Allegheny Energy 10K 2007 Annual report

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, 2007

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

ALLEGHENY ENERGY, INC.

(Name of Registrant)


Maryland		13-5531602
(State of Incorporation) 800 Cabin Hill Drive, Greensburg, Pennsylvania		(IRS Employer Identification Number)

(Address of Principal Executive Offices)		15601 (Zip Code)

(724) 837-3000

(Telephone Number)

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 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. x

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

As of December 31, 2007, 167,223,576 shares of the common stock, par value of $1.25 per share, of the registrant were outstanding.

Documents Incorporated by Reference

Portions of the Allegheny Energy, Inc. definitive Proxy Statement for its 2008 Annual Meeting of Stockholders are incorporated by reference to Part III of this Annual Report on Form 10-K.

GLOSSARY

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


ACC		Allegheny Communications Connect, Inc., a subsidiary of Allegheny Ventures
AE		Allegheny Energy, Inc., a diversified utility holding company
AESC		Allegheny Energy Service Corporation, a subsidiary of AE
AE Solutions		Allegheny Energy Solutions, Inc., a subsidiary of Allegheny Ventures
AE Supply		Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC		Allegheny Generating Company, an unregulated generation subsidiary of AE Supply and Monongahela
Allegheny		Allegheny Energy, Inc., together with its consolidated subsidiaries
Allegheny Ventures		Allegheny Ventures, Inc., a nonutility, unregulated subsidiary of AE
Distribution Companies		Monongahela, Potomac Edison and West Penn, which collectively do business as Allegheny Power
Green Valley Hydro		Green Valley Hydro, LLC, a subsidiary of AE
Monongahela		Monongahela Power Company, a regulated subsidiary of AE
PATH, LLC		Potomac-Appalachian Transmission Highline, LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc.
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:


CDD		Cooling Degree-Days
Clean Air Act		Clean Air Act of 1970
CO₂		Carbon dioxide
DOE		United States Department of Energy
EPA		United States Environmental Protection Agency
Energy Policy Act		Energy Policy Act of 2005
Exchange Act		Securities Exchange Act of 1934, as amended
FERC		Federal Energy Regulatory Commission, an independent commission within the DOE
FPA		Federal Power Act
GAAP		Generally accepted accounting principles used in the United States of America
HDD		Heating Degree-Days
kW		Kilowatt, which is equal to 1,000 watts
kWh		Kilowatt-hour, which is a unit of electric energy equivalent to one kW operating for one hour
Maryland PSC		Maryland Public Service Commission
MW		Megawatt, which is equal to 1,000,000 watts
MWh		Megawatt-hour, which is a unit of electric energy equivalent to one MW operating for one hour
NSR		The New Source Performance Review Standards, or “New Source Review,” applicable to facilities deemed “new” sources of emissions by the EPA
OVEC		Ohio Valley Electric Corporation
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
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

CONTENTS


Item 1.	Business	5
	Overview	5
	Special Note Regarding Forward-Looking Statements	12
	Allegheny’s Sales And Revenues	14
	Capital Expenditures	15
	Electric Facilities	16
	Fuel, Power And Resource Supply	20
	Regulatory Framework Affecting Allegheny	22
	Environmental Matters	35
	Employees	40
	Executive Officers	41

Item 1A.	Risk Factors	42

Item 1B.	Unresolved Staff Comments	51

Item 2.	Properties	52

Item 3.	Legal Proceedings	53

Item 4.	Submission Of Matters To A Vote Of Security Holders	55

Item 5.	Market For The Registrant’s Common Equity, Related Stockholder Matters	56

Item 6.	Selected Financial Data	58

Item 7.	Management’s Discussion And Analysis Of Financial Condition And Results Of Operations	59

Item 7A.	Quantitative And Qualitative Disclosures About Market Risk	98

Item 8.	Financial Statements And Supplementary Data	100

Item 9.	Changes In And Disagreements With Accountants On Accounting And Financial Disclosure	173

Item 9A.	Controls And Procedures	173

Item 9B.	Other Information	174

Item 10.	Directors And Executive Officers	175

Item 11.	Executive Compensation	175

Item 12.	Security Ownership Of Certain Beneficial Owners And Management And Related Stockholder Matters	175

Item 13.	Certain Relationships And Related Transactions	175

Item 14.	Principal Accountant Fees And Services	175

Item 15.	Exhibits And Financial Statement Schedules	176

Signatures		177

PART I

ITEM 1. BUSINESS

OVERVIEW

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

Allegheny has two business segments:

•

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

•

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

The Delivery and Services Segment

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

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The Distribution Companies include Monongahela (excluding its West Virginia generation assets), Potomac Edison and West Penn. Each of the Distribution Companies is a public utility company and does business under the trade name Allegheny Power. Allegheny Power’s principal business is the operation of electric public utility systems. In April 2002, the Distribution Companies transferred functional control over their transmission systems to PJM. As a 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.

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Monongahela was incorporated in Ohio in 1924. It conducts an electric T&D business that serves approximately 378,600 customers in northern West Virginia in a service area of approximately 12,400 square miles with a population of approximately 783,000. Monongahela’s Delivery and Services segment had operating revenues of $650.8 million and sold 10.8 billion kWhs of electricity to retail customers in 2007. Monongahela also owns generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below.

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Potomac Edison was incorporated in Maryland in 1923 and was also incorporated in Virginia in 1974. It operates an electric T&D system in portions of West Virginia, Maryland and Virginia. Potomac Edison serves approximately 475,000 customers in a service area of about 7,300 square miles with a population of approximately 1.05 million. Potomac Edison had total operating revenues of $888.2 million and sold 13.5 billion kWhs of electricity to retail customers in 2007.

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West Penn was incorporated in Pennsylvania in 1916. It operates an electric T&D system in southwestern, south-central and northern Pennsylvania. West Penn serves approximately 711,000 customers in a service area of about 9,900 square miles with a population of approximately 1.5 million. West Penn had total operating revenues of $1.3 billion and sold 20.5 billion kWhs of electricity to retail customers in 2007.

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TrAIL Company was incorporated in Maryland and Virginia in 2006. In June 2006, PJM, which manages a regional planning process for transmission expansion, approved a regional transmission expansion plan designed to maintain the reliability of the transmission grid in the Mid-Atlantic region. The transmission expansion plan includes TrAIL, a new 240-mile 500 kV transmission line, 210 miles of which is to be located in the Distribution Companies’ PJM zone. 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 own and operate the new transmission line.

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PATH, LLC was formed in Delaware in 2007 as a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc. (“AEP”) following PJM approval of PATH, a 290-mile, high-voltage transmission line. PATH will include approximately 244 miles of 765 kV transmission line and approximately 46 miles of twin-circuit 500 kV transmission lines and will extend from AEP’s substation near St. Albans, West Virginia, to a new substation near Kemptown, 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 AEP and, through an operating subsidiary, will build, own and operate the portion of the line extending from AEP’s Amos substation to Allegheny’s Bedington substation. The “Allegheny Series” is 100% owned by Allegheny and, through an operating subsidiary, will build, own and operate the portion of the line extending from Bedington to the new substation near Kemptown, Maryland.

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Allegheny Ventures is a nonutility, unregulated subsidiary of AE that was incorporated in Delaware in 1994. Allegheny Ventures engages in telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal wholly-owned subsidiaries, ACC and AE Solutions. Both ACC and AE Solutions are Delaware corporations. ACC develops fiber-optic projects, including fiber and data services. AE Solutions manages energy-related projects. Allegheny Ventures had total operating revenues of $9.1 million in 2007.

During 2007, the Delivery and Services segment had operating revenues of $2.8 billion and net income of $117.7 million. As of December 31, 2007, the Delivery and Services segment held approximately $4.6 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 16, “Business Segments,” to the Consolidated Financial Statements.

The Generation and Marketing Segment

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

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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, 2007, AE Supply owned or contractually controlled approximately 6,896 MWs of generation capacity. See “Electric Facilities” below.

AE Supply markets its electric generation capacity to various customers and markets. AE Supply currently is contractually obligated to provide Potomac Edison and West Penn with the power that they need to meet a majority of their PLR obligations, which represents a majority of AE Supply’s normal operating capacity. AE Supply had total operating revenues of $1.6 billion in 2007.

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Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment. As of December 31, 2007, Monongahela owned or contractually controlled 2,806 MWs of generation capacity. See “Electric Facilities” below.

Monongahela’s generation capacity supplies Monongahela’s Delivery and Services segment. 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’s Generation and Marketing segment had operating revenues of $555.2 million in 2007.

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AGC was incorporated in Virginia in 1981. As of December 31, 2007, 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 1,059 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC had total operating revenues of $67.4 million in 2007. See “Electric Facilities” below.

In addition to coordinating the movement of wholesale electricity in its region and managing regional plans for generation and transmission expansion, PJM operates a competitive wholesale energy market. 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 PJM market and purchase power from the PJM market to meet their contractual obligations to supply power. See “Fuel, Power and Resource Supply” and “Regulatory Framework Affecting Allegheny” below.

During 2007, the Generation and Marketing segment had operating revenues of $2.1 billion and net income of $294.5 million. As of December 31, 2007, the Generation and Marketing segment held approximately $5.3 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 16, “Business Segments,” to the Consolidated Financial Statements.

Intersegment 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, AE Supply, AGC, the Distribution Companies, Allegheny Ventures, 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 4,355 employees as of December 31, 2007.

Initiatives and Achievements

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

Significant initiatives and recent achievements include:

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Transmission Expansion. In June 2006, PJM approved a regional transmission expansion plan designed to maintain the reliability of the transmission grid in the Mid-Atlantic region that includes TrAIL, and in June 2007, PJM authorized the construction of PATH. These new lines are designed to alleviate future reliability concerns and increase the west to east transmission capability of the PJM transmission system. PJM designated Allegheny to construct the portion of TrAIL that will be located in the Distribution Companies’ PJM zone, and Allegheny and AEP have formed a joint venture to construct PATH. FERC approved four incentive rate treatments, which are intended to promote the construction of transmission facilities, for TrAIL. PATH, LLC has applied for incentive rate treatment for PATH. Additionally, the DOE designated the region in which both projects are proposed to be located as a National Interest Electric Transmission Corridor. Allegheny currently is in the process of seeking requisite permits and regulatory approvals.

Allegheny also is taking additional steps to enhance the performance and reliability of its transmission system. For example, in December 2007, Allegheny completed the installation and start-up of the world’s largest Static VAR Compensator, or “SVC,” located at its Black Oak transmission substation, near Rawlings, Maryland. The new SVC is expected to enhance the reliability of Allegheny’s high-voltage Black Oak-Bedington transmission line, which is one of the most congested transmission lines in the PJM region, and increase transmission capacity across the PJM region.

•

Environmental Compliance and Risk Management. Allegheny is working to effectively manage its environmental compliance efforts to ensure continuing compliance with applicable federal and state regulations while controlling its compliance costs, reducing emissions levels and minimizing its risk exposure.

Among other initiatives, AE Supply and Monongahela completed the elimination of a partial Scrubber bypass at the Pleasants generation facility in 2007, are constructing Scrubbers at the Hatfield’s Ferry generation facility in Pennsylvania and the Fort Martin generation facility in West Virginia, and are also

evaluating other pollution control projects at other facilities. Additionally, AE Supply and Monongahela are currently blending lower-sulfur Powder River Basin (“PRB”) coal at several generation facilities. See “Environmental Matters” below.

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Energy Efficiency and Conservation. Through its Watt Watchers program introduced in 2007, Allegheny has implemented a number of programs to encourage energy efficiency and conservation among its customers, in addition to its long-standing portfolio of existing energy conservation programs. In August 2007, for example, Allegheny announced its partnership with ENERGY STAR^®, the EPA’s voluntary, market-based program to reduce greenhouse gasses through energy efficiency. As part of this initiative, Allegheny joined the “Change a Light, Change the World” campaign, a national program to encourage consumers to replace at least one standard light bulb with a longer-lasting, more efficient bulb that has earned the ENERGY STAR^® label. Customers can pledge to replace the lights in their homes and can purchase compact fluorescent light bulbs and other energy-efficient products through Allegheny’s website. Also as part of its Watt Watchers program, Allegheny has worked to educate students in its region about energy conservation by, among other things, providing free educational materials on energy conservation and safety.

Allegheny also is pursuing options for “green” energy sourcing for its customers. In November, 2007, Allegheny filed an application with the Pennsylvania PUC to offer a voluntary wind energy program to customers in Pennsylvania, and Allegheny continues to explore other programs through which customers can purchase electricity from renewable sources.

Allegheny is developing a number of other new programs for customers that it believes can help drive energy efficiency and conservation, such as: helping customers conduct home energy audits; conducting workshops for business customers to encourage participation in utility demand reduction programs; and launching an automated metering pilot program to help customers better understand and manage their energy usage.

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Investment Grade Status and Common Stock Dividend. Allegheny’s extensive efforts since 2003 to improve its credit profile by repaying debt and improving liquidity, along with the overall improvements in Allegheny’s financial condition, led to the achievement of a significant milestone in 2007 with the upgrade to investment grade of Allegheny’s corporate credit ratings by all three major credit rating agencies. In May 2007, Standard & Poor’s upgraded AE’s corporate credit rating from BB+ to BBB-, marking Allegheny’s return to investment grade status, and in September 2007, Moody’s Investor Services upgraded AE’s corporate family rating from Ba2 to Baa3. In December 2007, Fitch Ratings upgraded AE’s issuer default rating and unsecured debt rating from BB+ to BBB-.

With Allegheny’s return to investment grade status, AE reinstated its common stock dividend, ending a suspension that began in 2002, when Allegheny was in financial distress. In October 2007, AE’s Board of Directors declared a cash dividend on AE’s common stock of $0.15 per share, and in February 2008, the Board declared a dividend of $0.15 per share. See Note 8, “Dividend Restrictions” to the Consolidated Financial Statements.

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Transition to Market-based Rates. Each of the states in Allegheny’s service territory other than West Virginia has, to some extent, deregulated its electric utility industry. Pennsylvania and Maryland have instituted customer choice and are transitioning to market-based, rather than cost-based pricing for generation. Virginia undertook to deregulate the provision of generation services beginning in 1999, but recent legislation in Virginia will result in re-regulation of these services as of January 1, 2009 for most customers. In West Virginia, the rates charged to retail customers are regulated by the West Virginia PSC and are determined through traditional, cost-based, regulated utility rate making.

In March 2007, the Maryland PSC approved a rate stabilization and transition plan proposed by Potomac Edison for its residential customers in Maryland that is intended to gradually transition residential customers from capped generation rates to generation rates based on market prices beginning in 2007 and ending in 2010. Under the plan, residential customers who did not opt out of the plan began

paying a distribution surcharge beginning in June 2007, which will result in an overall rate increase of approximately 15% annually from 2007 to 2010. 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 will convert to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, will be returned to customers as a credit on these customers’ electric bills, thereby reducing the effect of the rate cap expiration. The credit will continue, with adjustments, to maintain rate stability until December 31, 2010. See “Regulatory Framework Affecting Allegheny” and “Fuel, Power and Resource Supply” below.

In 2005, Allegheny successfully implemented a plan to transition Pennsylvania customers to generation rates based on market prices through increases in applicable rate caps in 2007, 2009 and 2010 and a two-year extension of the applicable transition period. Together with previously approved rate cap increases for 2006 and 2008, these increases are intended to gradually move generation rates in Pennsylvania closer to market prices. See “Risk Factors” below.

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

While its recent requests for rate increases in West Virginia and Virginia have for the most part been denied by the relevant state regulatory commissions, Allegheny was able to obtain approval from the West Virginia PSC for the reinstatement of a fuel and purchased power cost recovery clause in West Virginia and from the Virginia SCC for partial recovery of purchased power costs. Allegheny continues to appeal the decisions of the West Virginia PSC and Virginia SCC with respect to its rates in those jurisdictions. See “Regulatory Framework Affecting Allegheny” and “Risk Factors—Risks Relating to Regulation” below and Note 4, “Rates and Regulation” to the Consolidated Financial Statements.

As discussed above, in April 2005, Allegheny obtained approval from the Pennsylvania PUC for increases in applicable rate caps in 2007, 2009 and 2010 in connection with a two-year extension of the period during which Pennsylvania customers will transition to market prices. In addition, AE Supply won the contracts to serve the PLR customer load in Pennsylvania in 2009 and 2010 and entered into contracts to provide power to Potomac Edison to serve commercial, industrial and outdoor lighting customer loads in Maryland and customer load for all classes in Virginia.

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Plant Availability and Operational Efficiency. Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation facilities (those that utilize steam pressure in excess of 3,200 pounds per square inch). In 2007, Allegheny completed an extensive special maintenance program, which it began in 2005, at each of its 10 supercritical generating units, targeted at improving the availability of those units.

Allegheny is continuously working to identify and develop opportunities to optimize operating processes, increase productivity and reduce or contain operation and maintenance expenses where appropriate.

For example, in January 2007, Allegheny successfully implemented an enterprise resource planning system as part of its program to improve its processes and technology. As part of the same initiative, Allegheny entered into an agreement in 2005 to outsource many of its information technology functions.

Additionally, Allegheny has entered into various coal supply contracts in an effort to ensure a consistent supply of coal at predictable prices, and currently has commitments in place for the delivery of approximately 95% of its expected coal needs for 2008. See “Fuel, Power and Resource Supply” below.

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High Customer Satisfaction. Allegheny continues to see high levels of satisfaction among its customers. For example, in 2007, a leading independent survey firm ranked Allegheny second in customer satisfaction for residential customers and business customers in the eastern United States and fourth in residential customer satisfaction nationwide, while another leading independent survey firm

ranked Allegheny first in customer satisfaction among commercial and industrial customers in the northeast. Allegheny remains focused on maintaining or improving customer satisfaction levels.

Management’s priorities for 2008 include continued focus on improving operations, environmental stewardship, managing the transition to market-based rates, maintaining high levels of customer satisfaction and expanding Allegheny’s transmission system.

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 athttp://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 athttp://www.alleghenyenergy.com as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. Audited annual financial statements for AE Supply also are available on AE’s website. 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. Words such as anticipate, expect, project, intend, plan, believe and words and terms of similar substance used in connection with any discussion of future plans, actions or events identify forward-looking statements. These include statements with respect to:

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regulatory matters, including but not limited to environmental regulation, state rate regulation, and the status of retail generation service supply competition in states served by the Distribution Companies;

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financing plans;

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market demand and prices for energy and capacity;

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

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PLR and power supply contracts;

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results of litigation;

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results of operations;

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internal controls and procedures;

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capital expenditures;

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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; and

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capacity purchase commitments.

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

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

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plant performance and unplanned outages;

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volatility and changes in the price and demand for energy and capacity;

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volatility and changes in the price of coal, natural gas and other energy-related commodities and Allegheny’s ability to enter into long term fuel purchase agreements;

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changes in the weather and other natural phenomena;

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

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changes in market rules, including changes to PJM’s participant rules and tariffs;

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the loss of any significant customers or suppliers;

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

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

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

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changes in access to capital markets, the availability of credit and actions of rating agencies;

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inflationary and interest rate trends;

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the effect of accounting pronouncements issued periodically by accounting standard-setting bodies and accounting issues facing Allegheny;

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general economic and business conditions; and

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

ALLEGHENY’S SALES AND REVENUES

Generation and Marketing

The Generation and Marketing segment had operating revenues of $2.1 billion and $1.8 billion in 2007 and 2006, respectively. For more information regarding the Generation and Marketing segment’s operating revenues, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below and Note 16, “Business Segments,” to the Consolidated Financial Statements.

Delivery and Services

The Delivery and Services segment sold 44.9 billion and 43.2 billion kWhs of electricity to retail customers in 2007 and 2006, respectively. The Delivery and Services segment had operating revenues of $2.8 billion and $2.7 billion in 2007 and 2006, respectively. These revenues included revenue from electric sales and unregulated services. There were $1.7 billion and $1.4 billion of intersegment sales and revenues between the Generation and Marketing segment and the Delivery and Services segment in 2007 and 2006, respectively, which have been eliminated in Allegheny’s statement of income. The following table describes the segment’s revenues from electric sales:


Revenues (in millions):	2007		2006
Retail electric:
Generation	$	1,813.2	$	1,688.0
Transmission		166.0		160.3
Distribution		698.9		682.8

Subtotal retail	$	2,678.1	$	2,531.1

Transmission services and bulk power		110.1		150.7
Other affiliated and nonaffiliated energy services		41.0		35.9

Total Delivery and Services revenues	$	2,829.2	$	2,717.7

For more information regarding the Delivery and Services segment’s revenues, see “Management’s Discussion and Analysis of Financial Condition and Operating Results” below and Note 16, “Business Segments,” to the Consolidated Financial Statements.

CAPITAL EXPENDITURES

Actual capital expenditures for 2007 and estimated capital expenditures for 2008 and 2009 are shown on a cash basis in the following table. The amounts and timing of capital expenditures are subject to continuing review and adjustment, and actual capital expenditures may vary from these estimates.


	Actual		Projected
(In millions)	2007		2008		2009
Transmission and distribution facilities:
TrAIL and related transmission expansion (a)	$	65	$	255	$	360
PATH Project (b)		0		45		165
Other transmission and distribution facilities		209		265		285
Environmental:
Fort Martin Scrubbers (c)		96		295		140
Hatfield Scrubbers (d)		288		340		80
Other		69		80		60
Other generation facilities		91		60		70
Other capital expenditures		30		10		15

Total capital expenditures	$	848	$	1,350	$	1,175

AFUDC and capitalized interest included above	$	24	$	40	$	15

(a)	Includes expenditures for the TrAIL Project, which has a target completion date of 2011 and an estimated cost, excluding AFUDC, of approximately $820 million, as well as expenditures for other related transmission projects requested by PJM.

(b)

Reflects total expenditures for the PATH Project to be paid by PATH, LLC, a joint venture with AEP, in the years shown. The PATH Project has a target completion date of 2012. Excluding AFUDC, total project costs of the West Virginia Series, which is owned equally by Allegheny and AEP, are expected to be approximately $1.2 billion, and total project costs of the Allegheny Series, which is owned by Allegheny, are expected to be approximately $0.6 billion.

(c)	Construction of the Scrubbers at Allegheny’s Fort Martin generation facility is expected to be completed in 2009 at an estimated cost, excluding AFUDC, of approximately $550 million.

(d)	Construction of the Scrubbers at Allegheny’s Hatfield’s Ferry generation facility is expected to be completed in 2009 at an estimated cost, excluding capitalized interest, of approximately $725 million.

ELECTRIC FACILITIES

Generation Capacity

All of Allegheny’s owned or controlled generation capacity is part of the Generation and Marketing segment. In addition, the Distribution Companies are obligated to purchase 479 MWs of power through state utility commission-approved arrangements pursuant to PURPA. This PURPA capacity is part of the Delivery and Services segment, except that, effective January 1, 2007, the PURPA capacity for which Monongahela contracts is part of the Generation and Marketing segment. Allegheny’s generation capacity is more fully described in the tables titled “Nominal Maximum Operational Generation Capacity” and “PURPA Capacity” below.

Nominal Maximum Operational Generation Capacity (MW)


Stations	Units	Project Total	Regulated	Unregulated	Service Commencement Dates (b)
Stations	Units	Project Total	Monongahela (a)	AE Supply and Other (a)	Service Commencement Dates (b)
Coal Fired-Supercritical (Steam):
Harrison (Haywood, WV)	3	1,983	407	1,576	1972-74
Hatfield’s Ferry (Masontown, PA)	3	1,710		1,710	1969-71
Pleasants (Willow Island, WV)	2	1,300	100	1,200	1979-80
Fort Martin (Maidsville, WV)	2	1,107	1,107		1967-68

Coal Fired-Other (Steam):
Armstrong (Adrian, PA)	2	356		356	1958-59
Albright (Albright, WV)	3	292	292		1952-54
Mitchell (Courtney, PA)	1	288		288	1963
Ohio Valley Electric Corp. (Chelsea, OH) (Madison, IN) (c)	11	78	78
Willow Island (Willow Island, WV)	2	243	243		1949-60
Rivesville (Rivesville, WV)	2	142	142		1943-51
R. Paul Smith (Williamsport, MD)	2	116		116	1947-58

Pumped-Storage and Hydro:
Bath County (Warm Springs, VA) (d)	6	1,059	437	622	1985; 2001
Lake Lynn (Lake Lynn, PA) (e)	4	52		52	1926
Green Valley Hydro (f)	21	6		6	Various

Gas-Fired:
AE Nos. 3, 4 & 5 (Springdale, PA)	3	540		540	2003
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		9,705	2,806	6,899

(a)	Effective January 1, 2007, Monongahela and AE Supply completed an intra-company transfer of assets (the “Asset Swap”) that realigned generation ownership and contractual obligations within the Allegheny system. See Note 7, “Asset Swap,” to the Consolidated Financial Statements.

(b)	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.

(c)

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. Currently, as a result of AE’s equity interest, Monongahela is entitled to 3.5% of OVEC generation, a portion (66 MWs) of which it has agreed to sell to AE Supply at cost in connection with the Asset Swap. Monongahela will transfer to AE Supply its rights to OVEC generation at such time as AE Supply’s long-term unsecured non-credit enhanced indebtedness has a Standard & Poor’s credit rating of at least BBB- and a Moody’s Investor Services, Inc. credit rating of at least Baa3.

(d)

This figure represents capacity entitlement through ownership of AGC. A modernization project has been completed on four of the six generating units at the Bath County facility, and work on the remaining two units is expected to be completed in 2008 and 2009, respectively. Each upgrade results in an increase of approximately 25 MWs to AGC’s capacity entitlement.

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

(f)	The licenses for hydroelectric facilities Dam No. 4 and Dam No. 5, located in West Virginia and Maryland, will expire in November 2024. The licenses for the Shenandoah, Warren, Luray and Newport projects 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 additional generation capacity available to the Distribution Companies through state utility commission-approved arrangements pursuant to PURPA. PURPA requires electric utility companies, such as the Distribution Companies, to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities. The capacity purchases reflected in this table are reflected in the results of the Delivery and Services segment, except that the PURPA generation for which Monongahela contracts is reflected in the results of the Generation and Marketing segment.


	PURPA Capacity (MW)
PURPA Stations	Project Total	Monongahela	Potomac Edison	West Penn	Contract Termination Date
Coal-Fired: Steam
AES Warrior Run (Cumberland, MD) (a)	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
Allegheny Lock and Dam 6 (Freeport, PA)	7			7	2034
Allegheny Lock and Dam 5 (Freeport, PA)	6			6	2034

Total PURPA Capacity	479	161	180	138

(a)

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.

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

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, 2007:


	Underground	Above- Ground	Total Miles	Total Miles Consisting of 500-Kilovolt (kV) Lines	Number of Transmission and Distribution Substations
Monongahela	835	22,387	23,222	250	276
Potomac Edison	5,196	18,116	23,312	175	259
West Penn	2,898	24,236	27,134	277	597
AGC (a)	0	87	87	87	1

Total	8,929	64,826	73,755	789	1,133

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

The Distribution Companies’ transmission network has 12 extra-high-voltage (345 kV and above) and 36 lower-voltage interconnections with neighboring utility systems.

FUEL, POWER AND RESOURCE SUPPLY

Generation and Marketing Segment

Coal Supply

Allegheny consumed approximately 19 million tons of coal and synthetic fuel in 2007 at an average price of $40.64 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 several generation facilities.

Historically, Allegheny has purchased a majority of its coal from a limited number of suppliers. Of Allegheny’s coal purchases in 2007, 65% came from subsidiaries of three companies, the largest of which represented 35% of the total tons purchased.

As of February 27, 2008, Allegheny had commitments for the delivery of more than 95% of the coal that Allegheny expects to consume in 2008. Allegheny also had commitments for the delivery of approximately 60% of its anticipated coal needs for 2009 and 2010 and for approximately 50% of its anticipated coal needs for 2011 and 2012.

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 our coal suppliers, including increased costs, transportation constraints, safety issues and operational difficulties, may have negative effects on coal supplier performance. See “Risk Factors” below.

Natural Gas Supply

AE Supply purchases natural gas to supply its natural gas-fired generation facilities. In 2007, AE Supply purchased its natural gas requirements principally in the spot market.

The Delivery and Services Segment

Electric Power

Allegheny reorganized its corporate structure in response to electric utility deregulation within its service area between 1999 and 2001. The Distribution Companies, with the exception of Monongahela and its West Virginia generation assets, do not produce their own power. 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. The Asset Swap realigned ownership of certain generation facilities between Monongahela and AE Supply, effective as of January 1, 2007. See “Regulatory Framework Affecting Allegheny” below and Note 7, “Asset Swap,” to the Consolidated Financial Statements.

