oliver—62,279.

For Mr. Pappas, excludes 4,000 shares deferred until January 1, 2013. For Mr. Rice, excludes 476 shares owned by his spouse. Mr. Rice owns 5,701 shares jointly with his spouse, and he has shared voting and investment power with respect to such shares. Mr. Sarsten owns 26,858 shares jointly with his spouse, and he has shared voting and investment power with respect to such shares.

The shares shown above exclude deferred cash compensation credited as shares in a phantom stock fund as of February 1, 2011 for the following directors: Mr. Baldwin, 10,326; Mr. Freidheim, 1,303; Ms. Johnson, 10,125; Mr. Kleisner, 635; Mr. Pappas, 1,495; and Mr. Rice, 2,603. Any distribution related to the phantom stock fund will be paid in cash based on the market value of AE’s common stock as of the distribution date.

The shares shown above exclude any performance shares payable pursuant to the applicable agreement if the proposed Merger with FirstEnergy is consummated, as further described in the “Potential Payments Upon Termination or Change in Control” section above. The applicable agreements generally provide that the performance shares are payable on earlier of an executive’s involuntary termination from AE or the end of the award period.

(3) This information is based solely on the Schedule 13G filed by BlackRock, Inc. on February 2, 2011, reporting beneficial ownership of 9,424,728 shares of AE’s common stock as of December 31, 2010. BlackRock, Inc. has sole power to dispose or to direct the disposition of, and sole power to vote or to direct the voting of such shares. The address of BlackRock, Inc. is 40 East 52^nd Street, New York, NY 10022.

(4) This information is based solely on the Schedule 13G filed by T. Rowe Price on February 10, 2011, reporting beneficial ownership of 10,213,726 shares of AE’s common stock as of December 31, 2010.

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T. Rowe Price has sole power to dispose or to direct the disposition of 10,213,726 of such shares, and sole power to vote or to direct the voting of 2,482,945 of such shares. The address of T. Rowe Price is 100 E. Pratt Street, Baltimore MD 21202.

(5) This information is based solely on the Schedule 13G filed by Vanguard on February 10, 2011, reporting beneficial ownership of 8,608,643 shares of AE’s common stock as of December 31, 2010. Vanguard has sole power to dispose or to direct the disposition of 8,395,861 of such shares, and sole power to vote or to direct the voting of 212,782 of such shares. The address of Vanguard is 100 Vanguard Blvd., Malvern, PA 19355.

Change of Control

On February 10, 2010, AE, FirstEnergy, and Element Merger Sub, Inc., a direct wholly-owned subsidiary of FirstEnergy, entered into an Agreement and Plan of Merger. See “Business”, “Risk Factors” and Note 2, “Merger Agreement” to Allegheny’s consolidated financial statements.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related Person Transactions

AE recognizes that transactions between AE and its directors and executive officers or their immediate family members may raise questions as to whether those transactions present potential or actual conflicts of interest and create the appearance that decisions are based on considerations other than the best interests of AE and its stockholders. It is AE’s policy to enter into or ratify these transactions only when AE’s Board or the Governance Committee determines that the transaction is in, or is not inconsistent with, AE’s best interests and those of its stockholders. Accordingly, the Governance Committee charter requires the Governance Committee to review and approve all transactions between AE or any of its subsidiaries and any related person that are required to be disclosed under applicable SEC rules and regulations. The Board has also adopted a formal policy that requires the Governance Committee to review and, if appropriate, to approve or ratify all such related person transactions in an amount exceeding $120,000, subject to certain exclusions further described below. Based on the Governance Committee’s review and the applicable SEC rules and regulations, the Governance Committee determined there were no related person transactions that required disclosure in this Annual Report on Form 10-K.

