LOGO

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

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) of the SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

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
NO_X		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

LOGO

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

iii

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

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.

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

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.

•

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

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.

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.

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;

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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;

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results of operations;

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internal controls and procedures;

•

capital expenditures;

•

status and condition of plants and equipment;

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

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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;

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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;

•

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;

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

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

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

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environmental regulations;

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

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

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

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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;

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the availability of credit;

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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.”

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.

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.

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.

(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.

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.

LOGO

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.

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.

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.

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

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

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

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:

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a return on equity of 14.3%;

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a return on CWIP;

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

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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.”

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.

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:

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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

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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.

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

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.

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:

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

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

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

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

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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

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

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.

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

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.

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.

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:

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maintaining an accurate CO₂ emissions database;

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

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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

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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 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 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.

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.

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

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.

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.

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.

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.

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.

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.”

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.

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.

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

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

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:

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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;

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

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transmission constraints;

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

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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

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.

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.

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;

•

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.

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

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.

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

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.

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
1^st Quarter	$	23.99	$	20.40	$	35.97	$	20.32
2^nd Quarter	$	23.47	$	18.97	$	29.85	$	22.70
3^rd Quarter	$	24.78	$	20.01	$	27.70	$	23.42
4^th 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.

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.

LOGO


	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.

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.

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

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:

•

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.

•

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,

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.”

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

Financial results for each segment were as follows:


(In millions)	Merchant Generation			Regulated Operations			Eliminations			Allegheny Consolidated
2010	Merchant Generation			Regulated Operations			Eliminations			Allegheny Consolidated
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


(In millions)	Merchant Generation			Regulated Operations			Eliminations			Allegheny Consolidated
2008	Merchant Generation			Regulated Operations			Eliminations			Allegheny Consolidated
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

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

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

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.

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.

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

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%.

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.

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.

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


(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

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.

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.

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%.

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,

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

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.

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.

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.

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 2010		Projected
(in millions)	Actual 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		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

(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)

(c)

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.

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.

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.

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.

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.

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

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.

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

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,

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.

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.

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.

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

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


(In millions, except per share amounts)	Year ended December 31,
(In millions, except per share amounts)	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		$

ALLEGHENY ENERGY, INC 10-K