Each of the states in Allegheny’s service territory other than West Virginia has, to some extent, deregulated its electric utility industry. Pennsylvania and Maryland have instituted retail customer choice and are transitioning to market-based, rather than cost-based pricing for generation. Virginia undertook to deregulate the provision of generation services beginning in 1999, but recent legislation in Virginia will result in re-regulation of such services as of January 1, 2009 for all but large customers with load in excess of 5 MW or for any customer wishing to purchase renewable energy. In West Virginia, the rates charged to retail customers are regulated by the West Virginia PSC and are determined through traditional, cost-based, regulated utility rate-making.

West Penn has PLR obligations to its customers in Pennsylvania. Potomac Edison has PLR obligations to its customers in Virginia and its residential customers in Maryland. As “providers of last resort,” West Penn and Potomac Edison must supply power to certain retail customers who have not chosen alternative suppliers (or have chosen to return to Allegheny service) at rates that are capped at various levels during the applicable transition period. The transition periods vary across Allegheny’s service area and across customer class. These transition periods could be altered by legislative, judicial or, in some cases, regulatory actions. See “Regulatory Framework Affecting Allegheny” below.

A significant portion of the power necessary to meet the PLR obligations of West Penn and Potomac Edison is purchased from AE Supply. AE Supply is contractually obligated to provide power to West Penn and Potomac Edison during the relevant state deregulation transition periods under the terms of power sales agreements. These power sales agreements include both fixed price and market-based pricing components. These pricing components may not fully reflect the cost of supplying this power. As a result, AE Supply currently absorbs a portion of the risk of fuel price increases and increased costs of environmental compliance. Prior to January 1, 2007, AE Supply also 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. A portion of Allegheny’s PLR obligations is satisfied by PURPA contract purchases.

When the initial power sales agreements with AE Supply for service to PLR customers during the rate cap periods terminate, Potomac Edison and West Penn will be unable to rely on the previously dedicated supply of power at specified contract prices to meet their respective power supply requirements. The arrangements to serve the applicable PLR obligations following the expiration of these agreements have been partially determined in Maryland but are still under development in Pennsylvania and Virginia for all load, and in Maryland with respect to residential customers. AE Supply’s existing power sales agreements with West Penn and Potomac Edison will expire or have expired as set forth in the chart below.


Distribution Company	Load Type	State	Expiration Date of Power Sale Agreement
Potomac Edison	Commercial and Industrial	Maryland	December 31, 2004
Potomac Edison	Residential	Maryland	December 31, 2008
Potomac Edison	All load	Virginia	June 30, 2007 (a)
West Penn	All load (b)	Pennsylvania	December 31, 2010

(a)	Potomac Edison has procured market based agreements for this load through May 31, 2008. Additional procurements are occurring in the spring of 2008 for service beginning June 1, 2008.

(b)

Load served under Tariff 37 was not included in the rate cap extension plan approved by the Pennsylvania PUC in 2005 for service years 2009 and 2010. Consequently, the expiration date of the power sales agreement for that load is December 31, 2008, and a PLR II procurement plan has been filed with the Pennsylvania PUC to procure power supply of service beginning January 1, 2009.

Monongahela’s Generation and Marketing segment provides the power necessary to meet the obligations of its Delivery and Services segment. Additionally, Monongahela is contractually obligated to provide Potomac Edison with the power necessary to serve its West Virginia load through 2027. To facilitate the economic dispatch of its generation, 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.

REGULATORY FRAMEWORK AFFECTING ALLEGHENY

The interstate transmission services and wholesale power sales of the Distribution Companies, 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. The statutory and regulatory framework affecting these companies has evolved significantly over the past decade, and these changes have exposed the Distribution Companies to significant new risks and opportunities. In addition, Allegheny’s communications subsidiary, ACC, is subject, to a limited extent, to the jurisdiction of the Federal Communications Commission and state regulatory commissions. Allegheny is subject to numerous other local, state and federal laws, regulations and rules. See “Risk Factors” below.

Federal Regulation and Rate Matters

FERC, Competition and RTOs

FERC is an independent agency within the DOE that regulates the U.S. electric utility industry.

FERC Authority Under the Federal Power Act

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

•

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

•

the development, operation and maintenance of hydroelectricity projects;

•

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

•

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

•

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

•

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

•

the reliability of the transmission grid;

•

the siting of certain transmission facilities;

•

the allocation of transmission rights;

•

the types of incentives available to encourage new transmission investment;

•

the transparency of power sales prices and market manipulation;

•

the relationship between holding companies and their public utility affiliates, including cost allocations, affiliate transactions and communications, and the availability of books and records; and

•

the holding of a director or officer position at more than one public utility or specified company.

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

The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales and transmission of electricity in interstate commerce. Entities, such as the Distribution Companies, AE Supply and AGC, that sell electricity at wholesale or own transmission facilities are considered “public utilities” subject to FERC jurisdiction. Public

utilities must obtain FERC acceptance for filing of their wholesale rate schedules. Rates for wholesale sales of electricity are determined on a cost-basis, or, if the seller demonstrates that it does not have market power, FERC may grant market-based rate authority, which allows transactions to be priced based on prevailing market conditions. Rates for transmission facilities are determined on a cost basis.

Competition and RTOs

Over the past decade, FERC has taken a number of steps to foster increased competition within the electric industry. Among other things, FERC requires public utilities that own transmission facilities to offer non-discriminatory, open-access transmission services. FERC also has taken steps to encourage utilities to participate in RTOs, such as PJM, by transferring functional control over their transmission assets to RTOs.

In addition, FERC has imposed standards of conduct governing communications between employees conducting transmission functions and employees engaged in wholesale power sale activities. These standards of conduct are intended to prevent transmission-owning utilities from giving their power marketing businesses preferential access to the transmission system and transmission information.

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

However, this trend toward restructuring and increased competition for retail markets has slowed in response to events over the past several years. Market-based competition within the wholesale markets is now continuing with greater FERC oversight, and some states have moved away from electricity choice at the retail level by delaying and/or reversing the implementation of retail competition (as in Virginia) or rejecting it outright (as in West Virginia). Further delays, discontinuations or reversals of electricity marketing restructurings in states in which Allegheny operates could have a material adverse effect on its results of operation and financial condition.

All of Allegheny’s generation assets and power supply obligations are located within the PJM market, and PJM maintains functional control over the Distribution Companies’ transmission facilities. 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 also manages a regional planning process for transmission expansion in an effort to ensure reliability of the electric grid in its region. Changes in the PJM tariff, operating agreement, policies and/or market rules could adversely affect Allegheny’s financial results. These matters include changes involving: the terms, conditions and pricing of transmission services; construction of transmission enhancements; auction of long-term financial transmission rights and the allocation mechanism for the auction revenues; changes in PJM’s Reliability Pricing Model, or “RPM”; changes in the locational marginal pricing mechanism; changes in transmission congestion patterns due to the implementation of PJM’s regional transmission expansion planning protocol or other required transmission system upgrades; generation retirement rules and reliability pricing issues.

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 (“MISO”) regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for these regions. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others. FERC concluded that neither the rate design

proposals nor the existing PJM rate design had been shown to be just and reasonable. However, FERC ordered the continuation of the existing PJM rate design and the implementation of a transition charge for these regions through March 31, 2006 through filings made by transmission owners in both regions. In February 2005, FERC accepted these transition charges, effective December 1, 2004, subject to an evidentiary hearing. FERC’s February 2005 order remains subject to multiple rehearing requests and, potentially, appellate review. Allegheny cannot predict the outcome of these proceedings or whether they 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. These charges resulted in the payment by the Distribution Companies of $13.7 million, and payments to the Distribution Companies of $3.5 million, for the 16-month period ended March 31, 2006. Following the evidentiary hearing, on August 10, 2006, an administrative law judge issued an initial decision that generally found fault with the methodologies used to develop the transition charges. That decision is now subject to review by FERC. The order that will be issued by FERC on review of the initial decision may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of increases in the transition charges previously billed to them, or they may receive refunds of transition charges previously billed. Allegheny cannot predict the outcome of these proceedings. The Distribution Companies have entered into nine partial settlements with regard to the transition charges, and may enter into additional settlements in the future. FERC has approved four of these settlements, and approval is pending for the remaining partial settlements.

In a May 2005 order, FERC again determined that the existing PJM rate design may not be just and reasonable. On September 30, 2005, the Distribution Companies, together with another PJM transmission owner, filed a proposed rate design with FERC to replace the existing rate design within PJM, effective April 1, 2006. Two other PJM transmission owners also filed a separate proposed rate design. A hearing was held in April 2006 to determine whether the rate design is unjust and unreasonable and whether it should be replaced by either of the proposed rate designs. On July 13, 2006, the administrative law judge issued an initial decision, finding that the existing PJM rate design for existing transmission facilities is not just and reasonable. The administrative law judge found that the rate design for existing transmission facilities proposed by the Distribution Companies is just and reasonable, but ruled that the rate design proposed by FERC staff is also just and reasonable, is superior and should be made effective as of April 1, 2006. The initial decision also found that the Distribution Companies’ proposal for rate recovery for new transmission facilities had not demonstrated that the existing rate recovery mechanism for such facilities is unjust and unreasonable but adopted the Distribution Companies’ position that the implementation of a new rate design does not necessitate a change in the allocation of auction revenue rights and financial transmission rights. On April 19, 2007, FERC issued an order on the initial decision that (a) retained the current license plate rate design for existing facilities, (b) requires that the parties develop a detailed “beneficiary pays” methodology for new facilities below 500 kV that would be set forth in the PJM tariff, and (c) allocates on a region-wide basis the costs of new, centrally-planned facilities that operate at or above 500 kV. The Distribution Companies participated as settling parties in a settlement currently pending before FERC with regard to the “beneficiary pays” methodology. If approved, the settlement will continue the application of intra-zonal netting and distribution factors for the determination of cost allocations for new facilities below 500 kV. On January 31, 2008, FERC denied requests for rehearing of its April 19, 2007 order on the initial decision.

On August 1, 2007, the Distribution Companies joined in a filing with other PJM and MISO transmission owners proposing a rate design for transmission transactions crossing the border between PJM and MISO. The proposal provides that customers will pay the rates applicable in the transmission zone where such transmission transactions end. Several parties filed protests of the proposal. On January 31, 2008, FERC rejected the protests and accepted the proposal as filed. FERC’s January 2008 decision is currently pending on appeal to the U.S. Court of Appeals.

On September 17, 2007, AEP filed a complaint with FERC against MISO and PJM alleging that the rate designs underlying the MISO and PJM open access transmission tariffs are unjust, unreasonable and unduly discriminatory and, therefore, must be revised. AEP requested that FERC establish a refund-effective date of October 1, 2007 with respect to any such revisions. The Distribution Companies intervened in this proceeding, and on January 31, 2008, FERC denied AEP’s request.

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 participated in a settlement agreement that was filed with the 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 though 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. Capacity auctions were held in April, July and October of 2007 and in January 2008, and an additional auction is expected to be conducted in May 2008. 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 and the United States Court of Appeals for the Third Circuit.

On July 3, 2006, PJM filed at FERC a proposal to implement a process for allocating long-term transmission rights (“LTTRs”). The PJM proposal would allocate a ten-year financial transmission right to PJM LSEs based on each LSE’s zonal base load. The PJM proposal created a link between PJM’s long-term transmission planning process and the LTTR allocation process to ensure that the transmission system is being upgraded as necessary to maintain the availability of the LTTRs that PJM will allocate. On November 22, 2006, FERC issued an order accepting PJM’s proposal, subject to modifications. On January 22, 2007, PJM filed a related settlement agreement, as well as a proposal to allocate any costs to fund LTTRs fully to holders of financial transmission rights on a pro-rata basis. FERC accepted this settlement agreement and related cost allocation proposal in an order issued on May 17, 2007. On October 22, 2007, FERC denied requests for rehearing of the May 17, 2007 order. FERC has also ordered the creation of a stakeholder process to determine whether the PJM proposed full funding mechanism that was accepted by FERC should be changed subsequent to the 2007-2008 PJM planning year. AE Supply and the Distribution Companies are participating in this stakeholder process.

Transmission Expansion

TrAIL Project.In June 2006, the PJM Board of Managers approved a Regional Transmission Expansion Plan (“RTEP”) that directed the Distribution Companies and Virginia Electric and Power Company to cause the construction of a 240-mile 500 kV transmission line project from southwestern Pennsylvania through northern West Virginia and into northern Virginia to address potential electric reliability issues caused by increased customer load in the mid-Atlantic area that could have adverse effects within the service territories of the Distribution Companies. Approximately 210 miles of the project are located in the Distribution Companies’ PJM zone. In October 2006, Allegheny formed TrAIL Company as the entity responsible for financing, constructing, owning, operating and maintaining this project, which has been named “Trans-Allegheny Interstate Line” and is referred to as “TrAIL.” The project includes the construction of approximately 51 miles of 500 kV and 138 kV lines in southwestern Pennsylvania to address electric reliability issues in that area. Total project costs are expected to be approximately $820 million.

On July 20, 2006, FERC approved incentive rate treatments for TrAIL. On February 21, 2007, TrAIL Company submitted to FERC a filing under Section 205 of the FPA to implement a formula tariff rate, with a proposed effective date of June 1, 2007, that includes the incentive rate treatments approved by FERC. On May 31, 2007, FERC issued an order permitting the formula tariff rate to become effective on June 1, 2007, subject to refund and hearing on specifically identified issues. One of the issues set for hearing is the level of the incentive return on equity for TrAIL. On January 24, 2008, TrAIL Company filed a motion to suspend the procedural schedule in this case and indicated that a settlement in principle had been reached.

PATH Project.On June 22, 2007, the PJM Board of Managers authorized the construction of a 290-mile, high-voltage transmission line, named the Potomac-Appalachian Transmission Highline, or “PATH.” The project will include approximately 244 miles of 765 kV transmission line from AEP’s substation near St. Albans, West Virginia to Allegheny’s Bedington substation near Martinsburg, West Virginia, and will also include approximately 46 miles of twin-circuit 500 kV lines from Bedington to a new substation to be built and owned by Allegheny near Kemptown, Maryland. On September 1, 2007, Allegheny entered into a joint venture agreement with a subsidiary of AEP to build PATH. Total project costs are expected to be approximately $1.8 billion, of which Allegheny’s share is expected to be approximately $1.2 billion.

On December 28, 2007, PATH, LLC submitted a filing to FERC under Section 205 of the FPA to implement a formula tariff rate to be effective March 1, 2008. The filing also included a request for certain incentive rate treatments.

National Interest Electric Transmission Corridor.The Energy Policy Act amended the FPA to, among other things, direct the Secretary of Energy to conduct a nationwide study of electric transmission congestion by August 2006 and to update the study every three years thereafter. Based on its congestion study and other relevant factors, the Secretary may designate any geographic area experiencing electric energy transmission capacity constraints or congestion that adversely affects customers a national interest transmission corridor (“NIETC”). Within a NIETC, transmission proposals could potentially be reviewed by FERC, which would have siting authority supplementing existing state authority and may consider whether to issue a permit and authorize construction of a proposed transmission project within the NIETC in the event that the relevant state authorities do not approve siting of the project within the NIETC. Under certain circumstances, a federal permit could empower the permit holder to exercise the right of eminent domain to acquire necessary property rights to construct the proposed transmission project.

On August 8, 2006, the DOE published its initial congestion study in which a portion of the Mid-Atlantic region was classified as a “critical congestion area” meriting further federal attention. On October 2, 2007, the DOE issued a NIETC designation for the Mid-Atlantic corridor that includes the areas where TrAIL and PATH are proposed to be sited. Several requests for rehearing of the DOE’s October 2, 2007 NIETC designation have been filed and are pending before the DOE. In addition, several entities, including the Pennsylvania PUC, have initiated various proceedings in the federal courts challenging the NIETC designations and the FERC rules promulgated for siting transmission lines within a NIETC. The Distribution Companies and TrAIL Company have intervened in the proceeding that challenges the FERC rules.

PURPA

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

The Distribution Companies have committed to purchase 479 MWs of qualifying PURPA capacity. In 2007, PURPA capacity and energy purchases pursuant to these contracts totaled approximately $224.5 million. The

average cost to the Distribution Companies of these power purchases was 5.9 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

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

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 approved by the Pennsylvania PUC (the “1998 Restructuring Settlement”), 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 PLR 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, in each case at rates that are capped at various levels during the applicable transition period, which under the original 1998 Restructuring Settlement extended through December 31, 2008. West Penn’s T&D assets are subject to traditional regulated utility ratemaking (i.e., cost-based rates).

Joint Petition and Extension of Generation Rate Caps

By order entered on May 11, 2005, the Pennsylvania PUC approved a Joint Petition for Settlement and for Modification of the 1998 Restructuring Settlement, as amended, among West Penn, the Pennsylvania Office of Consumer Advocate, the Office of Small Business Advocate, The West Penn Power Industrial Intervenors and certain other parties (the “2004 Joint Petition”). The 2004 Joint Petition extended generation rate caps for most customers from 2008 to 2010 and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously approved rate cap increases for 2006 and 2008. The order approving the 2004 Joint Petition also extended distribution rate caps from 2005 through 2007, with an additional rate cap in place for 2009 at the rate in effect on January 1, 2009. The intent of this transition plan is to gradually move generation rates closer to market prices. Rate caps on transmission services expired on December 31, 2005.

Default Service Regulations

On May 10, 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 will end for the majority of its customers on December 31, 2010, when its generation rate caps expire.

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 is 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. On October 25, 2007, West Penn filed with the Pennsylvania PUC a default service plan, which has been referred to a Pennsylvania PUC administrative law judge for hearings.

Power Purchase Agreement

West Penn has long-term power purchase agreements with AE Supply to provide West Penn with the amount of electricity necessary to meet the majority of its PLR retail obligations during the Pennsylvania transition period. According to the terms of the 2004 Joint Petition described above, in May 2005, West Penn issued a Request for Proposal for the supply of its full requirements for wholesale electric power supply to serve its load obligations in 2009 and 2010. AE Supply was the successful bidder and was awarded the contract on July 21, 2005. AE Supply filed a request with the FERC for authority to make these wholesale power sales, which FERC granted on October 25, 2005.

Transmission Expansion

On April 13, 2007, TrAIL Company filed an application with the Pennsylvania PUC for authorization to construct the TrAIL project in Pennsylvania. The evidentiary hearing on this matter is scheduled to begin on March 24, 2008. Issuance of an order in this matter is expected by August 2008.

Stranded Cost Securitizations

In November 1999, under authority granted by the Pennsylvania PUC in its order approving the 1998 Restructuring Settlement, West Penn Funding, LLC, a subsidiary of West Penn, issued $600 million aggregate principal amount of Transition Bonds, Series 1999-A in order to securitize a customer charge relating to a portion of the anticipated loss in value of its generation-related assets resulting from deregulation, which are known as “stranded costs.” In November 2003, West Penn requested approval to issue additional transition bonds up to $115 million to securitize a customer charge relating to the portion of West Penn’s stranded costs that had not been recoverable on a more timely basis due to operation of the generation rate cap. A Joint Petition approved by the Pennsylvania PUC in May 2005 allowed West Penn to securitize up to $115 million of additional transition costs through the issuance of transition bonds. On September 27, 2005, WPP Funding, LLC, a subsidiary of West Penn, issued $115 million aggregate principal amount of 4.46% Transition Bonds, Series 2005-A.

Other Pennsylvania PUC Matters

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. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative sources are not reasonably available. The law directs that all costs related to the purchase of electricity from alternative energy sources and payments for alternative energy credits will be fully recovered pursuant to an automatic energy adjustment clause. The Pennsylvania PUC initiated a proceeding in January 2005 regarding implementation and enforcement of the legislation.

Management Efficiency Audit.In 2006 and 2007, the Pennsylvania PUC’s Bureau of Audits conducted an audit of the management efficiency of West Penn, as it is required by state law to do every five to eight years for all major Pennsylvania utilities. The last such audit of West Penn was completed in 2000. The Pennsylvania PUC’s Bureau of Audits has concluded its audit and fact finding, and its conclusions, along with West Penn’s response, became public upon the issuance of the Bureau of Audit’s report to the Pennsylvania PUC. The audit recommendations accepted in full or in part by West Penn include recommendations to:

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Develop an improvement plan to meet the Pennsylvania PUC’s three-year distribution reliability standards:

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Conduct a study to determine utilization practices for contractors and company line workers;

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Enforce an underground damage prevention program;

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Charge affiliate pole attachment fees consistent with the fees charged to non-affiliates;

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Intensify efforts toward attaining representation of women and minorities.

For each of the next three years, West Penn will be required to provide the PA PUC with annual reports on its implementation of, and progress with respect to, these recommendations. West Penn rejected recommendations to: limit its dividend payments to AE; achieve higher returns on final customer accounts that are referred to outside collection agencies; reorganize the reporting relationship of the internal audit function; and periodically change its independent accounting firm. The PA PUC did not order West Penn to implement the recommendations that it rejected.

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. In 2005, the parties to the proceeding, including the Consumer Advocate, the Utility Workers Union of America Local 102, and the Rural Electric Association entered into an agreement settling the proceeding and providing West Penn with attainable reliability benchmarks. The Pennsylvania PUC approved the settlement in an Order issued July 27, 2006. As of December 31, 2007, West Penn has not satisfied the reliability benchmarks approved by the Pennsylvania PUC in its July 2006 order as a result of various factors, including recent storm activity.

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.

Transmission Expansion

On March 30, 2007, TrAIL Company filed an application with the West Virginia PSC for authorization to construct the TrAIL project in West Virginia. An evidentiary hearing on this matter was held during a two-week period in January 2008. The West Virginia PSC is expected to issue an order in this matter by May 2, 2008.

Rate Case

On July 26, 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a request to raise their West Virginia retail rates by approximately $100 million annually, effective on August 25, 2006. The request included a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a fuel cost recovery clause, adjustable annually, to reflect upward or downward changes in the cost of fuel and purchased power, and a $26 million decrease in base rates. On May 22, 2007, the West Virginia PSC issued a final order directing Monongahela and Potomac Edison to reduce overall rates by approximately $6 million effective May 23, 2007, by increasing fuel and purchased power cost-related rates by $126 million and reducing base rates by approximately $132 million, which includes changes in authorized depreciation rates that will reduce annual depreciation expense by approximately $16 million. The order approved the request by Monongahela and Potomac Edison to reinstate a fuel cost recovery clause. On June 15, 2007, Monongahela and Potomac Edison filed a Petition for Reconsideration and Clarification (“Petition for Reconsideration”) of certain findings in the order. Other parties in the proceeding submitted responses in opposition to the Petition for Reconsideration on July 9, 2007. The West Virginia PSC has no procedural deadline for ruling on the Petition for Reconsideration. See Note 4, “Rates and Regulation” to the Consolidated Financial Statements.

Securitization and Scrubber Project

In May 2005, the state of West Virginia adopted legislation permitting securitization financing for the construction of certain types of pollution control equipment at facilities owned by public utilities that are regulated by the West Virginia PSC, subject to the satisfaction of certain criteria. In April 2006, the West Virginia PSC approved a settlement agreement among Monongahela, Potomac Edison and certain other interested parties relating to Allegheny’s plans to construct Scrubbers at the Fort Martin generation facility in West Virginia. Concurrently, the West Virginia PSC granted Monongahela and Potomac Edison a certificate of public convenience and necessity authorizing the construction and operation of the Scrubbers, approved the Asset Swap, and issued a related financing order (the “Financing Order”) approving a proposal by Monongahela and Potomac Edison to finance $338 million of project costs using the securitization mechanism provided for by the legislation adopted in May 2005. Specifically, Monongahela and Potomac Edison received approval to issue environmental control bonds secured by the right to collect a surcharge from West Virginia retail customers dedicated to the repayment of the bonds.

In October 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a Petition to Reopen Proceedings and to Amend Financing Order (“Petition”), informing the West Virginia PSC that the current estimate for constructing the Scrubbers at Fort Martin had increased from $338 million to an amount up to $550 million. In December, 2006, Allegheny reached a settlement agreement with all parties in the reopened cases and filed the agreement with the West Virginia PSC. The West Virginia PSC approved the settlement agreement, authorizing Allegheny to securitize up to $450 million of the estimated construction costs, plus $16.5 million of upfront financing costs and certain other costs. Allegheny also is permitted to recover a return on actual

construction costs exceeding the $450 million during the period prior to placing the project into commercial

service and may file for recovery of any costs exceeding the $450 million once the Scrubber is in commercial service.

On April 11, 2007, Allegheny completed the securitization with the sale by two indirect subsidiaries of an aggregate of $459.3 million in environmental control bonds.

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, or “SOS,” at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, will expire 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 retained its T&D assets. Potomac Edison’s T&D rates for all customers were capped through 2004 and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates).

Standard Offer Service

In 2003, the Maryland PSC approved two statewide settlements relating to the future of PLR and SOS. The settlement extended Potomac Edison’s obligation to provide SOS after the expiration of the current generation rate cap periods. The settlement 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. These actions also would alter the procurement for residential customers of other Maryland electric utilities, but not necessarily for customers of Potomac Edison. The November 8, 2006 order is subject to a motion for rehearing filed by the Maryland Office of People’s Counsel, and neither the Maryland PSC nor the Maryland legislature has taken further action on the subject of the December 31, 2006 report to the Maryland legislature. Allegheny cannot predict when a final resolution of these matters will be forthcoming.

The Maryland PSC opened a new docket in August 2007 (Case No. 9117) 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 at no discount and with no recourse. Testimony was filed in September 2007. On September 25, 2007, the Maryland PSC opened “Phase II” of the case and required the utilities to file testimony by October 12, 2007 on utility purchases or construction of generation, bidding for procurement of DSM 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. It is unclear when the Maryland PSC will issue its findings in these proceedings.

Potomac Edison developed a plan for seeking bids to serve its Maryland residential load for the period after the rate cap expires on December 31, 2008. Potomac Edison filed the proposal with the Maryland PSC on August 3, 2007. On September 12, 2007, the Maryland PSC directed Potomac Edison to proceed with an initial partial procurement in October 2007, but to file a modified plan for the rest of the procurement after the resolution of Case No. 9117. On November 22, 2007, Potomac Edison filed a second partial procurement plan, for bidding in January 2008, which the Maryland PSC approved on December 19, 2007.

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 when capped generation rates end on January 1, 2009.

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 will result in an overall rate increase of approximately 15% annually from 2007 through 2010. 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 would convert to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, would be returned to customers as a credit on their electric bills, thereby reducing the effect of the rate cap expiration. The credit would continue, with adjustments, to maintain rate stability until December 31, 2010 or until all monies collected from customers plus interest are returned. Of Potomac Edison’s more than 217,000 residential customers in Maryland, approximately 8,900, or 4.1%, elected to opt-out of Potomac Edison’s plan.

Power Purchase Agreement

Potomac Edison has a power purchase agreement with AE Supply to provide the amount of electricity necessary to meet Potomac Edison’s PLR retail obligations to residential customers during the Maryland generation rate cap period through December 31, 2008. Potomac Edison will procure the wholesale electric supply services necessary to serve its residential PLR obligation after the expiration of the rate caps and before the expiration of its SOS obligations, and currently procures supply for its non-residential PLR obligations in Maryland, through a competitive bid process. Potomac Edison is allowed to recover its costs for providing these services, including a return for its shareholder, through an administrative charge. Beginning in June 2006 and through all wholesale contracts awarded to AE Supply to date, AE Supply has, or will, sell to Potomac Edison approximately, 2.2 million MWhs of generation and associated services for certain residential, small commercial and industrial customers in Maryland, based on actual power sold from June 2006 through December 2007 and estimated sales from January 2008 through May 2010.

Advanced Metering and Demand Side Management Initiatives

On June 8, 2007, the Maryland PSC established a new case to consider the following four items:

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technical standards for, and operational capabilities of, advanced meters;

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the extent to which demand side management programs are to be offered in Maryland on a competitively-neutral basis;

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recovery of costs of demand side management programs; and

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the appropriate measure(s) of cost effectiveness of demand side management programs to be employed in Maryland.

The staff of the Maryland PSC filed its report on these matters on July 6, 2007. 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 a proposal that electric demand in Maryland be reduced by 15% 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. One other party filed a plan in January 2008, and the remaining utilities, which include co-ops and municipals, are due to file plans in February. The Maryland PSC has also initiated a series of workshops to coordinate the utilities’ plans, the first of which was held on January 4, 2008.

In September 2007, the Maryland PSC approved a fast-track compact fluorescent light (“CFL”) and education campaign that included recovery of $2.5 million in costs through a special, one-year surcharge on customers’ distribution bills. The Maryland PSC held further hearings on the program in January 2008, at which Allegheny agreed, among other things, to refund cost recovery for the program. The Maryland PSC also ordered Potomac Edison and three other Maryland utilities to file, by February 15, 2008, a Demand Response Service Program, which is intended to be a plan for mandatory load reduction during times of peak usage through the installation of technology in customers’ homes.