Pursuant to the policy discussed above, the Governance Committee has delegated to the Governance Committee chairperson the authority to approve any related person transaction if the aggregate amount of the transaction is expected to be less than $2 million. The policy excludes certain categories of transactions that the applicable SEC rules and regulations also exclude from the definition of related person transactions and certain other transactions that the Governance Committee has determined would not constitute a direct or indirect material interest. These excluded transactions include, but are not limited to, transactions that are competitively bid, regulated transactions where the rates or charges are fixed in conformity with law or governmental authority, certain banking-related services, certain transactions that are not in excess of the greater of $1 million or 2% of the other organization’s revenues and transactions where all stockholders receive proportional benefits. The policy further requires that, at least annually, the Governance Committee be provided with a summary of certain transactions, including, but not limited to, each transaction that was approved by the Governance Committee chairperson.

Matters Relating to the Proposed Merger with FirstEnergy

Continued FirstEnergy Board Service

AE and FirstEnergy agreed that two members of the AE Board will be added to the FirstEnergy board effective upon completion of the Merger. Julia L. Johnson and Ted J. Kleisner have been designated to become members of the FirstEnergy board. The other directors of AE will no longer serve as directors of AE (and will

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not serve as directors of FirstEnergy) effective upon completion of the Merger and will become eligible to receive any vested benefits, including any deferred compensation under AE’s non-employee director deferred compensation plan.

Continuing Employment with FirstEnergy

Certain of AE’s current executive officers may serve as employees of FirstEnergy or the surviving entity after the completion of the Merger. However, the Merger Agreement does not require FirstEnergy or the surviving entity to continue or resume the employment of any specific person. FirstEnergy and Paul J. Evanson have entered into an employment agreement, dated as of March 19, 2010, pursuant to which, upon completion of the Merger, Mr. Evanson will serve as executive vice chairman of FirstEnergy reporting to and working at the discretion of Mr. Alexander, FirstEnergy’s chief executive officer. The agreement is to commence upon the completion of the Merger and is for a two year term.

Director Independence

A substantial majority of the members of AE’s Board historically have been independent, and key committees are comprised solely of independent directors. AE’s Board has adopted a Policy Regarding Director Independence Determinations (the “Director Independence Policy”) to assist it in determining director independence in accordance with applicable NYSE and SEC requirements. The Director Independence Policy requires the Board to make an annual determination regarding the independence of each of the directors and sets forth categorical standards for making these determinations that are consistent with the listing standards of the NYSE. The full text of the Director Independence Policy is available on AE’s website, www.alleghenyenergy.com, in the Corporate Governance section.

In 2011, AE’s Board made independence determinations for each Board member, based on recommendations made by the Governance Committee, and affirmatively determined that all of the current directors other than Mr. Evanson are independent. Mr. Evanson is not considered an independent director because of his employment as AE’s President and Chief Executive Officer.

In determining that each of the directors (other than Mr. Evanson) is independent, AE’s Board considered the following business relationships, which it determined were immaterial to the directors’ independence. The Board considered that AE and its subsidiaries in the ordinary course of business have, during the last three years, sold services to and purchased products and/or services from, a company where a director’s immediate family member is an executive officer. The Board also considered that some directors were directors or trustees (but not officers) of companies or institutions to which AE sold services or from which AE purchased products and services during the last three years. In each case, the amount paid to or received from such company in each of the last three years did not exceed the greater of $1 million or 2% of the consolidated gross revenue of that company, which is the threshold set forth in the Director Independence Policy. The Board determined that none of the independent directors have ongoing relationships relevant to an independence determination that were inconsistent with the categorical standards in the Director Independence Policy and that none of the relationships that it considered impaired the independence of these directors. In addition, AE’s directors do not currently provide professional services to AE, its affiliates or any officer of AE and its directors are not related to any executive officer of AE.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit and Other Fees

The following table presents fees for professional audit services rendered by Deloitte & Touche for the years ended December 31, 2010 and 2009, respectively, and fees for other services rendered by Deloitte & Touche during those periods. The Audit Committee’s policy is to pre-approve all audit and non-audit services provided by its independent auditor.