Renewable Energy Portfolio Standard

Legislation enacted in 2004 (and supplemented with respect to solar power in 2007) 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.

Virginia

Transmission Expansion

On April 19, 2007, TrAIL Company filed an application with the Virginia SCC for authorization to construct the TrAIL project in Virginia. An evidentiary hearing in this matter is scheduled to commence on February 25, 2008. Issuance of an order in this matter is expected by July 2008.

Purchased Power Filing

During the 2007 session, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”), to re-regulate the provision of electric generation services in the Commonwealth beginning January 1, 2009. Until that time, Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Until December 31, 2008, Potomac Edison is the PLR for those customers who do not choose an alternate generation supplier or whose alternate generation supplier does not deliver. After January 1, 2009, Potomac Edison will provide generation services at regulated rates to its customers in Virginia other than large customers with load in excess of 5 MW, who may choose alternate generation suppliers, and customers wishing to purchase renewable energy.

Potomac Edison had a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations through June 30, 2007 at capped generation rates. In April 2007, Potomac Edison conducted a competitive bidding process to purchase its PLR requirements from the wholesale market and AE Supply was the successful bidder with respect to a substantial portion of these requirements. On July 1, 2007 Potomac Edison began to purchase its PLR requirements at market prices. Market prices for purchased power resulting from that bidding process are higher than the rates Potomac Edison is currently allowed to recover from its retail customers.

Accordingly, on April 12, 2007, Potomac Edison filed an Application with the Virginia SCC to establish a fuel factor and increase retail rates by approximately $103 million beginning on July 1, 2007 to offset the impact of increased purchased power costs. In the Application, Potomac Edison also proposed a transition plan that would limit the average increase on July 1, 2007 to 20% and defer, with interest, amounts above 20% for collection over the subsequent three years. Potomac Edison argued that, based on amendments to the Restructuring Act in 2001 and 2004, the generation rates that Potomac Edison will be able to charge its Virginia customers beginning on July 1, 2007, will be based on its cost of purchased power.

On June 28, 2007, the Virginia SCC issued an order denying the Application and rejecting Potomac Edison’s request to recover its purchased power expenses effective July 1, 2007, denying Potomac Edison’s Motion for Interim Rates and dismissing the case. On July 6, 2007, Potomac Edison filed with the Virginia SCC a Motion for Suspension of Order and Motion for Interim Rates, which the Virginia SCC denied on August 7, 2007. Potomac Edison filed an appeal with the Virginia Supreme Court on July 26, 2007 and also asked the Virginia Supreme Court for relief pending appeal. The Court denied Potomac Edison’s motions for relief pending appeal and set the matter for review in the ordinary course. Potomac Edison filed its initial brief on appeal on December 21, 2007. Oral argument is scheduled for the last week of February 2008.

Potomac Edison filed at the Virginia SCC a new application for rate recovery of costs for load above 367 MW on September 11, 2007, while continuing to pursue its appeal for full cost recovery. The Virginia SCC held an evidentiary hearing on Potomac Edison’s new application on December 4, 2007. At the hearing, Potomac Edison contended that it was entitled to recovery of $42.3 million in costs for load above 367 MW, while the Virginia SCC’s staff contended that Potomac Edison was entitled to nothing or, at most, $9.5 million. On December 20, 2007, the Virginia SCC issued an order adopting the Staff’s alternative calculation of $9.5 million.

At this time, there can be no assurance that Potomac Edison will be able to recover any more of the cost of power purchases in excess of the capped generation rates that it is currently permitted to charge its Virginia customers beyond that allowed in the December 20, 2007 order of the Virginia SCC. The inability to recover such costs is expected to have a significantly negative effect on Potomac Edison’s income and cash flows from Potomac Edison’s Virginia operations, which in turn may have an adverse effect on its overall business, results of operations and financial condition. Potomac Edison’s management is currently reevaluating planned capital and other expenditures and may postpone or eliminate all or a portion of those expenditures or take other measures in response to the expected negative impact of these regulatory decisions.

Potomac Edison’s T&D rates in Virginia are presently capped through 2008, subject to certain exceptions. Prior to 2009, Potomac Edison has one opportunity to petition the Virginia SCC for changes to its T&D rate after July 1, 2007. Furthermore, the Restructuring Act requires the Virginia SCC to adjust Potomac Edison’s capped T&D rates not more than once annually for the timely recovery of costs prudently incurred after January 1, 2004 for T&D system reliability or to comply with state or federal environmental laws or regulations. During the first six months of 2009, the Commission will initiate a proceeding to review the rates, terms and conditions for Potomac Edison’s provision of generation, distribution and transmission services in the Commonwealth.

ENVIRONMENTAL MATTERS

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

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

Global Climate Change. The United States relies on coal-fired plants for more than 50 percent 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 more than 95 percent of its electricity at coal-fired facilities and currently produces approximately 45 million tons of CO₂ annually through its energy production. While there are many unknowns concerning the final regulation of greenhouse gases in the United States, federal and/or state legislation and implementing regulations addressing climate change likely will be adopted some time in the future, and may include limits on emissions of CO₂. Thus, CO₂ legislation and regulation, if not reasonably designed, could have a significant impact on Allegheny’s operations. Current proposals range from cap-and-trade schemes with $12 safety-valve allowance prices to direct taxation of tons emitted on the order of $50 per ton. Allegheny can provide no assurance that limits on CO₂ emissions, if imposed, will be set at levels that can accommodate its generation facilities absent the installation of controls. See “Risk Factors” below.

Moreover, there is a gap between desired reduction levels in the current proposed legislation and the current capabilities of technology; no current commercial-scale technology exists to enable many of the reduction levels being proposed in national, regional and state proposals. Such technology may not become available within a timeframe consistent with the implementation of any future climate control legislation 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 DOE National Electric Technology Laboratory report, it could cost as much as $3,000 per kW to replace existing coal-based power generation with fossil fuel stations capable of capturing and sequestering CO₂ emissions, and recent project announcements suggest that these costs could be substantially higher. However, exact estimates are difficult because of the variance in the legislative proposals and the current lack of deployable technology.

Allegheny supports federal legislation and believes that the United States must commit to a response to climate change that both encourages the development of technology and creates a workable control system. Regardless of the eventual mechanism for limiting CO₂ emissions, however, 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 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 seven tasks:

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developing an accurate CO₂ emissions inventory;

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

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following developing technologies for clean-coal energy and for CO₂ emission controls at coal-fired power plants;

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following developing technologies for carbon sequestration;

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participating in CO₂ sequestration efforts (e.g. reforestation projects) both domestically and abroad;

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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 more than 1,090 MWs of renewable hydroelectric and pumped storage power generation. Allegheny is also pursuing permits to allow for a limited use of bio-mass (wood chips and saw dust) and waste-tire derived fuel at two of its coal-based power stations in West Virginia, and Allegheny is actively exploring the economics of installing additional renewable generation capacity.

Allegheny intends to engage in the dialogue that will shape the regulatory landscape surrounding carbon dioxide 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. 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 meets current emission standards for SO₂ by using emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

Allegheny’s compliance with the Clean Air Act of 1990 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the EPA on March 10, 2005 may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Based on current forecasts, Allegheny estimates that it may have exposure to the SO₂ allowance market in 2008 of about 85,000 to 120,000 tons and may have an exposure in 2009 of between 40,000 and 60,000 tons. Monongahela’s exposure is expected to be approximately 50% and 60% of Allegheny’s total exposure in 2008 and 2009, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Allegheny continues to evaluate and implement options for compliance; it completed the elimination of a partial Scrubber bypass at its Pleasants generation facility in December 2007, and current plans include the installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generation facilities by 2009.

Allegheny meets current emission standards for nitrogen oxides (“NOx”) by using low NOx burners, Selective Catalytic Reduction, Selective Non-Catalytic Reduction and over-fire air and optimization software, as well as through the use of emission allowances. Allegheny is currently evaluating its options for CAIR compliance.

The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities.

On March 15, 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”), establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and developing its strategy for compliance, but it will include the emission reduction projects discussed above for the Hatfield’s Ferry, Fort Martin and Pleasants generation facilities, as they will have a co-benefit effect and also remove mercury from plant emissions.

The Pennsylvania Department of Environmental Protection (the “PA DEP”) promulgated a more aggressive mercury control rule on February 17, 2007. Pennsylvania’s proposed shortened compliance schedule and more aggressive emissions limits might result in the installation of additional emission controls at any of Allegheny’s three Pennsylvania coal-fired facilities or in a change in fuel specifications. Controls might include additional Scrubbers, activated carbon injection, selective catalytic reduction or other, currently emerging technologies.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NOx, requires greater reductions in mercury emissions more quickly than required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative (“RGGI”) and participate in that coalition’s regional efforts to reduce CO₂ emission. On April 20, 2007, Maryland’s governor signed the 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 does provide a conditional exemption for the R. Paul Smith power station, provided that PJM declares the station vital to reliability in the Baltimore/Washington DC metropolitan area. In response to Allegheny’s request and after conducting a reliability evaluation, PJM, by letter dated November 8, 2006, determined that R. Paul Smith is vital to the regional reliability of power flow. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) will now create specific regulations for R. Paul Smith to comply with both the Healthy Air Act and the federal CAIR. Allegheny is assessing the new legislation and upcoming implementing regulations to determine the full extent of the impacts on Allegheny’s Maryland operations and is working with the MDE on the R. Paul Smith-specific regulations. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions, and Maryland issued draft regulations to implement RGGI requirements in December 2007, subject to the review of the Maryland Legislative Review Committee. Allegheny is also assessing the reach and impact of those regulations on its Maryland operations.

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

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology.

On April 2, 2007, the United States Supreme Court issued a decision in the Duke Energy case vacating the Fourth Circuit’s decision that had supported the industry’s understanding of NSR requirements and remanded the case to the lower court. The Supreme Court rejected the industry’s position on an hourly emissions standard and adopted an annual emissions standard favored by environmental groups. However, the Supreme Court did not specify a testing standard for how to calculate annual emissions and otherwise provided little clarity on whether the industry’s or the government’s interpretation of other aspects of the NSR regulations will prevail.

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 Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

On January 6, 2005, AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal District Court in West Virginia (“West Virginia DJ Action”). This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia comply with the Clean Air Act. The Attorneys General filed a motion to dismiss the West Virginia DJ Action. It is possible that the EPA and other state authorities may join or move to transfer the West Virginia DJ Action.

On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Distribution Companies in the 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 will occur during the first quarter of 2008.

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 was directed to AE, Monongahela and West Penn and 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, the West Virginia DJ Action 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.

Other Environmental Litigation

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 filed a notice of appeal of that ruling on September 17, 2007, and the appeal will now proceed before the United States Court of Appeals for the Fifth Circuit. AE intends to vigorously defend against this action but cannot predict its outcome.

Claims Related to Alleged Asbestos Exposure: The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in 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. Liberty Mutual Insurance Company, Civil Action No (Suffolk Superior Court, MA). The parties in these actions 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. Allegheny believes that it has recorded appropriate liabilities to cover existing and future asbestos claims. As of December 31, 2007, Allegheny’s total number of claims alleging exposure to asbestos was 826 in West Virginia, two in Pennsylvania and one in Illinois.

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

EMPLOYEES

Substantially all of Allegheny’s officers and other personnel are employed by AESC. As of December 31, 2007, AESC employed 4,355 employees. Of these employees, 28.7% are subject to collective bargaining arrangements. Approximately 74% of the unionized employees are at the Distribution Companies and approximately 26% are at AE’s other subsidiaries. As of December 31, 2007, System Local 102 of the Utility Workers Union of America (the “UWUA”) represents 1,059 employees, and locals of the International Brotherhood of Electrical Workers (the “IBEW”) represent 192 employees. Collective bargaining arrangements with the IBEW expire at various dates during the first half of 2010. 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, the Professional Services Agreement will expire on December 31, 2012. Most of the AESC employees performing Allegheny’s information technology functions were offered employment with the service provider.

Executive Officers

The names of AE’s executive officers, their ages, the positions they hold, and their business experience during the past five years appear below. All of AE’s officers are elected annually.


Name	Age	Title
Paul J. Evanson (a)	66	Chairman, President, Chief Executive Officer and Director
Edward Dudzinski (b)	55	Vice President
David M. Feinberg (c)	38	Vice President, General Counsel and Secretary
David E. Flitman (d)	43	Vice President
Philip L. Goulding (e)	48	Senior Vice President and Chief Financial Officer
William F. Wahl, III (f)	48	Vice President, Controller and Chief Accounting Officer

(a)

Paul J. Evansonhas been Chairman of the Board, President, Chief Executive Officer and a director of AE since June 2003. Mr. Evanson is the Chair of the Executive Committee. Prior to joining Allegheny, Mr. Evanson was President of Florida Power & Light Company, the principal subsidiary of FPL Group, Inc., and a director of FPL Group, Inc. from 1995 to 2003.

(b)

Edward Dudzinskihas been Vice President, Human Resources and Safety, of AE since August 2004. Prior to joining Allegheny, Mr. Dudzinski was Vice President, Human Resources for the Agriculture and Nutrition Platform and Pioneer Hi-Bred International, Inc. on behalf of E. I. DuPont de Nemours and Company (“DuPont”). Prior to that, he served in various other executive and leadership positions at DuPont.

(c)

David M. Feinberg has been Vice President, General Counsel and Secretary of AE since October 2006. Mr. Feinberg joined Allegheny in August 2004 and served as Deputy General Counsel until October 2006. Prior to joining Allegheny, Mr. Feinberg was a partner with the law firm of Jenner & Block LLP in its Chicago office.

(d)

David E. Flitman has been President of Allegheny Power, which includes Monongahela, Potomac Edison and West Penn, since July 2006. Mr. Flitman joined Allegheny in February 2005 as Vice President, Distribution. Prior to joining Allegheny, Mr. Flitman was employed with DuPont, most recently as Global Business Director for the Nonwovens Business Group.

(e)

Philip L. Gouldinghas been Senior Vice President and Chief Financial Officer of AE since July 2006. Mr. Goulding joined Allegheny in October 2003 as Vice President, Strategic Planning and Chief Commercial Officer. Prior to joining Allegheny, Mr. Goulding led the North American energy practice of L.E.K. Consulting.

(f)

William F. Wahl, IIIhas been Vice President, Controller and Chief Accounting Officer of AE since May 2007. He joined Allegheny in 2003 and served as Assistant Controller, Corporate Accounting from February 2005 to May 2007. From 2002 to 2003, Mr. Wahl was employed by PNC Financial Services Group, Inc. Prior to that, he was employed by Dominion Resources, Inc.

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” above. Allegheny’s susceptibility to certain risks could exacerbate other risks. These risk factors should be considered carefully in evaluating Allegheny’s risk profile. Risks applicable to Allegheny include:

Risks Relating to Regulation

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

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 are 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. Compliance with these laws and regulations may require Allegheny to expend significant financial resources to, among other things, meet air emission standards, conduct site remediation, perform environmental monitoring, purchase emission allowances, use alternative fuels and modulate operations of its generation facilities in order to reduce emissions. If Allegheny fails to comply with applicable environmental laws and regulations, even if it is unable to do so due to factors beyond its control, it may be subject to civil liabilities or criminal penalties and may be required to incur significant expenditures to come into compliance. In addition, any alleged violations of environmental laws and regulations may require Allegheny to expend significant resources defending itself against such alleged violations. Either result could have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

Potential Climate Change Legislation.The United States relies on coal-fired plants for more than 50 percent of its energy. However, coal-fired power plants have come under scrutiny due to their emission of greenhouse gases implicated in climate change, primarily CO₂. Allegheny produces more than 95 percent of its electricity at coal-fired facilities and currently produces approximately 45 million tons of CO₂ annually through its energy production. While there are many unknowns concerning the final regulation of greenhouse gases in the United States, federal and/or state legislation and implementing regulations addressing climate change likely will be adopted some time in the future, and may include limits on emissions of CO₂. Thus, CO₂ legislation and

regulation, if not reasonably designed, could have a significant impact on Allegheny’s operations. Current proposals range from cap-and-trade schemes with $12 safety-valve allowance prices to direct taxation of tons emitted on the order of $50 per ton. Allegheny can provide no assurance that limits on CO₂ emissions, if imposed, will be set at levels that can accommodate its generation facilities absent the installation of controls.

Because the legislative process and applicable technology each is in its infancy, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures, or to fully evaluate the magnitude and impact of potential expenditures, until the exact nature and requirements of any regulation are known and the capabilities of control or reduction technologies are more fully understood. In any event, compliance with any federal or other legislation or regulations regarding CO₂ emissions is likely to require significant expenditures by Allegheny and may have an adverse effect on its business, results of operations, cash flows and financial condition. See “Environmental Matters” above.

Clean Air Act Compliance.Allegheny’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule, or “CAIR,” promulgated by the EPA on March 10, 2005, may accelerate the need to install this equipment by phasing out a portion of currently available emission allowances. Allegheny continues to evaluate and implement options for compliance; in December 2007, it completed the elimination of a partial Scrubber bypass at its Pleasants generation facility, and current plans include the installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generation facilities by 2009. The installation of Scrubbers at the Hatfield’s Ferry and Fort Martin generation facilities will be subject to various implementation and financial risks. See “Capital Expenditures” and “Environmental Matters” above.

Applicable standards under the EPA’s NSR initiatives remain in flux. Under the Clean Air Act, modification of Allegheny’s generation facilities in a manner that causes increased emissions could subject Allegheny’s existing facilities to the far more stringent NSR standards applicable to new facilities. The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work believed by the companies to be routine maintenance. Allegheny currently is involved in litigation concerning alleged violations of the PSD provisions of the Clean Air Act at certain of its facilities in West Virginia and violations of the Pennsylvania Air Pollution Control Act and NSR provisions of the Clean Air Act at certain of its facilities in Pennsylvania. Allegheny intends to vigorously pursue and defend against the environmental matters described above but cannot predict their outcomes. If NSR and similar requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology, which could have an adverse impact on Allegheny’s business, results of operations, cash flows and financial condition. See “Environmental Matters” above.

In March 2005, the EPA issued the Clean Air Mercury Rule, or “CAMR,” establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants. In addition, the PA DEP proposed a more aggressive mercury control rule in June 2006. Allegheny is currently assessing the impact that these rules may have on its operations. Pennsylvania’s proposed shortened compliance schedule and more aggressive emissions limits might result in the installation of additional emission controls at any of Allegheny’s three

Pennsylvania coal-fired facilities or in a change in fuel specifications. Controls might include Scrubbers, activated carbon injection, selective catalytic reduction or other currently emerging technologies. Installation of such controls or other compliance efforts could entail significant costs, which could have an adverse impact on Allegheny’s business, results of operations, cash flows and financial condition. See “Environmental Matters” above.

Other Environmental Compliance Matters.In addition, Allegheny incurs costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if Allegheny fails to obtain, maintain or comply with any required approval, operations at affected facilities could be halted, curtailed or subjected to additional costs, which could have an adverse impact on Allegheny’s business, results of operations, cash flows and financial condition.

Shifting state and federal regulatory policies impose risks on Allegheny’s operations. 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 and the restructuring of transmission regulation. Any new requirements arising from these actions could lead to increased operating expenses and capital expenditures, the amount of which cannot be predicted at this time.

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. During its 2007 session, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act of 1999 to re-regulate the provision of electric generation services in the Commonwealth beginning January 1, 2009. In Pennsylvania, many of the state’s electric utilities, including Allegheny, are scheduled to transition to market rates in 2010 and 2011, when applicable generation rate caps expire. Significant price increases in other states following the end of such regulatory transition periods have created a heightened political concern regarding price volatility in Pennsylvania following the expiration of its rate caps. In September 2007, a special legislative session was convened in Pennsylvania to consider various energy proposals. During the special session, several proposed bills involving the extension of rate caps were introduced. Currently, generation rate caps for Allegheny’s Pennsylvania customers expire at the end of 2010. Allegheny cannot predict the outcome of the Pennsylvania special session at this time. See “Regulatory Framework Affecting Allegheny—State Rate Regulation” above.

Other 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 delayed, discontinued or reversed in the states in which Allegheny operates. Delays, discontinuations or 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—Federal Regulation and Rate Matters” above.

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 or capped by each state’s regulatory body. As a result, Allegheny may not be able to recover increased, unexpected or necessary costs and, even if it 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 business, results of operations, cash flows and financial condition.

Virginia

Potomac Edison’s Virginia generation rates were originally capped until July 1, 2007, but this cap was extended by legislation until December 31, 2008. Potomac Edison had a power purchase agreement with AE Supply to provide Potomac Edison with the amount of electricity necessary to meet its Virginia PLR retail obligations until July 1, 2007 at capped generation rates. On July 1, 2007, Potomac Edison began to purchase those requirements at market prices. Market prices for purchased power are, and likely will continue to be, significantly higher than the rates Potomac Edison is currently allowed to recover from its retail customers.

Accordingly, in April 2007, Potomac Edison filed an Application with the Virginia SCC to establish a fuel factor and increase retail rates to recover Potomac Edison’s estimated costs for purchased power to serve the Virginia retail load beginning July 1, 2007. Potomac Edison also proposed a transition plan. However, the Virginia SCC denied the Application, rejecting Potomac Edison’s request to recover its purchased power expenses and dismissing the case. Potomac Edison currently is appealing this decision to the Virginia Supreme Court. Allegheny also filed at the Virginia SCC a new application for a smaller rate increase, contending that it is at least entitled to recovery of $42.3 million in costs to service load above 367 MW. The Virginia SCC’s staff contended that Potomac Edison is entitled to nothing or, at most, $9.5 million, and in December 2007, the Virginia SCC issued an order adopting the staff’s alternative calculation of $9.5 million. See “Regulatory Framework Affecting Allegheny—State Rate Regulation” above.

At this time, there can be no assurance that Potomac Edison will be able to recover most of the cost of power purchases in excess of the capped generation rates that it is currently permitted to charge its Virginia customers. The inability to recover such costs is expected to have a significantly negative effect on Potomac Edison’s income and cash flows from Potomac Edison’s Virginia operations, which in turn may have an adverse effect on its overall business, results of operations and financial condition. Potomac Edison’s management is currently reevaluating planned capital and other expenditures and may postpone or eliminate all or a portion of those expenditures or take other measures in response to the expected negative impact of these regulatory decisions.

West Virginia

The West Virginia PSC sets Monongahela’s and Potomac Edison’s rates in West Virginia through traditional, cost-based regulated utility ratemaking.

In July 2006, Potomac Edison and Monongahela filed a request with the West Virginia PSC to increase their West Virginia retail rates by approximately $99.8 million annually, effective on August 25, 2006. The request included a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a cost recovery clause, adjustable annually, to reflect upward or downward changes in the cost of fuel and purchased power, and a $26 million decrease in transmission, distribution and generation (non-fuel) rates.

In May 2007, the West Virginia PSC issued a final order directing Monongahela and Potomac Edison to reduce overall rates by approximately $6.2 million, effective May 23, 2007, by increasing fuel and purchased power cost-related rates by $126 million and reducing base rates by approximately $132 million. The order approved the request by Monongahela and Potomac Edison to reinstate a fuel cost recovery clause. Monongahela and Potomac Edison filed a Petition for Reconsideration of certain findings in the order. The West Virginia PSC has no procedural deadline for ruling on these petitions. Allegheny can provide no assurance that the Petition for Reconsideration will succeed in whole or in part. The decrease in base rates embodied in the final Order may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny—State Rate Regulation” above.

The TrAIL Project and the PATH Project are 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 both the TrAIL Project and the PATH Project are subject to the prior approval of various state regulatory bodies. Allegheny is in the process of pursuing the necessary approvals, but has met with substantial political opposition, as well as opposition from environmental, community and other groups, and there can be no assurance that Allegheny will be able to obtain the regulatory approvals required in connection with these projects 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 affect on Allegheny’s business, results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny—Federal Regulation and Rate Matters” above.

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

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

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

Extreme weather or events outside of Allegheny’s service territory can also have a direct effect on the commodity markets. Events, such as hurricanes, that disrupt the supply of commodities used as fuel impact the price and availability of energy commodities and can have a material impact on Allegheny’s 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, could have a negative 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 T&D losses may be recoverable through regulatory proceedings, the delay and uncertainty of any such recovery could have a material adverse effect on Allegheny’s 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 experience financial, legal or technical problems that inhibit their ability to fulfill their obligations. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties may have negative effects on coal supplier performance. 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 event, 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.

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

Allegheny’s SO₂ and NOx 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 a material adverse effect on Allegheny’s business, financial condition, cash flows and results of operations. See “Environmental Matters” above.

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 and the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities. Allegheny’s ability to successfully complete these projects in a timely manner within established budgets is contingent upon many variables. 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 to acquire some of the necessary materials and construction related services in order to accomplish the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities and in connection with the TrAIL Project, and may in the future enter into additional such contracts with respect to these and other capital projects, including the PATH Project. 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. 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 cost associated therewith could have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

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 and Allegheny 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; changes in the RPM; changes in the locational marginal pricing mechanism; changes in 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, deterioration in the credit quality of other PJM members, socialization of member defaults, or the withdrawal from PJM of other transmission owners, could negatively impact Allegheny’s performance.

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

In connection with regulations governing the transition to market competition, Potomac Edison and West Penn are required to provide electricity at capped rates to certain retail customers who do not choose an alternate electricity generation supplier or who return to utility service from alternate suppliers. Potomac Edison and West Penn satisfy the majority of these obligations by purchasing power under contracts with external counterparties, or their affiliate, AE Supply. Those contracts provide for the supply of a significant portion of their energy needs

at the mandated capped rates and for the supply of a specified remaining portion at rates based on market prices. The amount of energy priced at market rates increases over each contract term. The majority of AE Supply’s normal operating capacity is dedicated to these contracts.

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

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 could 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 could have a material adverse effect on its financial condition, cash flow and results of operations. See “Environmental Matters” above and “Legal Proceedings” below.

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

The Distribution Companies have been named as defendants in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at Allegheny-owned facilities where suitable alternative materials are not available. Allegheny’s management believes that any remaining asbestos at Allegheny-owned facilities is contained. The continued presence of asbestos and other regulated substances at Allegheny-owned facilities, however, could result in additional actions being brought against Allegheny. See “Legal Proceedings” below and Note 21, “Asset Retirement Obligations,” to the 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. Under applicable law, Allegheny is required to make cash contributions to the extent necessary to comply with minimum funding requirements imposed by regulatory requirements. The amount of such required cash contribution is based on an actuarial valuation of the plan. The funded status of the plan can be affected by investment returns on plan assets, discount rates, mortality rates of plan participants, 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 recent 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. 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 an economic slowdown;

•

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

•

significant increases in the prices for oil or other fuel;

•

a terrorist attack or threatened attacks;

•

a significant transmission failure; or

•

changes in technology.

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

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

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

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

Although Allegheny reduced debt by approximately $2 billion between December 1, 2003 and December 31, 2007, Allegheny still has substantial leverage. At December 31, 2007, Allegheny had $4.1 billion of debt on a consolidated basis. Approximately $2 billion represented debt of AE Supply and AGC, $10 million 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;

•

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Substantially all of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations. Substantially all of Monongahela’s, Potomac Edison’s and West Penn’s properties are held subject to the lien of indentures securing their first mortgage bonds. Certain of the properties and other assets owned by AE Supply and Monongahela that were financed by solid waste disposal and pollution control notes are subject to liens securing the obligations under those notes. In many cases, the properties of Monongahela, Potomac Edison, 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” above, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” below and Note 11, “Capitalization” to the Consolidated Financial Statements.

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

ITEM 3. LEGAL PROCEEDINGS

Nevada Power Contracts.

On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with the 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, Nevada 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 the 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 September 25, 2007, the Supreme Court announced that it would hear the case on appeal. Briefing by all parties was completed by February 6, 2008, and oral argument before the Supreme Court was held on February 19, 2008.

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

Sierra/Nevada.

On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in United States District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). Sierra/Nevada has alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada has asserted claims against AE and AE Supply for: (a) wrongful hiring and supervision; (b) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (c) conspiracy and (d) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada’s most recent complaint seeks damages in excess of $850 million, including compensatory damages, punitive damages, attorneys’ fees and treble damages. AE and AE Supply have filed motions to dismiss the lawsuit, which have been pending since 2003. The lawsuit had been stayed since 2005, pending the outcome of certain state court proceedings in which Sierra/Nevada was seeking to reverse the Nevada PUC’s disallowance of expenses. On July 20, 2006, the Nevada Supreme Court reversed the Nevada PUC’s disallowance of the $180 million in deferred energy expenses, which formed the basis of the plaintiffs’ claims. An announcement was made on March 23, 2007 that the Nevada PUC approved two settlements relating to the requested disallowance, and those state court proceedings that were the focus of the prior stay have been closed. A scheduling order was then entered in this lawsuit that, among other things, sets a trial date of July 8, 2008. The parties are engaged in discovery and awaiting a ruling from the District Court on the previously filed motions to dismiss.

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

Claim 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 demand to AE Supply in the amount of approximately $190 million was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit to resolve all outstanding claims of alleged price manipulation in the California energy markets during 2000 and 2001. No complaint has been filed against Allegheny. Allegheny believes that all issues in connection with AE Supply sales to CDWR were resolved by a settlement in 2003 and otherwise believes that the California parties’ demand is without merit.

Allegheny intends to vigorously defend against this claim but cannot predict its outcome.

Litigation Involving Merrill Lynch.

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

On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the United States District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million. On May 29, 2003, the District Court ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York state court, as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the District Court. The counterclaims, as amended, alleged that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, that Merrill Lynch negligently misrepresented certain facts relating to the purchase agreement and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims sought damages in excess of $605 million, among other relief.

On April 15, 2005, the District Court granted Merrill Lynch’s motion for summary judgment with respect to its breach of contract claim and the counterclaims for breach of fiduciary duty and negligent misrepresentation, but denied the motion with respect to the counterclaims for fraudulent inducement and breach of warranty. In May and June of 2005, the District Court conducted a trial with respect to the damages owed Merrill Lynch on its breach of contract claim and with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of warranty. Following the trial, on July 18, 2005, the District Court entered an order: (a) ruling against AE and AE Supply on their fraudulent inducement and breach of contract claims; (b) requiring AE to pay $115 million plus interest to Merrill Lynch; and (c) requiring Merrill Lynch to return its equity interest in AE Supply to AE. On August 26, 2005, the District Court entered its final judgment in accordance with its July 18, 2005 rulings. As a result of the District Court’s ruling, AE recorded a charge during the first quarter of 2005 in the amount of $38.5 million, representing interest from March 16, 2001 through March 31, 2005.

AE and AE Supply appealed the District Court’s judgment to the United States Court of Appeals for the Second Circuit. On August 31, 2007, the Second Circuit issued an opinion that reversed the award of $115 million plus interest to Merrill Lynch, reversed the ruling against AE on its counterclaims for fraudulent inducement and breach of warranty, and remanded the case back to the District Court for reconsideration of both parties’ claims consistent with the appellate court’s opinion. The Second Circuit also dismissed AE Supply as a party to the case on jurisdictional grounds.

On January 25, 2008, AE and AE Supply entered into a settlement agreement with Merrill Lynch. Under the settlement agreement, Merrill Lynch will convey to AE its minority equity interest in AE Supply and AE will make a cash payment of $50 million to Merrill Lynch. In addition, the litigation will be dismissed and the parties will release their respective claims in the litigation.

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” above.

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. Allegheny is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.

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

No matters were submitted to a vote of security holders during the fourth quarter of 2007.

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 22, 2008, there were 19,073 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:


	2007				2006
	High		Low		High		Low
1^st Quarter	$	50.25	$	44.28	$	36.46	$	31.33
2^nd Quarter	$	56.13	$	48.67	$	37.90	$	33.01
3^rd Quarter	$	57.30	$	48.18	$	42.50	$	36.97
4^th Quarter	$	65.48	$	52.37	$	46.25	$	39.92

In the fourth quarter of 2007, AE declared a cash dividend of $0.15 per share on its common stock that was payable on December 17, 2007 to AE’s shareholders of record on December 3, 2007. AE did not pay any dividends on its common stock during 2006.

Performance Graph

The graph set forth below compares the cumulative total return on our common stock with the Dow Jones U.S. Electricity Index and the Standard & Poor’s 500 Index, assuming the investment of $100 in each on December 31, 2002 and the reinvestment of all dividends. The performance included in this graph is not necessarily indicative of future performance.


	12/02	12/03	12/04	12/05	12/06	12/07
Allegheny Energy, Inc.	100.00	168.78	260.71	418.65	607.28	843.51
S&P 500	100.00	128.68	142.69	149.70	173.34	182.87
Dow Jones US Electricity	100.00	125.07	155.53	181.76	219.67	265.82

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


Year ended December 31,	2007		2006		2005			2004			2003
(In millions, except per share amounts)
Operating revenues	$	3,307.0	$	3,121.5	$	3,037.9		$	2,756.1		$	2,182.3
Operating expenses	$	2,489.7	$	2,389.2	$	2,501.1		$	2,166.9		$	2,378.7
Operating income (loss)	$	817.3	$	732.3	$	536.8		$	589.2		$	(196.4	)
Income (loss) from continuing operations	$	412.2	$	318.7	$	75.1		$	129.7		$	(308.9	)
Income (loss) from discontinued operations, net of tax	$	—	$	0.6	$	(6.1	)	$	(440.3	)	$	(25.3	)
Net income (loss)	$	412.2	$	319.3	$	63.1		$	(310.6	)	$	(355.0	)
Income (loss) per share:
Income (loss) from continuing operations
—basic	$	2.48	$	1.94	$	0.48		$	1.00		$	(2.44	)
—diluted	$	2.43	$	1.89	$	0.47		$	0.99		$	(2.44	)
Loss from discontinued operations, net of tax
—basic	$	—	$	—	$	(0.04	)	$	(3.40	)	$	(0.20	)
—diluted	$	—	$	—	$	(0.04	)	$	(2.82	)	$	(0.20	)
Net income (loss)
—basic	$	2.48	$	1.94	$	0.40		$	(2.40	)	$	(2.80	)
—diluted	$	2.43	$	1.89	$	0.40		$	(1.83	)	$	(2.80	)
Dividends declared per share	$	0.15	$	—	$	—		$	—		$	—
Short-term debt	$	10.0	$	—	$	—		$	—		$	53.6
Long-term debt due within one year		95.4		201.2		477.2			385.1			544.9

Total current debt	$	105.4	$	201.2	$	477.2		$	385.1		$	598.5

Long-term debt	$	3,943.9	$	3,384.0	$	3,624.5		$	4,540.8		$	5,127.4
Capital leases		38.8		26.0		16.4			23.8			32.5

Total long-term obligations	$	3,982.7	$	3,410.0	$	3,640.9		$	4,564.6		$	5,159.9

Total assets	$	9,906.6	$	8,552.4	$	8,558.8		$	9,045.1		$	10,171.9

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


		Page No.
EXECUTIVE SUMMARY:

Business Overview		60

Key Indicators and Performance Factors		61

Primary Factors Affecting Allegheny’s Performance		63

Critical Accounting Policies and Estimates		63

RESULTS OF OPERATIONS		67

FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES:

Liquidity and Capital Requirements		87

Asset Sales		90

Dividends		91

Other Matters Concerning Liquidity and Capital Requirements		92

Cash Flows		93

Financing		96

Recent Accounting Pronouncements		96

Credit Ratings		97

Business Overview

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

Allegheny has two business segments:

•

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

•

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

The Delivery and Services Segment

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

•

Monongahela conducts an electric T&D business in northern West Virginia. Monongahela also owns generation assets, which are included in the Generation and Marketing Segment. Monongahela conducted electric T&D operations in Ohio and natural gas T&D operations in West Virginia until it sold the assets related to these operations on December 31, 2005 and September 30, 2005, respectively. Monongahela agreed to sell power at a fixed price to Columbus Southern Power Company (“Columbus Southern”), the purchaser of its electric T&D operations in Ohio, to serve Monongahela’s former Ohio customers until May 31, 2007. See “The Generation and Marketing Segment” and “Liquidity and Capital Resources—Asset Sales” below.

•

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

•

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

•

TrAIL Company was formed in 2006 in connection with the management and financing of transmission expansion projects, including the TrAIL Project.

•

PATH, LLCwas formed in 2007 as a joint venture between Allegheny and a subsidiary of AEP in connection with the management and financing of the PATH Project.

•

Allegheny Ventures is a nonutility, unregulated subsidiary of AE that engages in telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal wholly-owned subsidiaries, ACC and AE Solutions.

The Generation and Marketing Segment

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

•

AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities. AE Supply markets its electric generation capacity to various customers and markets. Currently, the majority of AE Supply’s normal operating capacity is committed to supplying certain obligations of West Penn and Potomac Edison, including their PLR obligations.

•

Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment. Monongahela’s Generation and Marketing segment’s normal operating capacity supplies Monongahela’s Delivery and Services segment. In addition, Monongahela has a contractual obligation to supply generation to meet Potomac Edison’s load obligations in West Virginia.

•

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 1,059 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela.

All of Allegheny’s generation facilities are located within the PJM market, and all of the power that the Generation and Marketing segment generates is sold into 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 contractual obligations to supply power. For more information regarding Allegheny’s business and the AE segments and subsidiaries discussed above, see “Business—Overview” above.

Intersegment Services

AESC is a service company for AE that employs substantially all of the Allegheny personnel who provide services to AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures, 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 4,355 employees as of December 31, 2007.

Key Indicators and Performance Factors

The Delivery and Services Segment

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

Revenue per MWh sold. This measure is calculated by dividing total revenues from retail sales of electricity by total MWhs sold to retail customers. Revenue per MWh sold in 2007, 2006 and 2005 was as follows:


	2007		2006		2005
Revenue per MWh sold	$	59.64	$	58.62	$	55.32

Operations and maintenance costs (“O&M”). Management closely monitors and manages O&M in absolute terms, as well as in relation to total MWhs sold. O&M per MWh sold in 2007, 2006 and 2005 was as follows:


	2007		2006		2005
O&M per MWh sold	$	7.63	$	7.97	$	8.05

Capital expenditures. Management prioritizes and manages capital expenditures to meet operational needs and regulatory requirements within available cash flow constraints. See “Business—Capital Expenditures” above.

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


	Normal	2007	2006	2005	2007 Change		2006 Change
Retail electricity sales (million kWhs)	N/A	44,901	43,178	48,275	4.0	%	(10.6	)%
HDD (a)	5,605	5,199	4,861	5,333	7.0	%	(8.9	)%
CDD (a)	776	1,007	781	1,087	28.9	%	(28.2	)%

(a)

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. HDD and CDD are most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day.

The Generation and Marketing Segment

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

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

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

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

The following table shows kWhs generated, excluding kWhs consumed by pumping at the Bath County, Virginia hydroelectric station, EAFs and Station O&M related to the Generation and Marketing segment:


	2007			2006			2005			2007 Change		2006 Change
Supercritical Units:
kWhs generated (in millions)		39,043			39,813			37,740		(1.9	)%	5.5	%
EAF		83.2	%		84.3	%		82.8	%	(1.1	)%	1.5	%
Station O&M (in millions):
Base and operations	$	104.0		$	100.8		$	101.6		3.2	%	(0.8	)%
Special maintenance		83.8			79.2			95.1		5.8	%	(16.7	)%

Total Station O&M	$	187.8		$	180.0		$	196.7		4.3	%	(8.5	)%

All Generation Units:
kWhs generated (in millions)		48,235			48,606			48,100		(0.8	)%	1.1	%
EAF		83.9	%		86.8	%		85.4	%	(2.9	)%	1.4	%
Station O&M (in millions):
Base and operations	$	161.6		$	158.6		$	167.6		1.9	%	(5.4	)%
Special maintenance		96.3			91.3			113.9		5.5	%	(19.8	)%

Total Station O&M	$	257.9		$	249.9		$	281.5		3.2	%	(11.2	)%

Primary Factors Affecting Allegheny’s Performance

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

•

Rate regulation and other regulatory policies,

•

plant availability and maintenance,

•

weather conditions,

•

demand and market prices for power,

•

cost of fuel (natural gas and coal),

•

wholesale commodity prices,

•

PJM market, rules and policies,

•

availability and access to liquidity and changes in interest rates,

•

environmental compliance costs and related capital expenditures and

•

labor costs.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“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.

Revenue Recognition: Allegheny follows the accrual method of accounting for revenues and recognizes revenue for electricity that has been delivered to customers but not yet billed through the end of its accounting period. Unbilled revenues are primarily associated with the Distribution Companies. Energy sales to individual customers are based on their meter readings, which are performed periodically on a systematic basis. At the end of each month, the amount of energy delivered to each customer after the last meter reading is estimated, and the Distribution Companies recognize unbilled revenues related to these estimated amounts. A provision for uncollectible amounts is recorded as a component of operations and maintenance expense. 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.

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. These rates are based on 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, but not current, recovery through rates of costs that would otherwise be charged to expense by an unregulated company. Regulators may also require that amounts be refunded to customers for various reasons. Therefore, this ratemaking process often results in the recording of regulatory assets based on estimated future cash inflows and the recording of regulatory liabilities based on estimated future cash outflows.

Allegheny regularly reviews its regulatory assets and liabilities and the estimates and assumptions from which they were calculated to assess the ultimate recoverability of the assets and anticipated customer refunds within approved regulatory guidelines. See Note 1, “Basis of Presentation” and Note 4, “Rates and Regulation,” for additional information.

Expanded Net Energy Cost (“ENEC”): On May 22, 2007, the West Virginia PSC issued a rate order (the “West Virginia Rate Order”) effective May 23, 2007 that re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues are being tracked for under and/or over recoveries, and revised ENEC rate filings with the West Virginia PSC will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, is being deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability, with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.” By order dated January 14, 2008, the West Virginia PSC approved a modification to the ENEC directing interest earnings on the Fort Martin scrubber project escrow fund to be applied to the ENEC.

Excess of Cost Over Net Assets Acquired (Goodwill): Recorded goodwill of $367.3 million at December 31, 2007 and December 31, 2006 arose in connection with the 2001 acquisition of a former energy trading business and was assigned to the Generation and Marketing segment. There were no changes in recorded goodwill during 2007 and 2006. Allegheny tests goodwill for impairment at least annually. The annual impairment test uses a discounted cash flow methodology to determine the fair value of the Generation and Marketing segment and indicated no impairment of goodwill in 2007 and 2006. Allegheny’s fleet of generation facilities, comprised primarily of low-cost coal-fired steam generation facilities, has a fair value well in excess of the carrying value of those assets. A hypothetical 10% decrease in the value of these facilities would therefore not result in an impairment of recorded goodwill.

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 SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, (“SFAS 71”). As a result, Allegheny must generate future cash flows from these assets in a non-regulated environment to ensure that the carrying values of these assets are not impaired. Allegheny assesses the carrying amount and potential impairment of these assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable.

Derivative Contracts: Derivative contracts are recorded in Allegheny’s Consolidated Balance Sheets at fair value, with changes in the fair value of the derivative contracts included in revenues or expenses on the Consolidated Statements of Income, unless the derivative falls within the “normal purchases and normal sales” scope exception of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities, as amended” (“SFAS 133”) 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 any ineffective portion of the hedge are recognized in earnings.

Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. Fair values are subject to change in the near term and reflect management’s best estimate based on various factors. In establishing the fair value of commodity contracts that do not have quoted prices, such as physical contracts, over-the-counter options and swaps, management uses available market data and pricing models to estimate fair values. Estimating fair values of instruments 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.

See Note 12, “Derivative Instruments and Hedging Activities,” for additional information regarding Allegheny’s accounting for derivative instruments under SFAS 133.

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. We establish reserves for tax-related uncertainties based on estimates of whether, and the extent to which, additional taxes will be due. We adjust these reserves in light of changing facts and circumstances, such as the outcome of tax audits. Effective January 1, 2007, we adopted the provisions of Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109” (“FIN 48”), which proscribes an approach to recognizing and measuring uncertain tax positions. See Note 6, “Income Taxes,” for additional information.

Stock-Based Compensation: Allegheny adopted the recognition and measurement principles of SFAS No. 123R “Accounting for Stock-Based Compensation,” (“SFAS 123R”) as of January 1, 2006. SFAS 123R 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 10, “Stock-Based Compensation,” 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 assets funded for the plan. Changes made to provisions for pension or other postretirement benefit plans may also affect current and future pension and OPEB costs. Allegheny 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 17, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for additional information concerning these assumptions.

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

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The following table shows the effect that a one percentage point increase or decrease in the 6.4% discount rate and the 8.25% expected rate of return, net of administrative expenses, on plan assets for 2008 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	$	(144.3	)	$	175.0
Net periodic pension and OPEB cost	$	(9.5	)	$	14.2
Change in expected rate of return on plan assets:
Net periodic pension and OPEB cost	$	(10.2	)	$	10.2

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 27, “Commitments and Contingencies,” for additional information.

RESULTS OF OPERATIONS

Income (Loss) Summary


(In millions)	Delivery and Services			Generation and Marketing			Eliminations			Total
2007	Delivery and Services			Generation and Marketing			Eliminations			Total
Operating revenues	$	2,829.2		$	2,141.3		$	(1,663.5	)	$	3,307.0
Fuel		—			930.8			—			930.8
Purchased power and transmission		1,939.2			108.1			(1,654.1	)		393.2
Deferred energy costs, net		(2.8	)		(7.3	)		—			(10.1	)
Operations and maintenance		342.5			353.9			(9.4	)		687.0
Depreciation and amortization		162.4			114.6			—			277.0
Taxes other than income taxes		134.0			77.8			—			211.8

Total operating expenses		2,575.3			1,577.9			(1,663.5	)		2,489.7
Operating income		253.9			563.4			—			817.3
Other income and expenses, net		16.2			26.8			(6.2	)		36.8
Interest expense and preferred dividends		74.0			120.2			(6.2	)		188.0

Income before income taxes and minority interest		196.1			470.0			—			666.1
Income tax expense		78.4			172.4			—			250.8
Minority interest in net income of subsidiaries		—			3.1			—			3.1

Net income	$	117.7		$	294.5		$	—		$	412.2


2006
2006
Operating revenues	$	2,717.7		$	1,834.4		$	(1,430.6	)	$	3,121.5
Fuel		—			842.7			—			842.7
Purchased power and transmission		1,773.0			33.2			(1,423.2	)		383.0
Gain on sale of OVEC power agreement and shares		—			(6.1	)		—			(6.1	)
Deferred energy costs, net		7.6			—			—			7.6
Operations and maintenance		344.0			349.0			(7.4	)		685.6
Depreciation and amortization		151.3			121.8			—			273.1
Taxes other than income taxes		122.0			81.3			—			203.3

Total operating expenses		2,397.9			1,421.9			(1,430.6	)		2,389.2
Operating income		319.8			412.5			—			732.3
Other income and expenses, net		22.2			14.8			(3.0	)		34.0
Interest expense and preferred dividends		81.4			193.1			(3.0	)		271.5

Income from continuing operations before income taxes and minority interest		260.6			234.2			—			494.8
Income tax expense from continuing operations		80.2			93.3			—			173.5
Minority interest in net income of subsidiaries		—			2.6			—			2.6

Income from continuing operations		180.4			138.3			—			318.7
Income (loss) from discontinued operations, net of tax		(1.0	)		1.6			—			0.6

Net income	$	179.4		$	139.9		$	—		$	319.3


(In millions)	Delivery and Services			Generation and Marketing			Eliminations			Total
2005	Delivery and Services			Generation and Marketing			Eliminations			Total
Operating revenues	$	2,845.5		$	1,703.3		$	(1,510.9	)	$	3,037.9
Fuel		—			759.1			—			759.1
Purchased power and transmission		1,878.7			81.0			(1,501.4	)		458.3
Loss on sale of Ohio T&D assets		29.3			—			—			29.3
Deferred energy costs, net		(1.5	)		—			—			(1.5	)
Operations and maintenance		388.5			356.2			(9.5	)		735.2
Depreciation and amortization		153.6			154.6			—			308.2
Taxes other than income taxes		130.4			82.1			—			212.5

Total operating expenses		2,579.0			1,433.0			(1,510.9	)		2,501.1
Operating income		266.5			270.3			—			536.8
Other income and expenses, net		24.2			21.1			(1.1	)		44.2
Interest expense and preferred dividends		123.3			318.2			(1.0	)		440.5

Income (loss) from continuing operations before income taxes and minority interest		167.4			(26.8	)		(0.1	)		140.5
Income tax expense from continuing operations		55.2			9.6			—			64.8
Minority interest in net income of subsidiaries		—			0.6			—			0.6

Income (loss) from continuing operations		112.2			(37.0	)		(0.1	)		75.1
Income (loss) from discontinued operations, net of tax		1.0			(7.2	)		0.1			(6.1	)
Cumulative effect of accounting change, net of tax		—			(5.9	)		—			(5.9	)

Net income (loss)	$	113.2		$	(50.1	)	$	—		$	63.1

CONSOLIDATED RESULTS

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

Operating Revenues

Operating revenues increased $185.5 million for 2007 compared to 2006, primarily due to:

•

higher generation rates charged to Pennsylvania customers,

•

an increase in the weighted average “round-the-clock” price for power in Allegheny’s region of PJM, the APS Zone, from $47.32 per MWh for 2006 to $54.87 per MWh for 2007 and increased net PJM capacity market revenues,

•

increased revenues related to the collection of the environmental control surcharge from the West Virginia retail customers of Monongahela and Potomac Edison, which began in April 2007 and

•

increased transmission and distribution revenues due to increases in HDD and CDD, increased customer load and the expiration of a Maryland customer choice credit,

•

partially offset by a 0.8% decrease in total MWhs generated due to a decrease in supercritical plant availability.

Operating revenues increased $83.6 million for 2006 compared to 2005, primarily due to:

•

the expiration of a PLR contract with one large industrial customer in Maryland in December 2005, which resulted in greater net sales into PJM at market prices,

•

higher generation rates charged to Pennsylvania customers,

•

Monongahela’s agreement to provide power to Columbus Southern from January 1, 2006 through May 31, 2007 under a fixed price power supply agreement at a higher rate per MWh, net of lost Ohio T&D revenues and

•

increased MWhs generated.

These factors contributing to increases in 2006 operating revenues were partially offset by a decrease in average market prices, the March 2006 assignment of AE Supply’s rights to generation from the Ohio Valley Electric Corporation (“OVEC”) in connection with the December 31, 2004 sale of a portion of AE’s equity interest in OVEC, the expiration of third-party transmission capacity contracts and decreased revenues associated with the completion of a construction services project during the second quarter of 2006.

Operating Income

Operating income increased $85.0 million for 2007 compared to 2006, due to:

•

the $185.5 million increase in operating revenues discussed above,

•

partially offset by an $88.1 million increase in fuel expense.

Fuel expense increased primarily due to higher coal, natural gas and emission allowance costs. The higher coal costs were primarily due to an increase in the average price of coal. The higher natural gas costs resulted from an increase in the amount of natural gas burned as a result of an increase in the dispatch of Allegheny’s gas-fired generation facilities.

Operating income increased $195.5 million in 2006 compared to 2005, due to:

•

the $83.6 million increase in operating revenues discussed above and

•

a $111.9 million decrease in operating expenses.

Operating expenses decreased as a result of a $75.3 million decrease in purchased power and transmission expense, a $29.3 million loss recorded during 2005 in connection with the sale of Monongahela’s Ohio T&D assets, a $49.6 million decrease in operations and maintenance expense and a $35.1 million decrease in depreciation and amortization expense, partially offset by an $83.6 million increase in fuel expense. Purchased power and transmission decreased due to the March 2006 assignment of AE Supply’s rights to generation from OVEC, a reduction in contracts that were designated as normal purchase and normal sale, a refund received on certain transmission charges and a reduction in power purchases due to the 2005 sale of Monongahela’s Ohio T&D assets. Operations and maintenance expense decreased due to litigation settlements, a reduction in accrued site remediation reserves associated with a previously terminated generation project, reductions in costs associated with a completed construction services project and decreased salaries and wages expense related to a decrease in the number of information technology employees as a result of the 2005 outsourcing of this function. These decreases were partially offset by increased outside services expense due to costs associated with the implementation of Allegheny’s information technology initiatives. Depreciation and amortization expense decreased due to the extension of the depreciable lives of Allegheny’s unregulated coal-fired generation facilities, partially offset by increased depreciation resulting from net property, plant and equipment additions. Fuel expense increased primarily due to an increase in coal expense resulting from an increase in the average price of coal and an increase in the amount of coal consumed, partially offset by a decrease in natural gas expense resulting from a decrease in the average price of natural gas and a decrease in the amount of natural gas consumed.

Income from Continuing Operations Before Income Taxes and Minority Interest

Income from continuing operations before income taxes and minority interest increased $171.3 million for 2007 compared to 2006, primarily due to:

•

the $85.0 million increase in operating income discussed above and

•

an $83.5 million decrease in interest expense and preferred dividends, primarily due to the reversal of accrued interest resulting from the settlement of Allegheny’s litigation with Merrill Lynch and Co., Inc. (“Merrill Lynch”), as well as lower average debt outstanding and increased capitalization of interest, partially offset by increased interest expense associated with the April 2007 issuance of environmental control bonds. See Note 28, “Subsequent Event,” for additional information regarding the settlement of Allegheny’s litigation with Merrill Lynch.

Income from continuing operations before income taxes and minority interest increased $354.3 million for 2006 compared to 2005, primarily due to:

•

the $195.5 million increase in operating income discussed above and

•

a $169.0 million decrease in interest expense and preferred dividends, primarily due to the premium and associated costs recorded during 2005 to redeem AE Supply’s outstanding 10.25% and 13% Senior Notes, costs related to the April 2005 tender offer by AE and Allegheny Capital Trust I (“Capital Trust”) for Capital Trust’s outstanding Trust Preferred Securities, $38.5 million of interest recorded during the first quarter of 2005 related to a court decision in the litigation involving Merrill Lynch and lower average debt outstanding.

Income Tax Expense

The effective tax rates for Allegheny’s continuing operations were 37.6%, 35.0% and 44.8% for 2007, 2006 and 2005, respectively. See Note 6, “Income Taxes,” for a reconciliation of income tax expense to income tax expense calculated at the federal statutory rate of 35%.

Discontinued Operations

Allegheny had no income or loss from discontinued operations in 2007. Allegheny recorded income from discontinued operations, net of tax of $0.6 million for the year ended December 31, 2006 and losses from discontinued operations, net of tax of $6.1 million for the year ended December 31, 2005 related to agreements to sell, or decisions to sell, certain non-core assets.

The $6.7 million increase in income from discontinued operations, net of tax for 2006 compared to 2005 primarily reflects adjustments associated with the sale of AE Supply’s natural gas-fired peaking facilities.

See Note 14, “Discontinued Operations,” for additional information.

DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

Delivery and Services

The following table provides retail electricity sales information:


	Normal	2007	2006	2005	2007 Change		2006 Change
Retail electricity sales (million kWhs)	N/A	44,901	43,178	48,275	4.0	%	(10.6	)%
HDD	5,605	5,199	4,861	5,333	7.0	%	(8.9	)%
CDD	776	1,007	781	1,087	28.9	%	(28.2	)%

Operating Revenues

Operating revenues were as follows:


(In millions)	2007		2006		2005
Retail electric:
Generation	$	1,813.2	$	1,688.0	$	1,783.9
Transmission		166.0		160.3		176.0
Distribution		698.9		682.8		711.0

Total retail electric		2,678.1		2,531.1		2,670.9

Transmission services and bulk power		110.1		150.7		115.9
Other affiliated and nonaffiliated energy services		41.0		35.9		58.7

Total operating revenues	$	2,829.2	$	2,717.7	$	2,845.5

Retail electric revenues increased $147.0 million for 2007 compared to 2006, primarily due to:

•

a $125.2 million increase in generation revenues and

•

a $21.8 million increase in T&D revenues.

Generation revenues increased primarily due to a $52.0 million increase resulting from higher generation rates charged to Pennsylvania customers, a $15.5 million increase resulting from higher market rates for commercial and industrial customers in Maryland, a $21.1 million increase from the West Virginia Rate Order, which approved an increase in generation rates charged to customers, and a $29.4 million increase due to increased customer load from increases in HDD and CDD.

T&D revenues increased primarily due to a $42.7 million increase from increased customer load and an $11.1 million increase due to the expiration of a Maryland customer choice credit, partially offset by a $29.4 million decrease as a result of the West Virginia Rate Order.

Retail electric revenues decreased $139.8 million for 2006 compared to 2005, primarily due to:

•

a $95.9 million decrease in generation revenues due to the following items:

•

a $70.9 million decrease due to the expiration of a contract with one large industrial customer in Maryland in December 2005,

•

a $42.0 million decrease due to milder weather and lower industrial usage, partially offset by increased load growth from new customers and customer usage,

•

a $39.4 million decrease due to certain Potomac Edison customers choosing alternate electricity generation providers and

•

a $47.7 million decrease due to the sale of Monongahela’s Ohio service territory on December 31, 2005,

•

partially offset by a $52.0 million increase in revenues as a result of the transition to market-based generation rates for Maryland commercial and industrial customers, as well as an increase in Monongahela’s effective generation rates and a $52.1 million increase in revenues as a result of higher generation rates charged to Pennsylvania customers, offset by a lower surcharge rate for intangible transition charge revenues,

•

and a $43.9 million decrease in T&D revenues, primarily as a result of an $8.8 million decrease in revenue from the expiration of a contract with one large industrial customer in Maryland in December 2005, a $21.2 million decrease associated with the sale of Monongahela’s Ohio service territory and a $13.9 million decrease due to milder weather and lower industrial usage, partially offset by increased load growth from new customers and customer usage.