	2010		2009
Audit Fees (1)	$	3,715,625	$	3,571,550
Audit-Related Fees:
Benefit plan audit (2)		50,000		50,000
Reports on the results of agreed upon procedures		26,000		20,000
Merger related due diligence		308,000		0
Other (3)		4,000		3,600
Total Audit-Related Fees	$	388,000	$	73,600
Tax Fees	$	—	$	—
All Other Fees	$	—	$	—
Total	$	4,103,625	$	3,645,150

(1) Consisted of fees and expenses related to the integrated audit of AE’s annual consolidated financial statements, the audit of the separate financial statements of certain subsidiaries, including certain statutory audits, reviews of quarterly financial statements and comfort letters issued in connection with debt offerings. For 2010, this amount included $1,113,825 paid in 2011 and, for 2009, this amount included $923,650 paid in 2010.

(2) Paid directly by the benefit plan trust.

(3) Other Audit-Related Fees consisted of subscription fees to access Deloitte & Touche’s technical accounting research tool.

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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 192.

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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 23, 2011

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 23, 2011
(ii)	Principal Financial Officer:
	/s/ Kirk R. Oliver         (Kirk R. Oliver)	Senior Vice President and Chief Financial Officer	February 23, 2011
(iii)	Principal Accounting Officer:
	/s/ William F. Wahl, III         (William F. Wahl, III)	Vice President, Controller and Chief Accounting Officer	February 23, 2011
(iv)	Directors:
	/s/ H. Furlong Baldwin         (H. Furlong Baldwin)	/s/ Ted J. Kleisner         (Ted J. Kleisner)
	/s/ Eleanor Baum         (Eleanor Baum)	/s/ Christopher D. Pappas         (Christopher D. Pappas)
	/s/ Paul J. Evanson         (Paul J. Evanson)	/s/ Steven H. Rice         (Steven H. Rice)	February 23, 2011
	/s/ Cyrus F. Freidheim, Jr.         (Cyrus F. Freidheim, Jr.)	/s/ Gunnar E. Sarsten         (Gunnar E. Sarsten)
	/s/ Julia L. Johnson         (Julia L. Johnson)	/s/ Michael H. Sutton         (Michael H. Sutton)

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CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-160988 on Form S-3 and Registration Statement Nos. 333-65657, 333-31610, 333-40432, 333-113660, 333-117117, 333-151647, 333-119397 and 333-161811 on Form S-8 of our reports dated February 23, 2011, relating to the consolidated financial statements and financial statement schedules of Allegheny Energy, Inc. and subsidiaries and the effectiveness of Allegheny Energy, Inc. and subsidiaries’ internal control over financial reporting, appearing in the Annual Report on Form 10-K of Allegheny Energy, Inc. for the year ended December 31, 2010.

/s/ Deloitte & Touche LLP

Pittsburgh, Pennsylvania

February 23, 2011

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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 KIRK R. OLIVER , 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, 2010, 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 23, 2011

/s/ H. Furlong Baldwin         (H. Furlong Baldwin)	/s/ Ted J. Kleisner         (Ted J. Kleisner)
/s/ Eleanor Baum         (Eleanor Baum)	/s/ Christopher D. Pappas         (Christopher D. Pappas)
/s/ Paul J. Evanson         (Paul J. Evanson)	/s/ Steven H. Rice         (Steven H. Rice)
/s/ Cyrus F. Freidheim, Jr.         (Cyrus F. Freidheim, Jr.)	/s/ Gunnar E. Sarsten         (Gunnar E. Sarsten)
/s/ Julia L. Johnson         (Julia L. Johnson)	/s/ Michael H. Sutton         (Michael H. Sutton)

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EXHIBIT INDEX

(Rule 601(a))