Distribution revenues from customers who chose alternate generation suppliers are reflected in retail electric revenues regardless of the customers’ election to receive service from Allegheny or an alternate generation supplier. However, transmission revenues attributable to retail customers served by alternate generation suppliers are no longer reflected in retail revenues, but, instead, are reflected in transmission and bulk power revenues. The return of customers to default generation service results in an increase in total revenues due to the addition of a generation charge that Allegheny did not collect while those customers were using alternate generation suppliers.

Transmission services and bulk power revenues decreased by $40.6 million for 2007 compared to 2006, primarily due to the May 2007 expiration of a fixed price power supply agreement to serve Monongahela’s former Ohio service territory.

Transmission services and bulk power revenues increased by $34.8 million for 2006 compared to 2005, primarily due to:

•

a $77.6 million increase in bulk power revenues related to Monongahela’s fixed price power supply agreement with Columbus Southern to serve Monongahela’s former Ohio service territory as of January 1, 2006,

•

partially offset by a $30.5 million decrease in transmission revenues related to the expiration of third-party transmission capacity contracts and a $12.6 million decrease in bulk power revenues resulting from decreased power sales from the AES Warrior Run PURPA generation facility due to a scheduled outage at that facility during the first quarter of 2006 and a contractual reduction in the capacity rate at the facility.

Other affiliated and nonaffiliated energy services revenues increased $5.1 million for 2007 compared to 2006, primarily due to the deferral of revenue on certain fiber optic agreements during the first quarter of 2006 and the impact of regulatory activities related to certain transmission contracts.

Other affiliated and nonaffiliated energy services revenues decreased $22.8 million for 2006 compared to 2005, primarily due to decreased revenues associated with a construction services project that was completed during the second quarter of 2006.

Operating Expenses

Purchased Power and Transmission: Purchased power and transmission represents the Distribution Companies’ power purchases from other companies (primarily AE Supply and Monongahela), as well as purchases from qualifying facilities under PURPA. Purchased power and transmission consists of the following items:


(In millions)	2007		2006		2005
Other purchased power and transmission	$	1,780.9	$	1,569.2	$	1,669.7
From PURPA generation		158.3		203.8		209.0

Total purchased power and transmission	$	1,939.2	$	1,773.0	$	1,878.7

West Penn and Potomac Edison currently have power purchase agreements with AE Supply, under which AE Supply provides West Penn and Potomac Edison with the majority of the power necessary to meet their PLR obligations. These agreements have both fixed-price and market-based pricing components. In addition, through December 31, 2006, Potomac Edison had a power purchase agreement with AE Supply under which AE Supply provided Potomac Edison with the power necessary to meet its West Virginia load obligation at a fixed rate. In connection with the Asset Swap, Monongahela assumed the obligation to supply power to serve Potomac Edison’s West Virginia load. Thus, effective January 1, 2007, Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela’s Generation and Marketing segment at a prorated share of overall Monongahela generation costs and associated revenue. Effective with the institution under the 2007 West Virginia Rate Order of the ENEC method of recovering net power supply costs for Allegheny’s West Virginia service territory, the amount charged to Potomac Edison reflects the adjustment for over and/or under recovery. See “Business—Electric Facilities” and “Business—Regulatory Framework Affecting Allegheny” above, Note 4, “Rates and Regulation” and Note 7 “Asset Swap,” for additional information.

Through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela sold the power that it generated from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchased from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. Effective January 1, 2007, 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 its contractual obligations. The net revenue from these PJM purchases and sales is reflected in wholesale and other revenues, net within the Generation and Marketing segment.

Other purchased power and transmission increased $211.7 million for 2007 compared to 2006, primarily due to:

•

a $74.9 million increase due to increased purchased power volume, primarily as a result of increases in HDD and CDD, increased customer load and the decrease in purchased power from PURPA generation, primarily as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment, which caused a corresponding increase in other purchased power and transmission,

•

a $60.8 million increase due to market-based rates in Virginia beginning July 1, 2007 (See “Business—Regulatory Framework Affecting Allegheny” above and Note 4, “Rates and Regulation,” for additional information regarding market-based rates in Virginia),

•

a $52.0 million increase, primarily due to a net increase in the price of purchased power from AE Supply for Pennsylvania customers, which is passed on to AE Supply under the terms of a power supply agreement between West Penn and AE Supply,

•

a $33.9 million increase, primarily due to the January 1, 2007 activity between Potomac Edison and Monongahela discussed above (Monongahela’s revenues relating to this agreement are included in the Generation and Marketing segment) and

•

a $17.7 million increase due to the West Virginia Rate Order, which approved an increase in generation rates charged to customers (resulting in greater costs to the Delivery and Services segment and greater revenues to the Generation and Marketing segment),

•

partially offset by a $21.8 million decrease due to the expiration of a contract to supply power for Monongahela’s former Ohio electric service territory through May 2007.

Purchased power from PURPA generation decreased $45.5 million for 2007 compared to 2006, primarily as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment, partially offset by increased power purchased from the AES Warrior Run PURPA generation facility, primarily due to a scheduled outage at that facility during 2006 that did not recur during 2007.

Other purchased power and transmission decreased $100.5 million for 2006 compared to 2005, primarily due to:

•

a $74.0 million decrease due to milder weather and lower industrial usage, partially offset by increased load growth from new customers and customer usage,

•

a $70.8 million decrease related to the expiration of a contract with one large industrial customer in Maryland in December 2005,

•

a $39.4 million decrease as a result of commercial and industrial customers electing third-party generation providers in Maryland and

•

a $36.6 million decrease related to the sale of Monongahela’s Ohio service territory on December 31, 2005,

•

partially offset by a $54.5 million increase, primarily due to a net increase in the price of purchased power from AE Supply for Pennsylvania customers, effective January 1, 2006, as a result of a rate increase arising from a settlement approved by the Pennsylvania PUC and a $65.9 million increase as a result of the transition to market-based generation rates for Maryland commercial and industrial customers.

Purchased power from PURPA generation decreased $5.2 million for 2006 compared to 2005, primarily due to decreased power purchased from the AES Warrior Run PURPA generation facility due to a scheduled outage at that facility during 2006 and a decrease in the contractual capacity rate at that facility.

Loss on Sale of Ohio T&D Assets: During 2005, the Delivery and Services segment recorded a loss of $29.3 million in connection with the sale of Monongahela’s electric T&D assets in Ohio. The loss was based on the estimated value, at December 31, 2005, of Monongahela’s power sales agreement with Columbus Southern to provide power at below-market prices from January 1, 2006 through May 31, 2007, partially offset by approximately $8.0 million, representing the purchase price less the net book value of the assets at December 31, 2005 and approximately $2.0 million in expenses associated with the sale.

Deferred Energy Costs, Net: Deferred energy costs, net represents a component of expense to reconcile the period in which increases or decreases in certain energy costs are incurred to the period in which such costs are recovered in rates. Deferred energy costs relate to the following:

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 (the “AES Warrior Run Surcharge”). Any under-recovery or over-recovery of net costs is being deferred pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge.

Market-based Maryland Generation Costs

Potomac Edison is authorized by the Maryland PSC to recover the costs associated with the generation component of power sold to certain commercial and industrial customers who did not choose a third-party alternative generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet relative to any under-recovery or over-recovery for the generation component of costs charged to Maryland commercial and industrial customers. Deferred energy costs, net relate, in part, to the recovery from, or payment to, customers related to these generation costs, to the extent amounts paid for generation costs differ from prices currently charged to customers.

Deferred energy costs, net were as follows:


(In millions)	2007			2006		2005
Deferred energy costs, net:
PURPA generation	$	(3.1	)	$	4.3	$	(0.8	)
Market-based generation and other costs		0.3			3.3		(0.7	)

Total deferred energy costs, net	$	(2.8	)	$	7.6	$	(1.5	)

The $10.4 million change in deferred energy costs, net for 2007 compared to 2006 represents a net credit to expense, primarily related to the AES Warrior Run PURPA generation facility and decreased deferred market-based Maryland generation costs.

The $9.1 million change in deferred energy costs, net for 2006 compared to 2005 represents a net expense, primarily related to the PURPA facilities described above and increased deferred market-based Maryland generation costs.

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


(In millions)	2007		2006		2005
Operations and maintenance	$	342.5	$	344.0	$	388.5

Operations and maintenance expenses decreased $1.5 million for 2007 compared to 2006, primarily due to:

•

a $9.8 million decrease in contractor services and

•

a $2.9 million decrease in insurance expense, primarily due to reduced claim reserves,

•

partially offset by a $5.5 million increase in labor and overhead expense and a $5.2 million increase in outside services expense, primarily due to a $4.6 million contingent fee relating to a consulting project and increased legal fees.

Operations and maintenance expenses decreased $44.5 million for 2006 compared to 2005, primarily due to:

•

approximately $20 million of reduced expenses primarily due to a $15 million charge associated with an arbitration settlement in 2005 and a $4.9 million environmental insurance settlement credit during 2006,

•

a $17.6 million decrease in equipment procurement and subcontracting costs associated with a construction services project that was completed during the second quarter of 2006 and

•

a $13.1 million decrease in salaries and wages expenses, primarily due to a decrease in the number of information technology employees as a result of the outsourcing of this function during 2005,

•

partially offset by an $11.4 million increase in outside service expenses, primarily due to costs associated with the implementation of Allegheny’s information technology initiatives.

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


(In millions)	2007		2006		2005
Depreciation and amortization	$	162.4	$	151.3	$	153.6

Depreciation and amortization expenses increased $11.1 million for 2007 compared to 2006, primarily due to increased depreciation resulting from net property, plant and equipment additions, amortization of regulatory assets and the West Virginia Rate Order, which shortened the depreciable lives of certain T&D assets.

Depreciation and amortization expenses decreased $2.3 million for 2006 compared to 2005, primarily due to the sale of Monongahela’s electric T&D assets in Ohio and the retirement of certain software that became fully amortized during 2006.

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


(In millions)	2007		2006		2005
Taxes other than income taxes	$	134.0	$	122.0	$	130.4

Taxes other than income taxes increased $12.0 million for 2007 compared to 2006, primarily due to:

•

a $7.3 million increase, primarily due to tax benefits recorded during 2006 as a result of the conclusion of a tax audit and

•

a $7.0 million increase in gross receipts tax, primarily due to increased taxable revenues in Pennsylvania.

Taxes other than income taxes decreased $8.4 million for 2006 compared to 2005, primarily due to tax benefits recorded as a result of the conclusion of a tax audit.

Other Income and Expenses, Net

Other income and expenses, net were as follows:


(In millions)	2007		2006		2005
Other income and expenses, net	$	16.2	$	22.2	$	24.2

Other income and expenses, net decreased $6.0 million for 2007 compared to 2006, primarily as a result of a $2.7 million decrease in interest income on investments due to lower investment balances and a $2.4 million decrease related to premium services.

Other income and expenses, net decreased $2.0 million for 2006 compared to 2005, primarily as a result of proceeds received from unregulated investments during 2005.

Interest Expense and Preferred Dividends:

Interest expense and preferred dividends were as follows:


(In millions)	2007		2006		2005
Interest expense and preferred dividends	$	74.0	$	81.4	$	123.3

Interest expense and preferred dividends decreased $7.4 million for 2007 compared to 2006, primarily due to lower average debt outstanding and the write-off of prior deferred financing costs during 2006 that did not recur during 2007.

Interest expense and preferred dividends decreased $41.9 million for 2006 compared to 2005, primarily due to:

•

$21.0 million of costs related to the April 2005 tender offer for Capital Trust’s outstanding Trust Preferred Securities and

•

a $20.9 million decrease in interest expense on long-term debt, primarily due to lower average debt outstanding.

See Note 11, “Capitalization and Short-Term Debt,” for additional information regarding Allegheny’s debt.

Income Tax Expense

The effective tax rate for 2007 was 39.9%. Income tax expense for 2007 was higher than the income tax expense calculated at federal statutory tax rate of 35%, primarily due to state taxes that increased the rate by 2.3%, rate-making effects of depreciation that increased the rate by 3.0% and changes in tax reserves related to uncertain tax positions that increased the rate by 1.4%, offset by consolidated tax savings and amortization of investment tax credit that reduced the rate by 1.8%.

The effective tax rate for 2006 was 30.7%. Income tax expense for 2006 was lower than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to the Delivery and Services segment’s share of consolidated tax savings and a $9.1 million benefit due to the resolution of federal and state tax audit issues.

The effective tax rate for 2005 was 32.5%. Income tax expense for 2005 was lower than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to the Delivery and Services segment’s share of consolidated tax savings.

Discontinued Operations

Income (loss) from discontinued operations, net of tax for the Delivery and Services segment was as follows:


(In millions)	2007		2006			2005
Income (loss) from discontinued operations, net of tax	$	—	$	(1.0	)	$	1.0

The $2.0 million increase in loss from discontinued operations, net of tax for 2006 compared to 2005 was due to additional business and occupation taxes recorded as a result of the conclusion of an audit.

Generation and Marketing

The following table provides electricity generation information, excluding kWhs consumed by pumping at the Bath County, Virginia hydroelectric station:


	2007	2006	2005	2007 Change		2006 Change
Generation (million kWhs)	48,235	48,606	48,100	(0.8	)%	1.1	%

Operating Revenues

Operating revenues were as follows:


(In millions)	2007		2006		2005
Revenue from affiliates	$	1,654.1	$	1,423.2	$	1,501.5
PJM revenue, net		430.4		393.0		200.2
Fort Martin scrubber surcharge		17.5		—		—
Other, including cash flow hedges and trading activities, net		39.3		18.2		1.6

Total operating revenues	$	2,141.3	$	1,834.4	$	1,703.3

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

AE Supply currently provides Potomac Edison and West Penn with a majority of the power necessary to meet their PLR obligations under power sales agreements that have both fixed-price and market-based pricing components. In addition, through December 31, 2006, AE Supply had a power sales agreement with Potomac Edison to provide the power necessary to meet Potomac Edison’s West Virginia load obligation at a fixed rate. In connection with the Asset Swap, Monongahela assumed the obligation to supply power to serve Potomac Edison’s West Virginia load. Thus, effective January 1, 2007, Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela at a prorated share of overall Monongahela generation costs and associated revenue. Effective with the institution under the 2007 West Virginia Rate Order of the ENEC for Allegheny’s West Virginia service territory, the amount charged to Potomac Edison reflects the adjustment for over and/or under recovery. See “Business – Fuel, Power and Resource Supply” and “Business— Regulatory Framework Affecting Allegheny” above, Note 4, “Rates and Regulation” and Note 7 “Asset Swap,” for additional information.

Through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela sold the power that it generated from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchased from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. AE Supply recorded these transactions with Monongahela as either affiliated revenue or affiliated purchased power and transmission expense, depending on energy requirements as determined on an hourly basis. Effective January 1, 2007, 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 its contractual obligations. The net revenue from these PJM purchases and sales is reflected in wholesale and other revenues, net.

The average rate at which the Generation and Marketing segment sold power to the Distribution Companies was $38.43, $35.17 and $33.01 per MWh for the years ended December 31, 2007, 2006 and 2005, respectively.

Revenue from affiliates increased $230.9 million for 2007 compared to 2006, primarily due to:

•

a $92.5 million increase in Monongahela’s West Virginia affiliated revenues due to an increase in sales volume and price, including a $66.2 million increase reflecting the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment, causing a corresponding increase in both revenues and purchased power, and an $17.7 million increase due to the West Virginia Rate Order, which increased generation rates charged to customers (such increases result in greater costs to the Delivery and Services segment and greater revenues to the Generation and Marketing segment),

•

a $52.0 million increase due to higher generation rates charged to Pennsylvania customers, which are passed on to AE Supply under the terms of a power supply agreement between West Penn and AE Supply,

•

a $51.4 million increase as a result of higher prices during the third and fourth quarter 2007 due to a new power sales agreement with Potomac Edison effective July 1, 2007, which were partially offset by decreased sales volumes for certain of Potomac Edison’s customers in Virginia,

•

a $33.9 million increase in affiliated revenues from Potomac Edison due to the assignment, in connection with the Asset Swap, of AE Supply’s below-market power supply agreement to serve Potomac Edison’s West Virginia load obligations, as a result of which, Potomac Edison now purchases from Monongahela the power necessary to service its West Virginia customers at rates that are greater than the rates under the AE Supply agreement at a prorated share of overall Monongahela generation costs,

•

a $6.1 million increase related to higher contractual rates with increased sales volumes for certain of Potomac Edison’s customers in Maryland and

•

increased sales volumes as a result of increases in HDD and CDD and increased customer load,

•

partially offset by an $18.7 million decrease in ancillary service revenues from the Delivery and Services segment due to a contract expiration.

Revenue from affiliates decreased $78.3 million for 2006 compared to 2005, primarily due to:

•

a $70.8 million decrease in revenue related to the expiration of a contract with one large industrial customer in Maryland in December 2005,

•

a $20.9 million decrease in revenue related to decreased sales volumes from certain of Potomac Edison’s commercial and industrial customers in Maryland,

•

a $14.9 million decrease in revenue related to decreased sales volumes as a result of Monongahela no longer serving customers in its former Ohio service territory, which was sold on December 31, 2005, and the concurrent expiration of a power supply contract between Monongahela and AE Supply and

•

decreased sales volumes as a result of milder weather, which caused a decrease in electricity demand by the Delivery and Services segment,

•

partially offset by a $67.5 million increase in affiliated revenues related to higher generation rates charged to Pennsylvania customers, effective January 1, 2006, as a result of a West Penn settlement approved by the Pennsylvania PUC.

PJM revenue, net: PJM revenue was as follows:


(In millions)	2007			2006			2005
PJM Revenue:
Generation sold into PJM	$	2,418.9		$	2,055.4		$	2,536.1
Power purchased from PJM		(1,988.5	)		(1,662.4	)		(2,335.9	)

Net		430.4			393.0			200.2

PJM revenue, net increased $37.4 million for 2007 compared to 2006, primarily due to higher revenues from generation sold into PJM, partially offset by an increase in power purchased from PJM. Revenues from generation sold into PJM were higher, primarily due to an increase in the market price of power, increased PJM capacity market revenues and an increase in the dispatch of gas-fired generation facilities as a result of higher market prices for electricity, partially offset by a decrease in MWhs generated due to a decrease in supercritical plant availability. Power purchased from PJM increased due to an increase in the market price of power, increased sales volume from the Distribution Companies due to increases in HDD and CDD, increased customer load, increased sales volumes for certain of Potomac Edison’s customers in Maryland and Virginia and the transfer of Monongahela’s PURPA contracts to the Generation and Marketing segment from the Delivery and Services segment. These amounts were partially offset by the expiration of certain contracts to provide ancillary load services.

PJM revenue, net increased $192.8 million for 2006 compared to 2005, primarily due to lower purchased power from PJM, partially offset by a decrease in revenues from generation sold into PJM. Revenues from generation sold into PJM were lower primarily due to a decrease in the market price of power and the March 2006 assignment of rights to generation from OVEC in connection with the sale of a portion of AE’s equity interest in OVEC, partially offset by a 1.1% increase in MWhs generated. During 2006, the weighted average “round-the-clock” price for power in Allegheny’s region of PJM, the APS Zone of the PJM market, was approximately $46.50 per MWh, which represents a decrease of approximately 20% compared to 2005. The increase in MWhs generated was due to increased availability of Allegheny’s supercritical plants. Power purchased from PJM decreased due to a decrease in the market price of power and milder weather. In addition, power purchased from PJM decreased due to the expiration in December 2005 of a contract between Potomac Edison and one large industrial customer in Maryland that is no longer required to be served by AE Supply, a

decrease in sales volume related to certain of Potomac Edison’s commercial and industrial customers in Maryland and reduced power needs because Monongahela is no longer serving customers in its former Ohio service territory, which was sold on December 31, 2005.

Fort Martin scrubber surcharge:

The $17.5 million Fort Martin scrubber surcharge revenue relates to an environmental control surcharge that Monongahela and Potomac Edison impose on their West Virginia retail customers following the April 2007 Fort Martin securitization financings. This surcharge is intended to recover a portion of the specific costs to construct the Scrubbers at Fort Martin and certain related financing costs and will result in no net income or loss. A regulatory liability is recorded for amounts billed in excess of costs incurred. See “Business—Regulatory Framework Affecting Allegheny” above and Note 11, “Capitalization and Short-Term Debt” for additional information regarding the securitization transaction.

Other Operating Revenues:

Other operating revenues increased $21.1 million for 2007 compared to 2006, primarily due to increased marketing contract sales to third parties and the results of risk management and trading activities, including cash flow hedges and emission allowance strategies.

Other operating revenues increased $16.6 million for 2006 compared to 2005, primarily due to increased marketing contract sales to third parties, proceeds from the sale of excess PRB coal and an increase in net gains from cash flow hedges and trading activities.

Fair Value of Contracts: Derivatives are recorded in Allegheny’s Consolidated Balance Sheets at fair value, with changes in the fair value of the derivative contract included in revenues or expenses on the Consolidated Statements of Income unless the derivative falls within the “normal purchases and normal sales” scope exception of SFAS 133 or is designated as a hedge for accounting purposes. The normal purchases and normal sales scope exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under accrual accounting and, therefore, are not recorded on the balance sheet at fair value. For certain transactions that are designed to hedge the cash flows of a forecasted transaction, the effective portion of the hedge is recorded as a separate component of stockholders’ equity under the caption “Accumulated other comprehensive income (loss)” and subsequently reclassified into earnings when the forecasted transaction is completed or settled. Changes in any ineffective portion of the hedge are immediately recognized in earnings.

Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. Fair values are subject to change in the near term and reflect management’s best estimate based on various factors. In establishing the fair value of commodity contracts that do not have quoted prices, such as physical contracts, over-the-counter options and swaps, management uses available market data and pricing models to estimate fair values. Estimating fair values of instruments that do not have quoted market prices requires management’s judgment in determining amounts which could reasonably be expected to be received from, or paid to, a third party in settlement of the instruments. These amounts could be materially different from amounts that might be realized in an actual sale transaction. At December 31, 2007, Allegheny’s portfolio consisted of derivatives with actively quoted prices.

The following table disaggregates the net fair values of derivative contract assets and liabilities, based on the underlying market price source and the contract settlement periods. The table excludes non-derivatives such as Allegheny’s generation assets, the Distribution Companies’ PLR requirements and SFAS 133 scope exceptions under the normal purchase and normal sale election:


	Fair value of contracts at December 31, 2007
Classification of contracts by source of fair value (In millions)	Settlement by:
	2008			2009			2010			2011			2012		Total
Prices actively quoted	$	(14.1	)	$	(5.6	)	$	(5.7	)	$	(1.5	)	$	—	$	(26.9	)
Prices provided by other external sources		—			—			—			—			—		—
Prices based on models		—			—			—			—			—		—

Total	$	(14.1	)	$	(5.6	)	$	(5.7	)	$	(1.5	)	$	—	$	(26.9	)

See Note 12, “Derivative Instruments and Hedging Activities,” for additional information.

Operating Expenses

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


(In millions)	2007		2006		2005
Fuel	$	930.8	$	842.7	$	759.1

Total fuel expense increased by $88.1 million for 2007 compared to 2006, primarily due to a $40.0 million increase in coal expense, a $29.9 million increase in natural gas expense and a $12.8 million increase in emission allowance expense. The increase in coal expense was primarily due to an increase in the average price of coal of $2.69 per ton. The increase in natural gas expense was primarily due to a 3.8 million decatherm increase in the amount of natural gas burned. The increase in the amount of natural gas burned was primarily due to an increase in the dispatch of gas-fired generation facilities as a result of higher market prices for power.

Total fuel expense increased by $83.6 million for 2006 compared to 2005, primarily due to a $98.3 million increase in coal expense, partially offset by a $20.8 million decrease in natural gas expense. The increase in coal expense was due to an increase in the average price of coal of $3.27 per ton and a 1.0 million-ton increase in the amount of coal burned. The increase in the amount of coal burned was primarily due to an increase in the use of lower British Thermal Unit (“BTU”) PRB coal and an increase in total MWhs generated. The decrease in natural gas expense was due to a decrease in the average price of natural gas of $1.19 per decatherm and a 1.5 million decatherm decrease in the amount of natural gas burned.

Purchased Power and Transmission: Purchased power and transmission expenses, including purchases from qualifying facilities under PURPA, were as follows:


(In millions)	2007		2006		2005
Other purchased power and transmission	$	41.9	$	33.2	$	81.0
From PURPA generation		66.2		—		—

Purchased power and transmission	$	108.1	$	33.2	$	81.0

Purchased power and transmission expenses increased $74.9 million for 2007 compared to 2006, primarily due to a $66.2 million increase in purchased power from PURPA generation as a result of a January 1, 2007 transfer of Monongahela’s PURPA contracts from the Delivery and Services segment to the Generation and Marketing segment.

Purchased power and transmission expenses decreased $47.8 million for 2006 compared to 2005, primarily due to the March 2006 assignment of AE Supply’s rights to generation from OVEC in connection with the sale of a portion of AE’s equity interest in OVEC, a reduction in contracts that were designated as normal purchase and normal sale and a refund received on certain transmission charges.

Gain on Sale of OVEC Power Agreement and Shares: On December 31, 2004, AE sold a 9% equity interest in OVEC to Buckeye Power Generating, LLC. The gain on sale of OVEC power agreement and shares were $6.1 million for 2006 and represent the release, in connection with the fulfillment of certain post-closing commitments of the parties, of the proceeds of the transaction that were placed in escrow at the time of the sale.

Deferred Energy Costs, Net: Deferred energy costs, net represents a component of expense to reconcile the period in which increases or decreases in certain energy costs are incurred to the period in which such costs are recovered in rates. Deferred energy costs relate primarily to the following:

Expanded Net Energy Cost (“ENEC”)

The May 22, 2007 West Virginia Rate Order re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues will be tracked for under and/or over recoveries, and revised ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, will be deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.” By order dated January 14, 2008, the West Virginia PSC approved a modification to the ENEC directing interest earnings on the Fort Martin scrubber project escrow fund to be applied to the ENEC. See “Business—Regulatory Framework Affecting Allegheny” above and Note 4, “Rates and Regulation,” for additional information.

Grant Town PURPA Generation Facility

Monongahela acquires energy from the Grant Town PURPA generation facility in West Virginia. The West Virginia PSC approved an amendment to the Electric Energy Purchase Agreement between Monongahela and American Bituminous Power Partners, L.P., the owners of the Grant Town PURPA generation facility, in April 2006. The amendment provided for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia PSC authorized Monongahela to institute a temporary surcharge designed to recover the increase in costs from West Virginia customers, as well as a deferred accounting mechanism by which actual aggregate amounts of the incremental cost increase were tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge. As a result of the West Virginia Rate Order, the increase in costs discussed above are included in the ENEC. Effective with the May 22, 2007 establishment of the ENEC, deferred costs related to the Grant Town PURPA generation facility were recorded within the Generation and Marketing segment and were no longer recorded within the Delivery and Services segment. See “Business—Regulatory Framework Affecting Allegheny” above and Note 4, “Rates and Regulation,” for additional information.

Deferred energy costs, net were as follows:


(In millions)	2007			2006		2005
Deferred energy costs, net	$	(7.3	)	$	—	$	—

The $7.3 million change in deferred energy costs, net for 2007 compared to 2006 represents a net credit to expense, related to the Grant Town PURPA generation facility and the implementation of the ENEC.

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)	2007		2006		2005
Operations and maintenance	$	353.9	$	349.0	$	356.2

Operations and maintenance expenses increased $4.9 million for 2007 compared to 2006, primarily due to:

•

an $8.1 million reduction in estimated site remediation costs associated with a previously terminated generation project and a $6.4 million reversal of a guarantee liability associated with the Hunlock Creek Energy Ventures (“HCEV”) partnership, both of which occurred during 2006 and did not recur during 2007,

•

partially offset by a $6.5 million reduction during 2007 in estimated site remediation costs associated with an ash disposal site and a $2.5 million decrease in insurance expense due to reduced claims.