	Documents	Incorporation by Reference
2.1**	Agreement and Plan of Merger, dated as of February 10, 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny Energy, Inc.	Form 8-K filed February 11, 2010, ex. 2.1
2.2	Amendment No 1, dated as of June 4, 2010, to Agreement and Plan of Merger, by and among FirstEnergy Corp, Element Merger Sub, Inc. and Allegheny Energy, Inc.	Form 8-K filed June 9, 2010, ex. 10.1
3.1	Articles of Restatement, dated September 4, 2008	Form 10-Q filed November 6, 2008, ex. 3.1
3.2	Amended & Restated By-laws of the Company adopted December 3, 2009	Form 8-K filed December 9, 2009, ex. 3.1
10.1	Amended and Restated Revised Plan for Deferral of Compensation of Directors	Form 8-K filed October 6, 2006, ex. 99.1
10.2	Amended and Restated Revised Plan for Deferral of Compensation of Directors	Form 10-Q filed November 7, 2007, ex. 10.4
10.3	Allegheny Energy Amended and Restated Supplemental Executive Retirement Plan	Form 10-K filed December 31, 2005, ex. 10.4
10.4	Allegheny Energy Amended and Restated Supplemental Executive Retirement Plan	Form 10-Q filed November 7, 2007, ex. 10.8
10.5	Executive Life Insurance Program and Collateral Assignment Agreement	Form 10-K filed December 31, 1994, ex. 10.5
10.6	Restricted Stock Plan for Outside Directors	Form 10-K filed December 31, 1998, ex. 10.7
10.7	Amended and Restated Restricted Stock Plan for Outside Directors	Form 10-Q filed November 7, 2007, ex. 10.3
10.8	Deferred Stock Unit Plan for Outside Directors	Form 10-K filed December 31, 1997, ex. 10.8
10.9	Allegheny Energy, Inc. 2004 Non-Employee Director Stock Plan	Schedule 14A Definitive Proxy Statement filed April 4, 2004, Annex A
10.10	Allegheny Energy, Inc. Amendment 2010-1, dated as of December 9, 2010 to Amended and Restated Annual Incentive Plan	Form 8-K filed December 15, 2010, ex. 10.1
10.11	Allegheny Energy, Inc. Amended and Restated Annual Incentive Plan	Form 10-Q filed November 7, 2007, ex. 10.7
10.12	Form of Stock Option Agreement	Form 10-K filed December 31, 2004 ex. 10.12
10.13	Stock Unit Plan	Form 10-K filed December 31, 2004, ex. 10.13
10.14	Amended and Restated Stock Unit Plan	Form 10-Q filed November 7, 2007, ex. 10.7
10.15	Form of Stock Unit Agreement	Form 10-K filed December 31, 2004, ex. 10.14
10.16	Allegheny Energy, Inc. 1998 Long-Term Incentive Plan revised as of January 1, 2004	Form 10-Q filed March 31, 2004, ex. 10.1
10.17	Allegheny Energy, Inc. 1998 Long-Term Incentive Plan amended and restated as of January 1, 2008	Form 10-Q filed November 7, 2007, ex. 10.5
10.18	Allegheny Energy, Inc. 2008 Long-Term Incentive Plan	Schedule 14A Definitive Proxy Statement filed March 20, 2008, Annex B
10.19	Executive Severance Plan	Form 8-K filed July 16, 2008, ex. 10.1