Operations and maintenance expenses decreased $7.2 million for 2006 compared to 2005, primarily due to:

•

a $14.5 million decrease in other operation and maintenance expense, primarily due to a $6.4 million reversal of a guarantee liability associated with the HCEV partnership and an $8.1 million reduction in accrued site remediation reserves associated with a previously terminated generation project and

•

a $2.1 million decrease in salaries and wages expense due to a decrease in the number of information technology employees as a result of the outsourcing of this function during 2005,

•

partially offset by a $2.7 million increase in contract work, primarily due to insurance proceeds received during 2005 related to Hatfield’s Ferry Unit No. 2, which were recorded as an offset to contract work expense, increased planned maintenance costs, and an $8.0 million increase in outside services expense associated with the implementation of Allegheny’s information technology initiatives.

See Note 25, “Guarantees and Letters of Credit” for additional information related to the HCEV partnership interest transaction.

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


(In millions)	2007		2006		2005
Depreciation and amortization	$	114.6	$	121.8	$	154.6

Depreciation and amortization expense decreased $7.2 million for 2007 compared to 2006, primarily due to the West Virginia Rate Order, which extended the depreciable lives of regulated generating assets, partially offset by increased depreciation resulting from net property, plant and equipment additions.

Depreciation and amortization expense decreased $32.8 million for 2006 compared to 2005, primarily due to the extension of the depreciable lives of Allegheny’s unregulated coal-fired generation facilities, partially offset by increased depreciation resulting from net property, plant and equipment additions. The extension of the depreciable lives of Allegheny’s unregulated coal-fired generation facilities is discussed further at Note 20, “Review of Estimated Remaining Service Lives and Depreciation Practices.”

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


(In millions)	2007		2006		2005
Taxes other than income taxes	$	77.8	$	81.3	$	82.1

Taxes other than income taxes decreased $3.5 million for 2007 compared to 2006, primarily due to a $1.4 million decrease in franchise taxes due to the conclusion of a tax audit during the second quarter of 2007 and a $0.9 million decrease in business and occupation tax due to an increase in a revitalization credit.

Other Income and Expenses, Net

Other income and expenses, net were as follows:


(In millions)	2007		2006		2005
Other income and expenses, net	$	26.8	$	14.8	$	21.1

Other income and expenses, net increased $12.0 million for 2007 compared to 2006, primarily due to an $8.4 million gain relating to an exchange transaction involving La Paz, Arizona real estate during the third quarter of 2007 and a $2.8 million increase in interest and dividend income on investments due to a higher average investment balance and higher interest rates on investments.

Other income and expenses, net decreased $6.3 million for 2006 compared to 2005, primarily as a result of $11.2 million received from a former trading executive’s forfeited assets during 2005, partially offset by a $5.1 million increase in interest income on investments due to higher interest rates.

Interest Expense and Preferred Dividends

Interest expense and preferred dividends were as follows:


(In millions)	2007		2006		2005
Interest expense and preferred dividends	$	120.2	$	193.1	$	318.2

Interest expense and preferred dividends decreased $72.9 million for 2007 compared to 2006, primarily due to the reversal of accrued interest resulting from the settlement of Allegheny’s litigation with Merrill Lynch, lower average debt outstanding and increased capitalized interest due to capital projects, partially offset by increased interest associated with the April 2007 issuance of environmental control bonds. See Note 28, “Subsequent Event,” for additional information regarding the settlement of Allegheny’s litigation with Merrill Lynch.

Interest expense and preferred dividends decreased $125.1 million for 2006 compared to 2005, primarily due to:

•

$32.6 million recorded during 2005 to reflect the premium and associated costs to redeem AE Supply’s outstanding 10.25% and 13% Senior Notes,

•

$26.2 million in costs related to the April 2005 tender offer for Capital Trust’s outstanding Trust Preferred Securities,

•

$38.5 million in interest expense recorded during the first quarter of 2005 related to a court decision in the litigation involving Merrill Lynch and

•

a $19.1 million decrease in interest expense on long-term debt, primarily due to lower average debt outstanding.

For additional information regarding Allegheny’s debt, see Note 11, “Capitalization and Short-Term Debt.” For additional information regarding the litigation involving Merrill Lynch, see Note 27, “Commitments and Contingencies.”

Income Tax Expense

The effective tax rate for 2007 was 36.7%. Income tax expense for 2007 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state taxes that increased the rate by 2.7%, partially offset by the valuation adjustment of the Pennsylvania net operating loss, which decreased the rate by 1.0%.

The effective tax rate for 2006 was 39.8%. Income tax expense for 2006 was higher than the income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state income taxes and a $15.7 million charge due to the effects of resolving tax audit issues.

The effective tax rate for 2005 was 37.7%. The effective tax rate was higher than the income tax expense calculated at the federal statutory rate of 35%, primarily due to state income taxes and the Generation and Marketing segment’s share of consolidated tax savings.

Minority Interest in Net Income of Subsidiary

Minority interest in net income of subsidiary, which primarily represents an equity interest in AE Supply, was $3.1 million, $2.6 million and $0.6 million in 2007, 2006 and 2005, respectively.

Discontinued Operations

Income (loss) from discontinued operations, net of tax was as follows:


(In millions)	2007		2006		2005
Income (loss) from discontinued operations, net of tax	$	—	$	1.6	$	(7.2	)

Income from discontinued operations, net of tax decreased $1.6 million for 2007 compared to 2006, primarily due to adjustments associated with the sale of AE Supply’s natural gas-fired peaking facilities in 2006.

Loss from discontinued operations, net of tax decreased $8.8 million for 2006 compared to 2005, primarily due to increased income reflecting adjustments associated with the sale of AE Supply’s natural gas-fired peaking facilities, partially offset by income in 2005 associated with AE Supply’s Wheatland generation facility, which was sold in August 2005.

See Note 14, “Discontinued Operations,” for additional information.

Cumulative Effect of Accounting Change, Net

In connection with its adoption of FASB Interpretation 47, “Accounting for Conditional Asset Retirement Obligations,” Allegheny recorded a charge of $5.9 million, net of income taxes, as the cumulative effect of an accounting change as of December 31, 2005.

Liquidity and Capital Requirements

To meet cash needs for operating expenses, the payment of interest, retirement of debt and construction programs, Allegheny has historically used internally generated funds (net cash provided by operations less common and preferred dividends) and external financings, including the sale of common and preferred stock, debt instruments, installment loans and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions and Allegheny’s cash needs and capital structure objectives. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and upon market conditions.

Allegheny manages short-term obligations with cash on hand and amounts available under revolving credit facilities. AE manages excess cash through Allegheny’s internal money pool. The money pool provides funds to approved AE subsidiaries at the lower of the Federal Reserve’s federal funds effective interest rate for the previous day, or the Federal Reserve’s seven day commercial paper rate for the previous day, less four basis points. AE and AE Supply can only place money into the money pool. Monongahela, West Penn and Potomac Edison can either place money into, or borrow money from, the money pool. AGC can only borrow money from the money pool.

At December 31, 2007 and 2006, Allegheny had cash and cash equivalents of $258.8 million and $114.1 million, respectively and current restricted funds of $47.5 million and $12.9 million, respectively. Current restricted funds at December 31, 2007 included $35.2 million of funds collected from West Virginia customers that will be used to service the environmental control bonds issued in April 2007 in connection with the construction of the Scrubbers at Fort Martin and $12.3 million of intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. Current restricted funds at December 31, 2006 related to intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. In addition, at December 31, 2007, Allegheny had $347.0 million of long-term restricted funds relating to proceeds from the April 2007 issuance of environmental control bonds. See “2007 Debt Activity” below.

Allegheny had collateral deposits at December 31, 2007 and 2006 of $59.5 million and $39.4 million, respectively. These deposits are posted as security with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. These amounts were included in “Current assets” on the Consolidated Balance Sheets.

At December 31, 2006, Allegheny had posted cash collateral $15.3 million, as security for surety bonds issued by a third party. These funds were invested in a temporary investment fund and were included in the caption “Other” within the “Investments and Other Assets” section of the Consolidated Balance Sheets.

At December 31, 2007, Allegheny’s total borrowing capacity under AE’s and AE Supply’s respective revolving credit facilities and the use of this borrowing capacity were as follows:


(In millions)	Total Capacity		Borrowed		LOC’s Issued			Available Capacity
AE Revolving Credit Facility	$	400.0	$	—	$	6.7	(a)	$	393.3
AE Supply Revolving Facility		400.0		—		—			400.0

Total	$	800.0	$	—	$	6.7		$	793.3

(a)	This amount represents a letter of credit issued in connection with a contractual obligation of Allegheny Ventures that expires in July 2008.

In addition to the amounts shown in the table above, AE Supply has a $3.0 million letter of credit outstanding that expires in February 2009 and was not issued under either AE’s revolving credit facility or AE Supply’s revolving credit facility.

Allegheny’s consolidated capital structure, excluding short-term debt and minority interest, as of December 31, 2007 and 2006, was as follows:


	2007			2006
(In millions)	Amount		%	Amount		%
Long-term debt	$	4,039.3	61.4	$	3,585.2	63.0
Common equity		2,535.4	38.6		2,080.4	36.6
Preferred equity		—	—		24.0	0.4

Total	$	6,574.7	100.0	$	5,689.6	100.0

2007 Debt Activity

In April 2007, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $344 million and $115 million, respectively, of Senior Secured Sinking Fund Environmental Control Bonds, Series A. 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 in several tranches with interest rates ranging from 4.98% to 5.52% and maturities ranging from July 2014 to July 2027. Net proceeds from the sale of the bonds represent restricted funds and will be used to fund the majority of costs to construct and install the Scrubbers at Fort Martin.

In September 2007, AE Supply amended its credit facility to increase the size of its revolving credit facility from $200 million to $400 million.

On October 22, 2007, at the request of AE Supply, Pleasants County, West Virginia and Harrison County, West Virginia issued $142 million of tax-exempt pollution control refunding bonds and $73.5 million of tax-exempt solid waste disposal refunding bonds, respectively (collectively, the “2007 AE Supply Bonds”). The 2007 AE Supply Bonds were issued to provide funds to repay pollution control and solid waste disposal bonds previously issued by these counties to finance certain facilities at Allegheny’s Pleasants and Harrison generation facilities. Each series of 2007 AE Supply Bonds has a 30-year maturity and a 10-year call provision, and the weighted average interest rate of the 2007 AE Supply Bonds is 5.34%. Each series of 2007 AE Supply Bonds will be payable solely from payments to be made under a corresponding note from AE Supply.

On December 6, 2007, West Penn issued $275 million aggregate principal amount of 5.95% First Mortgage Bonds that mature in 2017. Proceeds from the First Mortgage Bonds were used in 2008 to repay a note payable and for other general corporate purposes.

On December 24, 2007, TrAIL Company issued a $10.0 million promissory note that matures on September 12, 2008. Proceeds from the promissory note will be used to fund the construction of the TrAIL Project pending completion of long-term financing for the TrAIL Project.

Allegheny made various other debt payments during 2007.

Issuances and repayments of indebtedness, by entity, during 2007 were as follows:


(In millions)	Issuances			Repayments
Monongahela:
Environmental Control Bonds	$	344.5		$	—
Pollution Control Bonds		—			15.5
Potomac Edison:
Environmental Control Bonds		114.8			—
West Penn:
First Mortgage Bonds		275.0			—
Transition Bonds (a)		5.5			79.9
AE Supply:
Pollution Control Bonds		222.5			237.1
AE Supply Credit Facility		—			175.0
TrAIL Company:
Short-Term Promissory Note		10.0			—
Eliminations (b)		(7.0	)		(5.3	)

Consolidated Total	$	965.3		$	502.2

(a)	The issuance amounts represent interest that was accrued and added to the principal amount of certain of the bonds.

(b)	Represents the elimination of certain pollution control bonds for which Monongahela and AE Supply are co-obligors.

2006 Debt Activity

On May 2, 2006, AE Supply entered into a new $967 million senior credit facility (the “AE Supply Credit Facility”) comprised of a $767 million term loan (the “AE Supply Term Loan”) and a $200 million revolving credit facility (the “AE Supply Revolving Facility”), which was increased to $400 million in September 2007. The AE Supply Credit Facility matures in 2011. Proceeds from the AE Supply Credit Facility were used to refinance $967 million outstanding under AE Supply’s prior term loan. The AE Supply Revolving Facility can also be used, if availability exists, to issue letters of credit.

On May 22, 2006, AE and AE Supply entered into a new $579 million credit facility (the “AE Credit Facility”) comprised of a $400 million senior unsecured revolving credit facility (the “AE Revolving Credit Facility”) and a $179 million senior unsecured term loan (the “AE Term Loan”). The AE Credit Facility matures in 2011. Proceeds from the AE Credit Facility were used to refinance the $179 million outstanding under AE’s prior credit facility and to continue $135 million of letters of credit issued under AE’s prior revolving facility. In addition, subject to certain limitations, AE Supply is permitted to request letters of credit in an amount not in excess of $50 million directly under the AE Revolving Credit Facility. AE is permitted to request letters of credit in an amount not in excess of $125 million on behalf of AE Supply and its subsidiaries.

In August 2006, West Penn issued $145 million aggregate principal amount of 5.875% First Mortgage Bonds that mature in 2016. Proceeds from the First Mortgage Bonds were used to repay a portion of a note payable, to pay a dividend to Allegheny and for other general corporate purposes.

In September 2006, Monongahela issued $150 million aggregate principal amount of 5.70% First Mortgage Bonds that mature in 2017. Monongahela used the net proceeds from the sale of the $150 million aggregate principal amount of 5.70% First Mortgage Bonds, plus available cash on hand, to fund the repayment at maturity of $300 million aggregate principal amount of its 5.0% First Mortgage Bonds.

In October 2006, Potomac Edison issued $100 million aggregate principal amount of 5.80% First Mortgage Bonds that mature in 2016. Potomac Edison used the net proceeds from the sale of the bonds, plus available cash on hand, to fund the repayment at maturity of $100 million aggregate principal amount of its 5.0% Medium-Term Notes.

Allegheny made various other debt payments during 2006.

Issuances and repayments of indebtedness, by entity, during 2006 were as follows:


(In millions)	Issuances		Repayments
AE:
AE Credit Facility	$	219.1	$	219.1
2005 AE Credit Facility		—		199.0
Monongahela:
First Mortgage Bonds		150.0		300.0
AE Supply:
AE Supply Credit Facility		967.0		220.0
2005 AE Supply Term Loan		—		989.0
Potomac Edison:
First Mortgage Bonds		100.0		—
Medium-Term Notes		—		100.0
West Penn:
First Mortgage Bonds		145.0		—
Transition Bonds (a)		5.2		75.8

Consolidated Total	$	1,586.3	$	2,102.9

(a)	The issuance amounts represent interest that was accrued and added to the principal amount of certain of the bonds.

During 2008, AE Supply made payments of $125 million on its credit facility.

Asset Sales

In May 2006, AE Supply sold a receivable from the Tennessee Valley Authority (the “TVA”) held by its Gleason operating unit for net proceeds of approximately $27.8 million. In December 2006, AE Supply completed the sale of the remaining assets associated with its Gleason generation facility to the TVA for net proceeds of $23 million.

On December 31, 2005, Monongahela completed the sale of its Ohio T&D assets to Columbus Southern for net proceeds of $51.8 million. The purchase price for the assets was the net book value at the time of closing, plus $10.0 million, less certain property taxes. The sale included a power sales agreement under which Monongahela provided power to Columbus Southern for Monongahela’s former Ohio retail customers from the time of closing through May 31, 2007 at $45 per megawatt-hour, which at the time of the transaction was less than the projected market price for power. During 2005, Monongahela recorded a loss on the sale of $29.3 million based on the estimated value, at December 31, 2005, of Monongahela’s power sales agreement with Columbus Southern to provide power at below-market prices from January 1, 2006 through May 31, 2007, partially offset by approximately $8.0 million, representing the purchase price less net book value of the assets at December 31, 2005 and approximately $2.0 million in expenses associated with the sale.

On September 30, 2005, Monongahela completed the sale of its West Virginia natural gas operations to Mountaineer Gas Holdings Limited Partnership, a partnership composed of IGS Utilities, LLC, IGS Holdings, LLC and affiliates of ArcLight Capital Partners, LLC, for approximately $161.0 million and the assumption of approximately $87.0 million of long-term debt. The assets sold included all of the issued and outstanding capital stock of Mountaineer Gas and certain other assets related to the West Virginia natural gas operations.

In August 2005, AE Supply and its subsidiaries, Allegheny Energy Supply Wheatland Generation Facility, LLC and Lake Acquisition Company, LLC completed the sale of certain assets relating to AE Supply’s Wheatland generation facility (the “Wheatland Assets”) to PSI Energy, Inc. and The Cincinnati Gas & Electric Company for approximately $100 million and the assumption of certain liabilities related to the Wheatland Assets.

During May 2005, Potomac Edison completed the sale of its Hagerstown, Maryland property for $10.6 million in net proceeds.

Dividends

Common stock

On December 17, 2007, AE paid a cash dividend of $0.15 per share to shareholders of record on December 3, 2007. On February 22, 2008, the Board of Directors of AE declared a cash dividend of $0.15 per share on AE’s common stock, payable on March 24, 2008 to shareholders of record on March 10, 2008. AE paid no dividends on its common stock in 2006 or 2005.

Preferred stock

Monongahela paid dividends on its preferred stock of $1.0 million and $1.2 million in 2007 and 2006, respectively.

On September 4, 2007, Monongahela redeemed its outstanding cumulative preferred stock. See Note 11, “Capitalization and Short-Term Debt,” for additional details.

Return of Capital

During October 2005, AE received a return of capital from Monongahela in the amount of $80.0 million, representing a portion of the cash proceeds from the sale of Monongahela’s West Virginia natural gas operations.

Construction and Capital Requirements

In April 2007, Allegheny announced plans to construct PATH, a 290-mile, high-voltage transmission line project (the “PATH Project”). PJM authorized construction of PATH in April 2007. In September 2007, Allegheny entered into a joint venture agreement with AEP to construct PATH. The joint venture, PATH, LLC, is a series limited liability company. The “West Virginia Series” is owned equally by Allegheny and AEP and will build, own and operate approximately 244 miles of 765-kV transmission line from AEP’s Amos substation near St. Albans, West Virginia to Allegheny’s Bedington substation near Martinsburg, West Virginia, through an operating subsidiary. The “Allegheny Series” is 100% owned by Allegheny and, through an operating subsidiary, will build, own and operate approximately 46 miles of twin-circuit 500-kV lines from Bedington to a new substation near Kemptown, Maryland, to be built and owned by Allegheny. Total project costs of the West Virginia Series are expected to be approximately $1.2 billion. Total project costs of the Allegheny Series are expected to be approximately $0.6 billion. PJM, the regional transmission organization, has specified June 2012 as the in-service date for the project.

In February 2006, Allegheny announced plans to construct the Trans-Allegheny Interstate Line (“TrAIL”) project, a new 210-mile, 500-kv extra-high voltage line extending from the Prexy substation in Western Pennsylvania, to east of the Meadow Brook Substation in Northern Virginia at the interconnection with Dominion Virginia Power (“Dominion”). If approved by the Virginia SCC, Allegheny and Dominion will jointly own a 30-mile 500-kv line segment that Dominion will then complete to Loudoun, VA. The TrAIL project also includes new 138 kV transmission lines and related substations. In June 2006, the board of directors of PJM

established the need for a new transmission line extending from Southwestern Pennsylvania through West Virginia to Northern Virginia, and designated Allegheny to build the AP Zone portion of the line. PJM, the regional transmission operator, which is responsible for the operation of and reliability planning for the transmission network in the PJM region, included the new line in its 2006 regional transmission expansion plan. The overall project has a targeted completion date of 2011. Cost estimates for Allegheny’s portion of the project are approximately $820 million.

During 2006, Allegheny began construction of Scrubbers at both its Fort Martin and Hatfield’s Ferry generation facilities. The Scrubbers are expected to be placed into service during 2009. The total project costs for the Scrubbers at Fort Martin and Hatfield’s Ferry are estimated to be approximately $550 million and $725 million, respectively.

Allegheny is funding $450 million of construction costs associated with the construction of the Scrubbers at Fort Martin with proceeds from the environmental control bonds issued in April 2007, which securitized the environmental control surcharge that Monongahela and Potomac Edison charge their West Virginia customers. Allegheny plans to fund the remainder of its capital expenditures with cash on hand, cash from operations and, when necessary, external debt financings.

Allegheny estimates that its cash-based capital expenditures will approximate $1,350 million in 2008 and $1,175 million in 2009, including amounts relating to significant multiple year environmental control and transmission expansion projects. See “Business—Capital Expenditures” above.

Other Matters Concerning Liquidity and Capital Requirements

On January 1, 2007, Allegheny adopted the provisions of FIN 48, which prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on an income tax return. As a result of the implementation, Allegheny recognized additional liabilities related to its uncertain tax positions, which are reflected in the contractual obligations and commitments table below. See Note 6, “Income Taxes,” for additional information.

On September 19, 2005, AE entered into a Professional Services Agreement, under which, on November 1, 2005, the Service Provider assumed responsibility for many of Allegheny’s information technology functions and agreed to assist Allegheny with the installation of an enterprise resource planning system. Unless extended by AE, the Professional Services Agreement will expire on December 31, 2012. Expected cash payments relating to the Professional Services Agreement are included in the contractual obligations and commitments table below.

Allegheny estimates that its contributions to the pension plan during 2008 will approximate $35 million. Allegheny also currently anticipates that it will contribute $15 million to $18 million during 2008 to fund postretirement benefits other than pensions. These anticipated contributions may change in the future if Allegheny’s assumptions regarding prevailing interest rates change, if actual investments under-perform or out-perform estimated returns, if actuarial assumptions or asset valuation methods change or if there are changes to employee benefit and tax laws.

AE 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 the payments due by period for these obligations and commitments, as of December 31, 2007. The table below does not include expected contributions for pension and postretirement benefits other than pensions, contingent liabilities and contractual commitments that were accounted for under fair value accounting. For more information regarding fair value accounting, see “Discussion of Segment Results of Operations-AE’s Generation and Marketing Segment Results.”


Contractual Obligations and Commitments (In millions)	Payments by December 31, 2008		Payments from January 1, 2009 to December 31, 2010		Payments from January 1, 2011 to December 31, 2012		Payments from January 1, 2013 and beyond		Total
Debt (a)	$	105.4	$	234.8	$	1,739.7	$	1,977.1	$	4,057.0
Interest on debt (b)		263.0		491.4		321.5		816.5		1,892.4
Interest rate swap obligations		6.1		12.3		1.0		—		19.4
Capital lease obligations		11.7		18.4		11.0		6.5		47.6
Operating lease obligations		3.5		6.7		6.8		12.7		29.7
PURPA purchased power (c)		238.6		500.0		538.5		4,142.4		5,419.5
Fuel purchase and transportation commitments		716.1		1,010.3		905.6		2,608.6		5,240.6
Uncertain tax positions		14.5		23.0		47.2		—		84.7
Other purchase obligation (d)		27.6		52.8		47.1		—		127.5

Total	$	1,386.5	$	2,349.7	$	3,618.4	$	9,563.8	$	16,918.4

(a)	Does not include unamortized debt expense, discounts, premiums and payments made and debt issued subsequent to December 31, 2007.

(b)

Amounts were based on interest rates as of December 31, 2007 and do not reflect any debt or interest rate changes subsequent to December 31, 2007. Total interest on debt includes $2.8 million in interest that will accrue and be added to the principal amount of West Penn’s $115.0 million of 4.46% Transaction Bonds, Series 2005-A.

(c)	Amounts were calculated based on expected PURPA purchased power prices at December 31, 2007 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 outsourcing of certain information technology functions.

Off-Balance Sheet Arrangements

AE has no off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on its financial condition, 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 will be affected by 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 in 2007, 2006 and 2005 are summarized as follows:


(In millions)	2007			2006			2005
Net income	$	412.2		$	319.3		$	63.1
Loss (income) from discontinued operations, net of tax		—			(0.6	)		6.1
Non-cash items included in income		540.0			468.9			430.1
Pension and other postretirement employee benefit plans contributions		(50.0	)		(78.0	)		(89.1	)
Changes in certain assets and liabilities		52.9			48.7			21.1
Net cash provided by discontinued operations		—			4.8			54.8

Net cash provided by operating activities	$	955.1		$	763.1		$	486.1

Cash flows provided by operating activities for the year ended December 31, 2007 were $955.1 million and primarily consisted of net income of $412.2 million, non-cash charges of $540.0 million that reduced net income but did not result in the outlay of cash, and changes in certain assets and liabilities of $52.9 million. The non-cash charges primarily consisted of depreciation and amortization of $277.0 million and deferred income taxes of $260.7 million. Changes in certain assets and liabilities primarily consisted of $30.2 million in changes in receivables and payables resulting from normal working capital activity and a $20.4 million change in accrued interest due to the timing of cash payments. These amounts were partially offset by contributions made to pension and other postretirement employee benefit plans of $50.0 million.

A key driver of the increase in cash provided by operating activities in 2006 was a $256.2 million increase in net income compared to 2005. Significant cash outflows included $78 million in payments to Allegheny’s pension and other postretirement employee benefit plans. Changes in certain assets and liabilities primarily consisted of a $132.7 million decrease in collateral deposits, primarily due to the settlement of various trading contracts and improved credit ratings, a $28.3 million decrease in prepaid taxes, primarily as a result of timing differences associated with the payment of certain tax obligations and a $24.8 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues. These amounts were partially offset by a $109.9 million decrease in accounts payable, primarily as a result of timing differences associated with the payment of certain obligations.

Cash flows provided by operating activities for the year ended December 31, 2005 included $89.1 million in payments to Allegheny’s pension and other postretirement employee benefit plans, primarily as a result of contributions made to satisfy the funding requirements of these benefit plans, $47.2 million in payments to the holders of Capital Trust’s Trust Preferred Securities under the terms of the tender offer and consent solicitation, $29.5 million in payments to the remaining holders of AE Supply’s 10.25% and 13.0% Senior Notes and the cash receipt of $11.2 million from a former trading executive’s forfeited assets. Changes in certain assets and liabilities primarily consisted of a $75.1 million increase in accounts payable, primarily as a result of timing differences associated with the payment of certain obligations, a $34.5 million increase in accrued interest, primarily as a result of interest expense accrued for the Merrill Lynch litigation summary judgment, a $28.6 million decrease in prepaid taxes, primarily as a result of the timing differences associated with the payment of certain tax obligations and a $21.9 million change in accrued taxes, primarily as a result of timing differences associated with the payment of certain tax obligations. These amounts were partially offset by a $65.9 million increase in collateral deposits, primarily due to the requirements of various contracts and a $63.2 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues.

Investing Activities

Cash flows from investing activities for 2007, 2006 and 2005 are summarized as follows:


(In millions)	2007			2006			2005
Capital expenditures	$	(848.4	)	$	(447.3	)	$	(306.5	)
Proceeds from asset sales		1.8			2.6			66.5
Purchase of minority interest in Hunlock Creek Energy Ventures		—			(13.9	)		—
Decrease (increase) in other restricted funds		(34.6	)		8.7			207.3
Increase in restricted funds related to Fort Martin		(450.0	)		—			—
Restricted funds used for Fort Martin construction		103.0			—			—
Other investments		(3.3	)		(4.3	)		(2.6	)
Net cash provided by discontinued operations		—			50.4			226.8

Net cash provided by (used in) investing activities	$	(1,231.5	)	$	(403.8	)	$	191.5

Cash flows used in investing activities for the year ended December 31, 2007 were $1,231.5 million and primarily consisted of $848.4 million of capital expenditures and a $381.6 million increase in restricted funds primarily as a result of the receipt and investment of the funds for the environmental control bonds relating to the construction of Scrubbers at Fort Martin.

Cash flows used in investing activities for the year ended December 31, 2006 were $403.8 million and included $447.3 million of capital expenditures and the $13.9 million purchase of the minority interest in HCEV. These items were partially offset by net cash provided by discontinued operations of $50.4 million relating to the sale of the Gleason generation facility.

Cash flows provided by investing activities for the year ended December 31, 2005 were $191.5 million and included net cash provided by discontinued operations of $226.8 million, primarily as a result of the sale of the West Virginia natural gas operations and AE Supply’s Wheatland generation facility, a decrease in restricted funds of $207.3 million, primarily due to the release of the proceeds related to the 2004 sales of a portion of AE’s equity interest in OVEC and AE Supply’s Lincoln generation facility and proceeds from the sale of assets of $66.5 million, primarily as a result of the sale of Monongahela’s Ohio T&D assets. These items were partially offset by $306.5 million of capital expenditures.

Financing Activities

Cash flows from financing activities for 2007, 2006 and 2005 are summarized as follows:


(In millions)	2007			2006			2005
Issuance of long-term debt, excluding debt related to Fort Martin	$	485.3		$	1,571.3		$	1,849.1
Issuance of long-term debt related to Fort Martin		451.6			—			—
Repayment of long-term debt		(502.2	)		(2,102.9	)		(2,406.9	)
Notes payable		10.0			—			—
Redemption of preferred stock of subsidiary		(25.1	)		—			(50.0	)
Proceeds from the exercise of employee stock options		26.4			24.7			2.9
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(0.4	)		—
Cash dividends paid on common stock		(25.0	)		—			—

Net cash provided by (used in) financing activities	$	421.0		$	(507.3	)	$	(604.9	)

Cash flows provided by financing activities for the year ended December 31, 2007 were $421.0 million and primarily included $936.9 million (net of $12.9 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, consisting of the issuance of $459.3 million of environmental control bonds, $215.5 million of tax-exempt pollution control refunding bonds and $275.0 million of 5.95% First Mortgage Bonds. Partially offsetting these amounts were $502.2 million in various debt repayments.

Cash flows used in financing activities for the year ended December 31, 2006 were $507.3 million and included repayments of long-term debt of $2,102.9 million, primarily related to the May 2006 refinancings of the 2005 AE Credit Facility and the 2005 AE Supply Term Loan. Additional debt repayments included the September 2006 and October 2006 refinancings of outstanding Monongahela First Mortgage Bonds and Potomac Edison Medium-Term Notes, respectively and repayments of a portion of the amounts outstanding under the AE Credit Facility and the AE Supply Credit Facility. Partially offsetting these amounts were $1,571.3 million (net of $9.8 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, primarily related to the previously mentioned refinancings and the issuance by West Penn of $145.0 million in First Mortgage Bonds.

Cash flows used in financing activities for the year ended December 31, 2005 were $604.9 million and included repayments of long-term debt of $2,406.9 million, primarily related to the June 2005 refinancing of an AE prior credit facility and Medium-Term Notes, the July 2005 refinancing of a prior AE Supply loan and Medium-Term Notes and the August 2005 and October 2005 refinancings of outstanding First Mortgage Bonds. Partially offsetting these amounts were $1,849.1 million (net of $18.9 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, primarily related to the previously mentioned refinancings and the issuance by a subsidiary of West Penn of $115.0 million in Transition Bonds.

Financing

AE Common Stock

AE issued 1.9 million and 2.4 million shares of common stock in 2007 and 2006, respectively, primarily in connection with stock option exercises and the settlement of stock units.

There were no shares of common stock repurchased in 2007 or 2006.

Preferred Stock

On September 4, 2007, Monongahela redeemed its 4.40% Cumulative Preferred Stock, $100 par value, its 4.80% Cumulative Preferred Stock, Series B, $100 par value, its 4.50% Cumulative Preferred Stock, Series C, $100 par value and its $6.28 Cumulative Preferred Stock, Series D, $100 par value with an aggregate carrying value of $24.0 million. In connection with the cash redemption, Monongahela paid accrued dividends at the redemption date plus a redemption premium of approximately $1.1 million that was charged against other paid-in capital. This premium also reduced income per common share. See Note 9, “Income (Loss) Per Common Share,” for additional details.

On October 31, 2005, Monongahela fully redeemed its $50.0 million of outstanding $7.73, Series L ($100 par value) Cumulative Preferred Stock. Monongahela paid accrued and unpaid dividends of approximately $1 million in connection with the redemption.

Debt

See “Liquidity and capital requirements,” above, and Note 11, “Capitalization and Short-Term Debt,” for information regarding debt.

Recent Accounting Pronouncements

See Note 2, “Recent Accounting Pronouncements and Effect of Accounting Change,” for information on recent accounting pronouncements affecting Allegheny.

CREDIT RATINGS

The following table lists Allegheny’s credit ratings, as of February 27, 2008:


	Moody’s	S & P	Fitch
AE:
Outlook	Stable	Stable	Stable
Corporate Credit Rating	Not Rated	BBB-	BBB-	(a)
Senior Unsecured Debt	Ba1	BB+	BBB-
AE Supply:
Outlook	Stable	Stable	Stable
Senior Secured Debt	Baa2	BBB	BBB
Senior Unsecured Debt	Ba1	BB+	BBB-
Monongahela:
Outlook	Stable	Stable	Stable
First Mortgage Bonds	Baa2	BBB+	BBB+
Senior Unsecured Debt	Baa3	BB+	BBB-
Environmental Control Bonds	Aaa	AAA	AAA
Potomac Edison:
Outlook	Negative	Stable	Negative
First Mortgage Bonds	Baa2	BBB+	BBB
Environmental Control Bonds	Aaa	AAA	AAA
West Penn:
Outlook	Stable	Stable	Stable
Transition Bonds	Aaa	AAA	AAA
First Mortgage Bonds	Baa2	BBB+	BBB+
Senior Unsecured Debt	Baa3	BBB-	BBB-
AGC:
Outlook	Stable	Stable	Stable
Senior Unsecured Debt	Baa3	BBB-	BBB-

(a)	Issuer default rating

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

During 2007, Allegheny continued its focus on managing risk, optimizing the value of its generation facilities and prudently managing and protecting the value associated with its wholesale energy markets transactions portfolio.

Allegheny remains exposed to market risks associated with commodity prices and interest rates. The commodity price risk exposure results from market fluctuations in the price and transportation costs of electricity, coal, natural gas and other energy-related commodities. The interest rate risk exposure results from changes in interest rates related to variable-rate debt and debt that is maturing and is refinanced. Allegheny has a program designed to systematically identify, measure, evaluate and actively manage and report market risks.

Allegheny’s Corporate Risk Policy was adopted by its Board of Directors and is monitored by a Risk Management Committee, which is chaired by its Chief Executive Officer or his designee and is composed of senior management. An independent risk management group within Allegheny measures and monitors the risk exposures to ensure compliance with the policy and to ensure that the policy is periodically reviewed.

To manage the financial exposure to commodity price fluctuations in its wholesale transactions portfolio, fuel procurement, power marketing, natural gas supply and risk management activities, Allegheny enters into contracts, such as electricity, coal and natural gas purchase and sale commitments, to hedge the risk exposure. However, Allegheny does not hedge the entire exposure of its operations from commodity price volatility for a variety of reasons. To the extent Allegheny does not hedge against commodity price volatility, its consolidated results of operations, cash flows and consolidated financial position may be affected either favorably or unfavorably by a shift in the forward price curves and spot commodity prices.

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 generation facilities. For accounting purposes, the generation facilities are recorded at historical cost less depreciation. As a result, Allegheny’s results of operations and financial position can be favorably or unfavorably affected by a change in forward market prices.

Of its commodity-driven risks, Allegheny is primarily exposed to risks associated with the wholesale electricity markets, including generation, coal and other fuel procurement, power marketing and the purchase and sale of electricity. Allegheny’s wholesale activities principally consist of bilateral forward contracts for the purchase and sale of electricity. 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.

At December 31, 2007, AE’s outstanding debt subject to variable interest rates was $582 million, compared to $747 million of outstanding debt subject to variable interest rates at December 31, 2006. Accordingly, a one percent increase in the variable interest rate under AE’s and AE Supply’s current credit facilities would increase Allegheny’s projected interest expense in 2008 by approximately $5.8 million for outstanding debt, on an annual basis, based on the amount of outstanding debt as of December 31, 2007. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Requirements” below and Note 11, “Capitalization and Short-Term Debt,” to the Consolidated Financial Statements.

Credit Risk

Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Allegheny evaluates the credit standing of a prospective counterparty based on the prospective counterparty’s financial condition. Where deemed necessary, Allegheny may impose specified collateral requirements and use standardized agreements that facilitate netting of cash flows. Allegheny monitors the financial conditions of existing counterparties on an ongoing basis. Allegheny’s independent risk management group oversees credit risk.

Allegheny engages in various energy trading activities. The counterparties to these transactions generally include electric and natural gas utilities, independent power producers, energy marketers and commercial and industrial customers. In the event the counterparties do not fulfill their obligations, Allegheny may incur a loss to close out a position.

Allegheny has a concentration of counterparties in the electric, coal 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.

As of December 31, 2007, Allegheny’s derivatives are comprised primarily of interest rate swap agreements with a single counterparty and commodity cash flow hedges that will expire through December 2008.

Allegheny currently is involved in a number of capital intensive projects, including the TrAIL Project, the PATH Project and the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities. 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.

Market Risk

Market risk arises from the potential for changes in the value of energy related to price and volatility in the market. Allegheny reduces these risks by using its generation assets to back positions on physical transactions. Allegheny monitors market risk exposure and credit risk limits within the guidelines of its Corporate Energy Risk Policy. Allegheny evaluates commodity price risk, operational risk and credit risk in establishing the fair value of commodity contracts.

Allegheny and AE Supply use various methods to measure their exposure to market risk on a daily basis, including a value at risk model (“VaR”). VaR is a statistical model that attempts to predict risk of loss based on historical market price and volatility data over a given period of time. The quantification of market risk using VaR provides a consistent measure of risk across diverse energy markets and products with different risk factors to set the overall corporate risk tolerance, determine risk targets and monitor positions. Allegheny and AE Supply calculate VaR by using a variance/covariance approach, in which the option positions are evaluated by using their delta equivalences. Due to inherent limitations of VaR, including the use of approximations to value options, subjectivity in the choice of liquidation period and reliance on historical data to calibrate the model, the VaR calculation may not accurately reflect Allegheny’s and AE Supply’s market risk exposure. As a result, changes in Allegheny’s and AE Supply’s market risk sensitive instruments could differ from the calculated VaR, and these changes could have a material effect on Allegheny’s and AE Supply’s consolidated results of operations and financial position. In addition to VaR, Allegheny and AE Supply routinely perform stress and scenario analyses to measure extreme losses due to exceptional events. Allegheny and AE Supply review the VaR and stress test results to determine the maximum expected reduction in the fair value of the entire energy markets portfolio.

AE Supply calculated VaR using the full term of all remaining wholesale energy market positions that are accounted for as marked-to-market. This calculation is based upon management’s best estimates and modeling assumptions, which could materially differ from actual results. As of December 31, 2007 and 2006, this calculation yielded a VaR of $0 and $8,000, respectively.

ITEM 8. FINANCIAL

STATEMENTS AND SUPPLEMENTARY DATA


		Page No.
Consolidated Financial Statements of Allegheny Energy, Inc. and Subsidiaries		101

Report of Independent Registered Public Accounting Firm		169

Schedule I AE (Parent Company) Condensed Financial Statements		170

Schedule II Valuation and Qualifying Accounts		172

100

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Income


	Year ended December 31,
(In thousands, except per share amounts)	2007			2006			2005
Operating revenues	$	3,307,020		$	3,121,489		$	3,037,887
Operating expenses:
Fuel		930,788			842,661			759,057
Purchased power and transmission		393,182			382,990			458,306
Loss on sale of Ohio T&D assets		—			—			29,256
Gain on sale of OVEC power agreement and shares		—			(6,124	)		—
Deferred energy costs, net		(10,108	)		7,584			(1,528	)
Operations and maintenance		687,050			685,650			735,330
Depreciation and amortization		277,014			273,134			308,141
Taxes other than income taxes		211,806			203,274			212,534

Total operating expenses		2,489,732			2,389,169			2,501,096

Operating income		817,288			732,320			536,791
Other income and expenses, net		36,778			33,956			44,230
Interest expense and preferred dividends:
Interest expense		187,226			270,264			436,447
Preferred dividends of subsidiary		700			1,172			4,071

Total interest expense and preferred dividends		187,926			271,436			440,518

Income from continuing operations before income taxes and minority interest		666,140			494,840			140,503
Income tax expense		250,805			173,543			64,771
Minority interest in net income of subsidiaries		3,121			2,562			587

Income from continuing operations		412,214			318,735			75,145
Income (loss) from discontinued operations, net of tax (Note 14)		—			586			(6,152	)

Income before cumulative effect of accounting change		412,214			319,321			68,993
Cumulative effect of accounting change, net of tax of $3,367		—			—			(5,928	)

Net income	$	412,214		$	319,321		$	63,065

Common share data:
Weighted average common shares outstanding:
Basic		166,022			164,184			155,016
Diluted		169,468			168,676			158,634
Basic income (loss) per common share:
Income from continuing operations	$	2.48		$	1.94		$	0.48
Loss from discontinued operations, net of tax		—			—			(0.04	)
Cumulative effect of accounting change, net of tax		—			—			(0.04	)

Basic income per common share	$	2.48		$	1.94		$	0.40

Diluted income (loss) per common share:
Income from continuing operations	$	2.43		$	1.89		$	0.47
Loss from discontinued operations, net of tax		—			—			(0.04	)
Cumulative effect of accounting change, net of tax		—			—			(0.03	)

Diluted income per common share	$	2.43		$	1.89		$	0.40

See accompanying Notes to Consolidated Financial Statements.

101

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows


	Year ended December 31,
(In thousands)	2007			2006			2005
Cash Flows From Operating Activities:
Net income	$	412,214		$	319,321		$	63,065
Loss (income) from discontinued operations, net of tax		—			(586	)		6,152
Adjustments for non-cash items included in income:
Cumulative effect of accounting change, net		—			—			5,928
Depreciation and amortization		277,014			273,134			308,141
Amortization of debt related costs		10,140			23,086			24,861
Amortization of power sale liability related to Ohio sale		(10,500	)		(25,900	)		—
Amortization of liability for adverse power purchase commitment		(17,287	)		(17,154	)		(16,727	)
Amortization of Pennsylvania stranded cost recovery asset		19,507			15,213			16,049
Loss (gain) on asset sales and disposals		(15,444	)		(1,444	)		26,520
Minority interest in net income of subsidiaries		3,121			2,562			587
Deferred income taxes and investment tax credit, net		260,697			163,834			16,064
Deferred energy costs, net		(10,109	)		7,584			(1,528	)
Stock-based compensation expense		10,662			13,875			10,632
Unrealized gains on derivative contracts, net		(3,198	)		(32,397	)		(20,639	)
Pension and other postretirement employee benefit plan expense		35,997			41,468			46,224
Pension and other postretirement employee benefit plan contributions		(49,998	)		(77,966	)		(89,079	)
Deferred revenue—Fort Martin scrubber project		18,328			—			—
Accrued interest reversal—Merrill Lynch settlement		(54,689	)		—			—
Other, net		15,731			4,960			14,015
Changes in certain assets and liabilities:
Accounts receivable, net		(31,667	)		24,817			(63,204	)
Materials, supplies and fuel		(4,513	)		(8,087	)		(3,744	)
Collateral deposits		(6,744	)		132,727			(65,863	)
Prepaid taxes		22,995			28,291			28,622
Prepaid assets		2,199			288			4,471
Other current assets		12,071			(10,046	)		1,233
Accounts payable		61,868			(109,931	)		75,128
Accrued taxes		(38,008	)		(36,633	)		21,955
Accrued interest		20,418			8,421			34,536
Other current liabilities		4,575			1,032			(11,161	)
Regulatory asset—PATH		(6,218	)		—			—
Other assets		2,460			1,948			3,979
Deferred income taxes		123			15,612			—
Regulatory liability—interest on environmental control bond proceeds		15,056			—			—
Other regulatory liabilities		6,861			—			—
Other liabilities		(8,603	)		271			(4,847	)
Net cash provided by discontinued operations		—			4,804			54,750

Net cash provided by operating activities		955,059			763,104			486,120

102

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows (continued)


	Year ended December 31,
(In thousands)	2007			2006			2005
Cash Flows From Investing Activities:
Capital expenditures		(848,397	)		(447,325	)		(306,461	)
Proceeds from asset sales		1,770			2,591			66,497
Purchase of minority interest in Hunlock Creek Energy Ventures		—			(13,900	)		—
Increase in restricted funds related to Fort Martin		(450,000	)		—			—
Decrease (increase) in other restricted funds		(34,578	)		8,666			207,268
Restricted funds used for Fort Martin construction		102,977			—			—
Other investments		(3,238	)		(4,278	)		(2,644	)
Net cash provided by discontinued operations		—			50,402			226,829

Net cash provided by (used in) investing activities		(1,231,466	)		(403,844	)		191,489

Cash Flows From Financing Activities:
Issuance of long-term debt, excluding debt related to Fort Martin		485,332			1,571,289			1,849,061
Issuance of long-term debt related to Fort Martin		451,583			—			—
Repayment of long-term debt		(502,189	)		(2,102,854	)		(2,406,870	)
Issuance of short-term notes payable		10,000			—			—
Payments on capital lease obligations		(3	)		(60	)		—
Redemption of preferred stock of subsidiary		(25,148	)		—			(50,000	)
Proceeds from exercise of employee stock options		26,447			24,691			2,941
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		—			(400	)		—
Cash dividends paid on common stock		(25,003	)		—			—
Net cash used in discontinued operations		—			—			(11	)

Net cash provided by (used in) financing activities		421,019			(507,334	)		(604,879	)

Net increase (decrease) in cash and cash equivalents		144,612			(148,074	)		72,730
Cash and cash equivalents at beginning of period		114,138			262,212			189,482

Cash and cash equivalents at end of period	$	258,750		$	114,138		$	262,212

Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest (net of amounts capitalized)	$	209,556		$	241,300		$	399,797
Income taxes, net	$	(677	)	$	3,204		$	3,215

See accompanying Notes to Consolidated Financial Statements.

103

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets


	As of December 31,
(In thousands)	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	258,750		$	114,138
Accounts receivable:
Customer		195,545			167,792
Unbilled utility revenue		110,569			117,977
Wholesale and other		57,626			63,894
Allowance for uncollectible accounts		(14,252	)		(14,591	)
Materials and supplies		103,075			96,117
Fuel		72,506			74,951
Deferred income taxes		286,440			127,531
Prepaid taxes		48,343			44,603
Collateral deposits		59,527			39,399
Derivative contracts		29			1,430
Restricted funds		47,501			12,923
Regulatory assets		73,299			39,128
Other		16,001			24,130

Total current assets		1,314,959			909,422

Property, Plant and Equipment, Net:
Generation		5,992,919			5,820,278
Transmission		1,126,657			1,056,759
Distribution		3,761,438			3,597,405
Other		452,525			412,894
Accumulated depreciation		(4,795,925	)		(4,636,972	)

Subtotal		6,537,614			6,250,364
Construction work in progress		658,966			262,529

Total property, plant and equipment, net		7,196,580			6,512,893

Investments and Other Assets:
Restricted funds—Fort Martin scrubber project		347,023			—
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		27,875			28,259
Other		15,974			27,932

Total investments and other assets		758,159			423,478

Deferred Charges:
Regulatory assets		601,603			674,095
Other		35,288			32,558

Total deferred charges		636,891			706,653

Total Assets	$	9,906,589		$	8,552,446

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Balance Sheets (continued)


	As of December 31,
(In thousands, except share amounts)	2007			2006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	10,000		$	—
Long-term debt due within one year (Note 11)		95,367			201,189
Accounts payable		380,688			236,706
Accrued taxes		83,580			136,216
Derivative contracts		14,117			5,984
Accrued interest		65,583			99,854
Other		138,168			140,830

Total current liabilities		787,503			820,779

Long-term Debt (Note 11)		3,943,947			3,383,986
Deferred Credits and Other Liabilities:
Derivative contracts		12,815			17,982
Income taxes payable		68,050			—
Investment tax credit		69,353			72,938
Deferred income taxes		1,345,953			936,911
Obligations under capital leases		38,765			26,007
Regulatory liabilities		488,393			464,092
Adverse power purchase commitment		149,799			166,937
Other		453,418			547,706

Total deferred credits and other liabilities		2,626,546			2,232,573

Commitments and Contingencies (Note 27)
Minority Interest		13,241			10,713
Preferred Stock of Subsidiary		—			24,000
Common Stockholders’ Equity:
Common stock—$1.25 par value per share, 260 million shares authorized and 167,273,069 and 165,409,908 shares issued at December 31, 2007 and 2006, respectively		209,091			206,762
Other paid-in capital		1,924,072			1,907,879
Retained earnings		444,177			74,698
Treasury stock at cost—49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(40,232	)		(107,188	)

Total common stockholders’ equity		2,535,352			2,080,395

Total Liabilities and Stockholders’ Equity	$	9,906,589		$	8,552,446

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Capitalization


			As of December 31,
(Dollar amounts in thousands)			2007			2006
Common Stockholders’ Equity			$	2,535,352		$	2,080,395

Preferred stock of subsidiary, Monongahela—240,000 shares outstanding at December 31, 2006			$	—		$	24,000

Long-Term Debt:
	As of December 31, 2007
	Contractual Maturities	Interest Rate %
Medium-term notes	2010-2012	6.625 – 8.250	$	1,240,000		$	1,240,000
First mortgage bonds	2014-2017	5.125 – 6.700		1,180,000			905,000
AE Supply Credit Facility	2011	5.940		572,000			747,000
Environmental control bonds	2016-2028	4.982 – 5.523		459,300			—
Pollution control bonds	2012-2037	5.050 – 6.875		324,280			356,065
Transition bonds	2008-2010	4.460 – 6.980		171,368			245,757
Debentures	2023	6.875		100,000			100,000
Unamortized debt discounts	—	—		(7,634	)		(8,647	)

Total long-term debt (including current portion of long-term debt of $95,367 and $201,189 at December 31, 2007 and 2006, respectively)			$	4,039,314		$	3,585,175

Total Capitalization			$	6,574,666		$	5,689,570

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Stockholders’ Equity and Comprehensive Income


(In thousands, except shares)	Shares outstanding	Common stock		Other paid-in capital			Retained earnings (deficit)			Treasury stock			Accumulated other comprehensive loss			Total stockholders’ equity			Comprehensive income
Balance at December 31, 2004	137,380,644	$	171,788	$	1,600,215		$	(307,690	)	$	(1,756	)	$	(108,741	)	$	1,353,816
Net income	—		—		—			63,065			—			—			63,065		$	63,065
Minimum pension liability adjustment, net of tax of $69	—		—		—			—			—			(5,011	)		(5,011	)		(5,011	)
Unrealized loss on available-for-sale securities, net of tax of $282	—		—		—			—			—			(252	)		(252	)		(252	)
Cash flow hedges, net of tax of $18,211	—		—		—			—			—			(28,717	)		(28,717	)		(28,717	)

Comprehensive income																			$	29,085

Issuance of common stock for Employee Stock Ownership and Savings Plan	294,904		369		7,388			—			—			—			7,757
Conversion of trust preferred securities	24,998,997		31,249		258,385			—			—			—			289,634
Stock-based compensation expense:
Stock units	—		—		9,939			—			—			—			9,939
Non employee stock awards	3,600		4		689			—			—			—			693
Exercise of stock options	199,969		250		2,691			—			—			—			2,941
Settlement of stock units	74,688		93		393			—			—			—			486
Tax benefit on exercised stock options and stock unit settlement	—		—		1,063			—			—			—			1,063
Other	—		—		(119	)		—			—			—			(119	)

Balance at December 31, 2005	162,952,802	$	203,753	$	1,880,644		$	(244,625	)	$	(1,756	)	$	(142,721	)	$	1,695,295

Net income	—		—		—			319,321			—			—			319,321		$	319,321
Pension and other postretirement employee benefits:
Adoption of SFAS 158, net of tax of $35,628	—		—		—			—			—			(52,321	)		(52,321	)
Change in pension AML, intangible asset and regulatory asset, net of tax of $38,208	—		—		—			—			—			56,109			56,109			56,109
Unrealized income on available-for-sale securities, net of tax of $1	—		—		—			—			—			1			1			1
Cash flow hedges, net of tax of $20,094	—		—		—			—			—			31,744			31,744			31,744

Comprehensive income																			$	407,175

Stock-based compensation expense:
Stock units	—		—		4,680			—			—			—			4,680
Non employee stock awards	4,000		5		1,251			—			—			—			1,256
Stock options	—		—		7,940			—			—			—			7,940
Exercise of stock options	1,234,759		1,543		23,148			—			—			—			24,691
Settlement of stock units	1,168,854		1,461		(10,591	)		—			—			—			(9,130	)
Settlement of performance shares	—		—		807			—			—			—			807
Other	—		—		—			2			—			—			2

Balance at December 31, 2006	165,360,415	$	206,762	$	1,907,879		$	74,698		$	(1,756	)	$	(107,188	)	$	2,080,395

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Stockholders’ Equity and Comprehensive Income (continued)


(In thousands, except shares)	Shares outstanding	Common stock		Other paid-in capital			Retained earnings			Treasury stock			Accumulated other comprehensive loss			Total stockholders’ equity			Comprehensive income
Balance at December 31, 2006	165,360,415	$	206,762	$	1,907,879		$	74,698		$	(1,756	)	$	(107,188	)	$	2,080,395
Net income	—		—		—			412,214			—			—			412,214		$	412,214
Pension and other postretirement employee benefit plans other than pension plans:
Net gain during period, net of tax of $10,634	—		—		—			—			—			15,674			15,674			15,674
Amortizations:
Net actuarial loss, net of tax of $1,365	—		—		—			—			—			2,012			2,012			2,012
Net transition obligation, net of tax of $664	—		—		—			—			—			979			979			979
Net prior service cost, net of tax of $349	—		—		—			—			—			514			514			514
Unrealized losses on available-for-sale securities, net of tax of $5	—		—		—			—			—			(8	)		(8	)		(8	)
Cash flow hedges, net of tax of $2,876	—		—		—			—			—			(4,521	)		(4,521	)		(4,521	)
Effects of West Virginia Rate Order:
Establishment of regulatory asset related to pension obligation, net of tax of $35,663	—		—		—			—			—			52,306			52,306			52,306
Adjustment related to 2005 SO₂allowance sale, net of tax of $5,777	—		—		(8,306	)		—			—			—			(8,306	)

Comprehensive income																			$	479,170

Adoption of FIN 48	—		—		—			(17,722	)		—			—			(17,722	)
Premium on redemption of preferred stock of Monongahela	—		—		(1,148	)		—			—			—			(1,148	)
Dividends on common stock	—		—		—			(25,003	)		—			—			(25,003	)
Stock-based compensation expense:
Stock units	—		—		2,392			—			—			—			2,392
Non-employee stock awards	18,300		23		957			(10	)		—			—			970
Stock options	—		—		6,975			—			—			—			6,975
Exercise of stock options	1,445,969		1,807		24,640			—			—			—			26,447
Settlement of stock units	373,395		467		(9,285	)		—			—			—			(8,818	)
Settlement of performance shares	25,497		32		(32	)		—			—			—			—
Other	—		—		—			—			—			—			—

Balance at December 31, 2007	167,223,576	$	209,091	$	1,924,072		$	444,177		$	(1,756	)	$	(40,232	)	$	2,535,352

See accompanying Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note No.		Page No.
1	Basis of Presentation	110

2	Recent Accounting Pronouncements and Effect of Accounting Change	118

3	Transmission Expansion Projects	120

4	Rates and Regulation	122

5	Regulatory Assets and Liabilities	125

6	Income Taxes	127

7	Asset Swap	131

8	Dividend Restrictions	131

9	Income (Loss) per Common Share	132

10	Stock-Based Compensation	133

11	Capitalization and Short-Term Debt	138

12	Derivative Instruments and Hedging Activities	142

13	Jointly Owned Bath County Generation Facility	144

14	Discontinued Operations	144

15	Asset Sales	145

16	Business Segments	145

17	Pension Benefits and Postretirement Benefits Other Than Pensions	147

18	Goodwill and Intangible Assets	154

19	Adverse Power Purchase Commitment Liability	155

20	Review of Estimated Remaining Service Lives and Depreciation Practices	155

21	Asset Retirement Obligations (“ARO”)	155

22	Fair Value of Financial Instruments	156

23	Other Income and Expenses, Net	157

24	Quarterly Financial Information (Unaudited)	157

25	Guarantees and Letters of Credit	158

26	Variable Interest Entities	158

27	Commitments and Contingencies	159

28	Subsequent Event	168

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: BASIS OF PRESENTATION

Business Description

Allegheny Energy, Inc. (“AE” and together with its directly and indirectly owned subsidiaries “Allegheny”) is an integrated energy business that owns and operates electric generation facilities and delivers electric services to customers in Pennsylvania, West Virginia, Maryland and Virginia. Allegheny’s two business segments are the Delivery and Services segment and the Generation and Marketing segment.

The Delivery and Services segment primarily consists of Allegheny’s regulated utility subsidiaries. These subsidiaries include Monongahela Power Company (“Monongahela”), excluding its generation operations, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”) (collectively, the “Distribution Companies”). The Distribution Companies primarily operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia, Maryland and Virginia. The Distribution Companies are subject to federal and state regulation, including regulation of rates. The Delivery and Services segment also includes Allegheny Ventures, Inc. (“Allegheny Ventures”), Trans-Allegheny Interstate Line Company (“TrAIL Company”) and Potomac-Appalachian Transmission Highline, LLC (“PATH, LLC”). TrAIL Company was formed in 2006 in connection with the management and financing of transmission expansion projects, including the Trans-Allegheny Interstate Line (“TrAIL”), Allegheny’s 210-mile 500 KV transmission line. PATH, LLC, which is a series limited liability company, was formed in 2007 as a joint venture with a subsidiary of AEP to build the Potomac-Appalachian Transmission Highline (“PATH”), a 290-mile, high-voltage transmission line.