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	Documents	Incorporation by Reference
10.20	Executive Change in Control Severance Plan	Form 8-K filed July 16, 2008, ex. 10.2
10.21	Amended and Restated Employment Agreement with Chief Executive Officer	Form 8-K filed July 10, 2009, ex. 10.1
10.22	Employment Agreement of Vice President, Human Resources	Form 8-K filed January 6, 2006, ex. 10.1
10.23	Amended and Restated Non-Employee Director Stock Plan	Form 10-Q filed November 7, 2007, ex. 10.2
10.24	Amended and Restated Nonqualified Deferred Compensation Plan	Form 10-Q filed November 7, 2007, ex. 10.9
10.25	Amendment to Employment Agreement of Vice President	Form 10-Q filed November 7, 2007, ex. 10.11
10.26	Credit Agreement, dated as of September 24, 2009, among Allegheny Energy Supply Company, LLC, certain lenders party thereto and Bank of America, N.A., as Administrative Agent.	Form 10-Q filed November 9, 2009, ex. 10.4
10.27*	Alliance Agreement for Engineering, Construction and Project Management for the Trans-Allegheny Interstate Line Project, dated February 28, 2007, by and between Trans-Allegheny Interstate Line Company and Kenny Construction Company	Form 10-Q filed May 8, 2007, ex. 10.1
10.28*	Limited Liability Agreement of Potomac-Appalachian Transmission Highline, LLC, dated as of September 1, 2007	Form 10-Q filed November 7, 2007, ex. 10.1
10.29	Credit Agreement, dated as of December 18, 2009, among Monongahela Power Company, certain lenders party thereto and The Bank of Nova Scotia as Administrative Agent	Form 8-K filed December 23, 2009, ex. 10.1
10.30	Credit Agreement, dated as of January 25, 2010, among Trans-Allegheny Interstate Line Company, certain lenders party thereto and BNP Paribas, as Administrative Agent.	Form 8-K filed January 28, 2010, ex. 10.1
10.31	Amended and Restated Credit Agreement, dated as of August 15, 2008, among Trans-Allegheny Interstate Line Company, certain lenders party thereto and Citibank, N.A., as Administrative Agent	Form 10-Q filed November 6, 2008, ex. 10.1
10.32	Equity Commitment Agreement, dated as of August 15, 2008, between Allegheny Energy, Inc. and Union Bank of California, as Collateral Agent	Form 10-Q filed November 6, 2008, ex. 10.2 and Form 10-Q filed November 9, 2009, ex. 10.10
10.33	Pledge Agreement, dated as of August 15, 2008, between Allegheny Energy, Inc. and Union Bank of California, as Collateral Agent	Form 10-Q filed November 6, 2008, ex. 10.3 and Form 10-Q filed November 9, 2009, ex. 10.11
10.34	Amendment Letter, dated as of February 10, 2010, in respect of the Credit Agreement, dated as of September 24, 2009, among Allegheny Energy Supply Company, LLC, the Lenders party thereto, and Bank of America, N.A., as Administrative Agent.	Form 8-K filed February 11, 2010, ex. 10.1
10.35	Amendment Letter, dated as of February 10, 2010, in respect of the Credit Agreement, dated as of May 22, 2006, among Allegheny Energy, Inc., Allegheny Energy Supply Company, LLC, the Lenders party thereto, and Citicorp North America, Inc. as Administrative Agent.	Form 8-K filed February 11, 2010, ex. 10.2
10.36	Amendment Letter, dated as of February 10, 2010, in respect of the Credit Agreement, dated as of December 18, 2009, among Monongahela Power Company, the Lenders party thereto, and The Bank of Nova Scotia, as Administrative Agent.	Form 8-K filed February 11, 2010, ex. 10.3

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	Documents	Incorporation by Reference
10.37	Amendment Letter, dated as of February 10, 2010, in respect of the Credit Agreement, dated as of January 25, 2010, among Trans-Allegheny Interstate Line Company, the Lenders party thereto, and BNP Paribas, as Administrative Agent.	Form 8-K filed February 11, 2010, ex. 10.4
10.38	Credit Agreement, dated as of April 30, 2010, among Allegheny Energy, Inc., certain lenders party thereto and Union Bank, N.A., as Administrative Agent	Form 8-K filed May 6, 2010, ex. 10.1
10.39	Credit Agreement, dated as of April 30, 2010, among The Potomac Edison Company, certain lenders party thereto, and Commerzbank, A.G., as Administrative Agent	Form 8-K filed May 6, 2010, ex. 10.2
10.40	Credit Agreement, dated as of April 30, 2010, among West Penn Power Company, certain lenders party thereto, and PNC Bank, National Association, as Administrative Agent	Form 8-K filed May 6, 2010, ex. 10.3
10.41	Subsidiaries’ Indentures described below
12	Computation of ratio of earnings to fixed charges	Filed herewith
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—100%	Delaware
	Allegheny Energy Supply Hunlock Creek, LLC—100%	Delaware
	Allegheny Energy Transmission, LLC—100%	Delaware
	Green Valley Hydro, LLC—100%	Virginia
	Ohio Valley Electric Corporation—3.50%	Ohio
23.1	Consent of Independent Registered Public Accounting Firm	See page 229 herein.
24	Powers of Attorney	See page 230 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

101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

* Confidential treatment has been requested from the commission for portions of this document.

** Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Allegheny will furnish the omitted schedules to the SEC upon request by the Commission.

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