The Generation and Marketing segment primarily consists of Allegheny’s electric generation subsidiaries, Allegheny Energy Supply Company, LLC (“AE Supply”) and Allegheny Generating Company (“AGC”), as well as Monongahela’s generation operations. AE Supply owns, operates and controls electric generation capacity and supplies and trades energy and energy-related commodities. AGC owns and sells generation capacity to AE Supply and Monongahela, which own approximately 59% and 41% of AGC, respectively. The Generation and Marketing segment is subject to federal and state regulation but, unlike the Delivery and Services segment, is not generally subject to state regulation of rates, except that Monongahela’s generation is subject to state regulation of its rates in West Virginia.

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of Allegheny’s personnel. As of December 31, 2007, AESC employed 4,355 employees, approximately 1,250 of whom were subject to collective bargaining arrangements.

Significant accounting policies of Allegheny are summarized below.

Use of Estimates

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Principles of Consolidation

The Consolidated Financial Statements include the accounts of AE and its wholly owned and controlled subsidiaries, as well as those Variable Interest Entities for which AE is the primary beneficiary. See Note 26, “Variable Interest Entities,” for additional information.

All significant intercompany balances and transactions have been eliminated. The Consolidated Financial Statements have been prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of the Federal Energy Regulatory Commission (��FERC”) and applicable state regulatory commissions.

Regulatory Assets and Liabilities

Under cost-based regulation, regulated utility enterprises generally are permitted to recover their operating expenses and earn a reasonable return on their utility investment.

Allegheny accounts for its regulated utility operations under the provisions of Statement of Financial Accounting Standards (“SFAS”) 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs, revenues or other comprehensive income would be recognized by an unregulated enterprise. Accordingly, Allegheny records assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” Allegheny periodically evaluates the applicability of SFAS 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation of rates ends or competition significantly increases, Allegheny may have to adjust its regulatory assets and liabilities to reflect a market basis less than cost. See Note 5, “Regulatory Assets and Liabilities,” for additional information.

Revenues

Revenues from the sale of electricity to customers of the regulated utility subsidiaries are recognized in the period that the electricity is delivered and consumed by customers, including an estimate for unbilled revenues.

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

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

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 or expenses on the Consolidated Statements of Income unless the derivative falls within the “normal purchases and normal sales” scope exception of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities, as amended” (“SFAS 133”) 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 any ineffective portion of the hedge are immediately recognized in earnings.

Allegheny has netting agreements with various counterparties, which provide the right to set off amounts due from or to the counterparty. In cases in which these netting agreements are in place, Allegheny records the fair value of derivative assets and liabilities and accounts receivable and accounts payable with counterparties on a net basis. Cash flows associated with derivative contracts are recorded in cash flows from operating activities. See Note 12, “Derivative Instruments and Hedging Activities,” for additional details regarding energy trading activities.

Unbilled revenues are primarily associated with the Distribution Companies. Energy sales to individual customers are based on their meter readings, which are performed periodically on a systematic basis. At the end of each month, the amount of energy delivered to each customer after the last meter reading is estimated, and the Distribution Companies recognize unbilled revenues related to these amounts. The unbilled revenue estimates are based on daily generation, purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses and the most recent consumer rates.

Revenues from all other activities are recorded in the period during which products or services are delivered and accepted by customers. A provision for uncollectible accounts is recorded as a component of operations and maintenance expense.

Deferred Energy Costs, Net

Expanded Net Energy Cost (“ENEC”)

On May 22, 2007, the Public Service Commission of West Virginia (the “West Virginia PSC”) issued a rate order (the “West Virginia Rate Order”), effective May 23, 2007, that re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues will be tracked for under and/or over recoveries, and revised ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, will be deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability, with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.” By order dated January 14, 2008, the West Virginia PSC approved a modification to the ENEC directing interest earnings on the Fort Martin scrubber project escrow fund to be applied to the ENEC. See Note 4, “Rates and Regulation,” for additional information.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

AES Warrior Run PURPA Generation

To satisfy certain of its obligations under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), Potomac Edison entered into a long-term contract beginning July 1, 2000 to purchase capacity and energy from the AES Warrior Run PURPA generation facility through the beginning of 2030. Potomac Edison is authorized by the Maryland Public Service Commission (the “Maryland PSC”) to recover all contract costs from the AES Warrior Run PURPA generation facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, by means of a retail revenue surcharge (the “AES Warrior Run Surcharge”). Any under-recovery or over-recovery of net costs is being deferred pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge.

Market-based Maryland Generation Costs

Potomac Edison is authorized by the Maryland PSC to recover costs associated with the generation component of power sold to certain commercial and industrial customers who did not choose a third-party alternative generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet relative to any under-recovery or over-recovery for the generation component of costs charged to Maryland commercial and industrial customers. Deferred energy costs, net relate, in part, to the recovery from or payment to customers related to these generation costs, to the extent amounts paid for generation costs differ from prices currently charged to customers.

Grant Town PURPA Generation Facility

Monongahela acquires energy from the Grant Town PURPA generation facility in West Virginia. The West Virginia PSC approved an amendment to the Electric Energy Purchase Agreement between Monongahela and American Bituminous Power Partners, L.P., the owners of the Grant Town PURPA generation facility, in April 2006. The amendment provided for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia PSC authorized Monongahela to institute a temporary surcharge designed to recover the increase in costs from West Virginia customers, as well as a deferred accounting mechanism by which actual aggregate amounts of the incremental cost increase were tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge. As a result of the West Virginia Rate Order, the increase in costs discussed above are now included in the ENEC. See Note 4, “Rates and Regulation,” for additional information.

Debt Issuance Costs

Costs incurred to issue debt are recorded as deferred charges on the Consolidated Balance Sheets. These costs are amortized over the term of the related debt instrument using the straight line method, which approximates the effective interest method.

Intercompany Transactions

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

Income Taxes. AE and its subsidiaries file a consolidated federal income tax return. Federal income tax expense (benefit) and tax assets and liabilities are allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Allegheny Money Pool. Allegheny manages excess cash through its internal money pool. The money pool provides funds to approved AE subsidiaries at the lower of the Federal Reserve’s previous day federal funds effective interest rate, or the Federal Reserve’s previous day seven day commercial paper rate, less four basis points. AE and AE Supply can only place money into the money pool. Monongahela, West Penn and Potomac Edison can either place money into, or borrow money from, the money pool. AGC can only borrow money from the money pool.

Power Sales and Purchases. AE Supply provides power to Potomac Edison and West Penn in accordance with agreements approved by FERC to meet the majority of the Distribution Companies’ retail provider-of-last-resort (“PLR”) obligations. Through December 31, 2006, Monongahela sold the power that it generated from its West Virginia jurisdictional assets to AE Supply at PJM market prices and purchased from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. Effective January 1, 2007, 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 its contractual obligations. Through December 31, 2006, Potomac Edison had a power purchase agreement with AE Supply under which AE Supply provided Potomac Edison with the power necessary to meet its West Virginia load obligation at a fixed rate. Effective January 1, 2007, Monongahela assumed the obligation to supply power to serve Potomac Edison’s West Virginia load.

AE Supply and Monongahela purchase all of AGC’s capacity in the Bath County generation facility under a “cost-of-service formula” wholesale rate schedule approved by FERC. AE Supply and Monongahela purchase capacity from AGC on a proportional basis, based on their respective equity ownership of AGC.

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

Long-Lived Assets

Allegheny’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows. There were no impairment charges recorded during 2007. See Note 14, “Discontinued Operations,” for asset impairment charges recorded during 2006 and 2005.

Property, Plant and Equipment

Regulated property, plant and equipment is recorded at original cost. Cost includes direct labor and materials, allowance for funds used during construction on property for which construction work in progress is not included in rate base and indirect costs, such as operation, maintenance and depreciation of transportation and construction equipment, taxes, postretirement benefits and other benefits related to employees to the extent they are engaged in construction. In general, upon retirement of the property, the original cost of the property less salvage is charged to accumulated depreciation and the cost of removal is charged to the related regulatory liability or regulatory asset, with no gain or loss recognized.

Unregulated property, plant and equipment is recorded at original cost. Cost includes direct labor and materials, capitalized interest and indirect costs, such as operation, maintenance and depreciation of transportation and construction equipment, taxes, postretirement benefits and other benefits related to employees

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

to the extent they are engaged in construction. Upon retirement, the cost of depreciable property is removed from the related accounts with no gain or loss recorded, any salvage is recorded to the accumulated provision for depreciation and the cost of removal is expensed when incurred.

Allegheny capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over the expected useful life of the software, beginning upon a project’s completion.

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

For non-utility construction, Allegheny capitalizes interest costs associated with construction. The average interest capitalization rates for 2007, 2006 and 2005 were 7.04%, 7.01% and 7.12%, respectively. Allegheny capitalized $20.0 million, $6.9 million, and $3.1 million of interest during 2007, 2006 and 2005 respectively.

AFUDC is a component of the construction of Property, Plant and Equipment (“PP&E”) defined in the applicable regulatory system of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is capitalized in those instances in which the related construction work in progress is not afforded rate base treatment and is reflected in the Statements of Income as a reduction to “Interest expense” and “Other income and expense, net” to the extent it represents borrowed funds and other funds used in construction, respectively. Rates used by the regulated subsidiaries for computing AFUDC in 2007, 2006 and 2005 averaged 7.56%, 6.42% and 6.79%, respectively. Allegheny recorded AFUDC of $6.8 million, $4.9 million and $2.7 million in 2007, 2006 and 2005, respectively, of which $2.7 million, $1.7 million and $1.4 million was reflected in “Other income and expense, net” and $3.9 million, $3.3 million and $1.3 million was reflected as a reduction to “Interest expense” for 2007, 2006 and 2005, respectively.

Depreciation and Maintenance

Depreciation expense is determined generally on a straight-line group method over the estimated service lives of depreciable assets for unregulated operations. For regulated utility operations, depreciation expense is determined using a straight-line group method in accordance with currently enacted regulatory rates. Under the straight-line group method, plant components are categorized as “retirement units” or “minor items of property.” As retirement units are replaced, the cost of the replacement is capitalized and the original component is retired. Replacements of minor items of property are expensed as maintenance. Depreciation expense was approximately 2.3%, 2.4% and 2.8% of average depreciable property in 2007, 2006 and 2005, respectively. Estimated service lives for generation, T&D and other property at December 31, 2007 were as follows:


		Years
Generation property:
Steam scrubbers and equipment		43-65
Steam generator units		45-80
Internal combustion units		40-44
Hydroelectric dams and facilities		50-152
Transmission and distribution property:
Electric equipment		10-70
Easements		70-100
Other property:
Office buildings and improvements		35-60
General office/other equipment		10-25
Vehicles and transportation		7-25
Computers, software and information systems		5-20

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

Goodwill and Intangible Assets

Goodwill represents the acquisition cost in excess of fair value of tangible and intangible assets acquired, less liabilities assumed. Recorded goodwill is not amortized, but is tested for impairment at least annually. Other intangible assets with finite lives are amortized over their useful lives and tested for impairment when events or circumstances warrant. See Note 18, “Goodwill and Intangible Assets” for additional information.

Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates are generally accounted for under the equity method of accounting. The income or loss on such investments is recorded in “Other income and expenses, net” in the Consolidated Statements of Income. Investments in unconsolidated affiliates of $27.9 million and $28.3 million at December 31, 2007 and 2006, respectively, primarily consisted of Allegheny’s investment, through AE Supply, in Buchanan Generation LLC.

Cash Equivalents

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

Restricted Funds

At December 31, 2007 and 2006, Allegheny had current restricted funds of $47.5 million and $12.9 million, respectively. Current restricted funds at December 31, 2007 included $35.2 million of funds collected from West Virginia customers that will be used to service the environmental control bonds issued in April 2007 in connection with the construction of flue-gas desulfurization equipment (“Scrubbers”) at the Fort Martin generation facility (“Fort Martin”) and $12.3 million of intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. Current restricted funds at December 31, 2006 related to intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. In addition, at December 31, 2007, Allegheny had $347.0 million of long-term restricted funds relating to proceeds from the April 2007 issuance of environmental control bonds, which will be used to fund the majority of costs to construct the Scrubbers at Fort Martin. See Note 4, “Rates and Regulation” for additional information.

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Collateral Deposits

Allegheny had collateral deposits at December 31, 2007 and 2006 of $59.5 million and $39.4 million, respectively. These amounts are deposited with counterparties, including PJM, for certain transactions and transmission and transportation tariffs and are classified as current assets on the Consolidated Balance Sheets.

Allegheny also had funds on deposit with a third party that were posted as collateral for the issuance of surety bonds. These amounts were $15.3 million at December 31, 2006, and were included in the caption “Other” within “Investments and other assets” on the Consolidated Balance Sheets. Allegheny did not have any collateral posted for surety bonds at December 31, 2007.

Inventory

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

Income Taxes

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

Taxable income differs from pre-tax accounting income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using enacted tax rates in effect in the years in which the differences are expected to reverse. See Note 6, “Income Taxes,” for additional information.

Taxes Collected from Customers and Remitted to Governmental Authorities

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

Pension and Other Postretirement Benefits

AE sponsors a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. AE makes contributions to the pension plan in order to meet at least the minimum funding requirements as set forth in employee benefit and tax laws, plus such additional amounts as AE may determine to be appropriate, but not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities, real estate investment trusts and cash. Allegheny also sponsors a Supplemental Executive Retirement Plan (“SERP”) for executive officers and other senior executives.

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AE also provides partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, have retiree premiums based upon an age and years-of-service vesting schedule, and include other plan provisions that limit future benefits and take into account certain collective bargaining arrangements. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. Medical benefits, with the exception of those provided to certain retired union employees, are self-insured. AE does not provide subsidized medical coverage in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006. See Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions” for additional information.

Stock-Based Compensation

Through December 31, 2005, Allegheny accounted for stock option awards using the intrinsic value method accompanied by pro forma disclosures of net income and earnings per share as if Allegheny had applied the fair value method to all such compensation. Since January 1, 2006, Allegheny has accounted for its stock option awards under the provisions of SFAS No. 123R “Accounting for Stock-Based Compensation,” (“SFAS 123R”). All share-based payments, including grants of employee stock options, are measured at fair value on the date of grant and are expensed over the requisite service period. See Note 10, “Stock-Based Compensation” for additional information.

Accumulated Other Comprehensive Loss

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


(In millions)	December 31, 2007			December 31, 2006
Cash flow hedges, net of tax	$	(4.3	)	$	0.2
Net unrecognized pension and other postretirement benefit costs, net of tax		(35.9	)		(107.4	)

Total	$	(40.2	)	$	(107.2	)

Reclassifications

Certain amounts in previously issued financial statements have been reclassified to conform to the current presentation.

NOTE 2: RECENT ACCOUNTING PRONOUNCEMENTS AND EFFECT OF ACCOUNTING CHANGE

Accounting Pronouncements Recently Adopted:

In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB No. 108”), which expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB No. 108 was effective for Allegheny for its December 31, 2006 annual financial statements and its adoption did not impact Allegheny’s financial statements.

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In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132R (“SFAS No. 158”). Allegheny adopted SFAS No. 158 as of December 31, 2006. See Note 17, “Pension Benefits and Postretirement Benefits Other than Pensions,” for information related to the impact of this accounting pronouncement.

In December 2004, the FASB issued SFAS No. 123R, Share Based Payment, (“SFAS No. 123R”). Allegheny adopted SFAS No. 123R effective January 1, 2006. See Note 10, “Stock-Based Compensation,” for information related to the impact of this accounting pronouncement.

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109” (“FIN 48”). On May 2, 2007, the FASB issued Interpretation No. 48-1, Definition of Settlement in FASB Interpretation No. 48 (“FIN 48-1”), which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. Allegheny adopted the provisions of FIN 48 and FIN 48-1 as of January 1, 2007 and May 2, 2007, respectively. See Note 6, “Income Taxes,” for information related to the impact of these accounting pronouncements.

In June 2006, the Emerging Issues Tax Force (“EITF”) reached a consensus on EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement” (“EITF 06-3”). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from revenues and costs) basis. Allegheny records taxes collected from customers that are assessed on those customers on a net basis. That is, in instances in which Allegheny acts as a collection agent for a taxing authority by collecting taxes that are the responsibility of the customer, Allegheny records the amount collected as a liability and relieves such liability upon remittance to the taxing authority without impacting revenues or expenses. Therefore, the January 1, 2007 implementation of EITF 06-3 did not have a material impact on Allegheny’s financial statements.

In September 2006, the FASB issued FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities” (the “FSP”). The FSP permits the following methods for accounting for planned major maintenance activities: direct expense, built-in overhaul and deferral. The FSP requires entities to disclose the method of accounting for planned major maintenance activities, as well as the impact of any change in method required as a result of the adoption of the FSP. The FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities. Allegheny adopted the FSP on January 1, 2007. It is Allegheny’s policy to account for planned major maintenance activities using the direct expense method. Therefore, the adoption of the FSP did not have an impact on Allegheny’s financial statements.

Accounting Pronouncements Not Yet Adopted as of December 31, 2007:

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to choose to measure at fair value certain financial instruments and other items that are not currently required to be measured at fair value. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for Allegheny beginning on January 1, 2008. Allegheny does not expect that this pronouncement will have a material impact on its financial statements.

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In April 2007, the FASB issued Interpretation No. 39-1, “Amendment of Interpretation No. 39” (“FIN 39-1”). FIN 39-1 permits entities that are party to master netting arrangements to offset cash collateral receivables or payables that approximate fair values with net derivatives positions. FIN 39-1 is effective for Allegheny beginning on January 1, 2008. Allegheny does not expect that this pronouncement will have a material impact on its financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosure about fair value measurements. It applies to other pronouncements that require or permit fair value but does not require any new fair value measurements. The statement defines fair value as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” SFAS 157, as it relates to financial assets and liabilities, is effective for Allegheny beginning January 1, 2008.

In February 2008, the FASB issued FSP FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which permits a one-year deferral of the application of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

Allegheny will adopt SFAS 157 and FSP FAS 157-2 effective January 1, 2008. Accordingly, the provisions of SFAS 157 will not be applied to nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, until January 1, 2009. Allegheny is currently analyzing the impact of SFAS 157 on its financial statements.

In December 2007, the FASB issued SFAS 141R, “Business Combinations” (“SFAS 141R”) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS 160”). SFAS 141R requires an acquirer to measure the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their fair values on the acquisition date, with goodwill being the excess value over the net identifiable assets acquired. SFAS 160 clarifies that a noncontrolling interest in a subsidiary should be reported as equity in the consolidated financial statements. The calculation of earnings per share will continue to be based on income amounts attributable to the parent. SFAS 141R and SFAS 160 are effective for Allegheny beginning on January 1, 2009. Allegheny does not expect that these statements will have a material impact on its financial statements.

Cumulative Effect of Accounting Change:

During 2005, Allegheny recorded a $5.9 million cumulative effect of accounting change related to its adoption of Financial Accounting Standards Board (“FASB”) Interpretation 47, “Accounting for Conditional Asset Retirement Obligations” (“Conditional AROs”) (“FIN 47”). For additional information, see Note 21, “Asset Retirement Obligations (“ARO”).”

NOTE 3: TRANSMISSION EXPANSION PROJECTS

Trans-Allegheny Interstate Line

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includes new 138 kV transmission lines and related substations. In June 2006, the board of directors of PJM established the need for a new transmission line extending from Southwestern Pennsylvania through West Virginia to Northern Virginia, and designated Allegheny to build the AP Zone portion of the line. PJM, the regional transmission operator, which is responsible for the operation of and reliability planning for the transmission network in the PJM region, included the new line in its 2006 regional transmission expansion plan. The overall project has a targeted completion date of 2011. Cost estimates for Allegheny’s portion of the project are approximately $820 million.

On July 20, 2006, FERC approved incentive rate treatments for TrAIL. On February 21, 2007, TrAIL Company submitted to FERC a filing to implement a formula tariff rate, with a proposed effective date of June 1, 2007, that includes the incentive rate treatments approved by FERC. On May 31, 2007, FERC issued an order permitting the formula tariff rate to become effective on June 1, 2007, subject to refund and hearing. One of the issues set for hearing is the level of the incentive return on equity for TrAIL. On January 24, 2008, TrAIL Company filed a motion to suspend the procedural schedule in this matter, stating that all active participants in the proceeding have reached a settlement in principle that resolves all issues set for hearing, and the procedural schedule for the hearing was suspended pending finalization of the settlement agreement.

Potomac Appalachian Transmission Highline

In April 2007, Allegheny announced plans to construct PATH, a 290-mile, high-voltage transmission line project (the “PATH Project”). PJM authorized construction of PATH in April 2007. In September 2007, Allegheny entered into a joint venture agreement with American Electric Power Company, Inc. (“AEP”) to construct PATH. The joint venture, PATH, LLC, is a series limited liability company. The “West Virginia Series” is owned equally by Allegheny and AEP and will build, own and operate approximately 244 miles of 765-kV transmission line from AEP’s Amos substation near St. Albans, West Virginia to Allegheny’s Bedington substation near Martinsburg, West Virginia, though an operating subsidiary. The “Allegheny Series” is 100% owned by Allegheny and, through an operating subsidiary, will build, own and operate approximately 46 miles of twin-circuit 500-kV lines from Bedington to a new substation near Kemptown, Maryland, to be built and owned by Allegheny. Total project costs of the West Virginia Series are expected to be approximately $1.2 billion. Total project costs of the Allegheny Series are expected to be approximately $0.6 billion. PJM has specified June 2012 as the in-service date for the project.

On December 28, 2007, PATH, LLC submitted a filing to FERC under Section 205 of the Federal Power Act to implement a formula tariff rate to be effective March 1, 2008. The filing also included a request for certain incentive rate treatments.

The accounts of PATH, LLC and its operating subsidiaries are included in Allegheny’s Consolidated Financial Statements, in accordance with the provisions of FASB Interpretation 46(R), Consolidation of Variable Interest Entities.

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NOTE 4: RATES AND REGULATION

Pennsylvania

Rate caps on transmission services in Pennsylvania expired on December 31, 2005. Distribution rate caps were also scheduled to expire on December 31, 2005 and generation rate caps were scheduled to expire on December 31, 2008. By order entered May 11, 2005, the Pennsylvania Public Utility Commission (the “Pennsylvania PUC”) approved an extension of generation rate caps from 2008 to 2010 and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously approved rate cap increases for 2006 and 2008. The order also extended distribution rate caps from 2005 to 2007, with an additional rate cap in place for 2009 at the rate in effect on January 1, 2009. The intent of this transition plan is to gradually move generation rates closer to market prices.

West Virginia

West Virginia Rate Order:

In a July 26, 2006 filing with the West Virginia PSC, Monongahela and Potomac Edison requested a decrease in base rates of approximately $26 million and an increase in revenues related to fuel and purchased power costs of approximately $126 million. The West Virginia Rate Order, which was issued in response to the July 2006 rate request, reduced Allegheny’s annual revenues by approximately $6 million and decreased annual depreciation expense by approximately $16 million, resulting in an annual net pre-tax benefit of approximately $10 million. The $6 million revenue decrease is comprised of a decrease in base rates of approximately $132 million and an increase in revenues related to fuel and purchased power costs of approximately $126 million.

The following is a summary of additional significant provisions and accounting impacts of the West Virginia Rate Order:

•

The West Virginia Rate Order established the annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs and other related expenses, net of related revenue. Under the ENEC, actual costs and revenues are tracked for under and/or over recoveries, and revised ENEC rate filings will be made on an annual basis. Any under and/or over recovery of costs, net of related revenues, is deferred as a regulatory asset or regulatory liability, for subsequent recovery and/or refund, with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.”

•

In December 2005, Monongahela sold sulfur dioxide (“SO₂”) allowances to AE Supply for $14.8 million in cash and recorded the $14.7 million difference between the carrying value of the allowances and the cash received as a credit to “Other paid-in capital” in the amount of $8.8 million, net of the income tax effects of $5.9 million. The West Virginia Rate Order requires Monongahela to reduce its rate base by $14.7 million, and requires the subsequent amortization of this amount, net of amortization for the period from the December 2005 sale date through the effective date of the West Virginia Rate Order, as a credit to cost of service over a period of approximately 29 years. As a result, Monongahela reclassified $14.0 million, $8.3 million net of tax, from other paid-in capital to a “Regulatory liability.” In addition, Monongahela recorded a related deferred tax asset in the amount of $5.8 million during the second quarter of 2007. The regulatory liability will be amortized to revenue, and the deferred tax asset will be amortized to income tax expense over a period of approximately 29 years.

•

The West Virginia Rate Order provides for the recovery of pension expense on an accrual basis. Monongahela and Potomac Edison previously recovered pension costs on a cash basis in West Virginia, and, therefore, Allegheny did not record a regulatory asset related to the portion of pension obligations

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allocable to the West Virginia jurisdiction when it adopted SFAS 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements 87, 88, 106 and 132R (“SFAS 158”) on December 31, 2006. As a result of the West Virginia Rate Order, in the second quarter of 2007, Allegheny’s service subsidiary, AESC, established a regulatory asset related to pension obligations recorded upon adoption of SFAS 158, in the amount of $88.0 million ($52.3 million net of tax), with a corresponding credit to “Other comprehensive income,” net of income tax effect.

Environmental Control Bonds:

As discussed in Note 11, “Capitalization and Short-Term Debt,” in April 2007, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $344 million and $115 million, respectively, of Senior Secured Sinking Fund Environmental Control Bonds, Series A. These bonds securitize the right to collect an environmental control surcharge from the West Virginia customers of Monongahela and Potomac Edison.

The West Virginia regulatory orders that authorize the environmental control surcharge provide that the surcharge revenues will recover the principal, interest and financing costs associated with the bonds. Proceeds of the environmental control bonds will be used to fund a majority of the costs associated with installation of Scrubbers at Allegheny’s Fort Martin generation facility.

Allegheny expects that the Scrubbers will be completed and placed in service by late 2009. The Scrubbers will be depreciated over their estimated useful lives, which may be a greater period than the duration of the environmental control surcharge and related environmental control bonds.

Allegheny will account for the construction of Scrubbers at Fort Martin in a manner that results in no net income or loss from the securitized portion of project costs as follows:

•

Environmental control surcharge revenues will be recorded as billed;

•

Interest expense on the bonds will be recorded as incurred;

•

Depreciation will be recorded over the estimated useful life of the Scrubbers after they are placed in service; and

•

A regulatory liability will be recognized with an offsetting charge against revenues to the extent that environmental control surcharge revenue exceeds interest and depreciation expense. This liability will decrease, with an offsetting credit to revenue over the remaining useful life of the Scrubbers, after the environmental control surcharge ends and the bonds have been repaid. See Note 5, “Regulatory Assets and Liabilities,” for additional information.

Maryland

In December 2006, Potomac Edison proposed a rate stabilization and market transition plan (the “Transition Plan”) for its Maryland residential customers, in accordance with a bill passed by the Maryland legislature in 2006. The Maryland Public Service Commission approved the Transition Plan on March 30, 2007. The Transition Plan provides for a gradual transition of Potomac Edison’s residential customers from capped generation rates to market-based generation rates, while at the same time preserving for customers the benefit of rate caps.

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Under the Transition Plan, Potomac Edison’s customers who did not opt out of the Transition Plan began paying a non-bypassable surcharge (the “Rate Stabilization Surcharge”) in June 2007, which will result in an overall rate increase of approximately 15%, after taking into account the expiration of a prior customer choice rate credit with the initiation of the new surcharge. On January 1, 2008, the surcharge will increase residential rates an additional 15%.

Beginning January 1, 2009, coincident with the expiration of the residential generation rate cap and implementation of market-based generation pricing, the Rate Stabilization Surcharge will convert from a charge to a credit on customers’ bills. Funds collected through the Rate Stabilization Surcharge during 2007 and 2008, plus interest, will be returned to customers as a credit on their electric bills, thereby reducing the impact of the rate cap expiration. The credit would continue, with adjustments, to maintain rate stability until approximately December 31, 2010.

The Rate Stabilization Surcharge is being recorded directly to a regulatory liability as it is billed to customers. In addition, interest on amounts collected from customers is recognized as a component of the regulatory liability for future refund to customers. This interest is recorded as interest expense on the Consolidated Statements of Income. As amounts are returned to customers as a surcharge credit in future periods, these customer credits will be charged directly to the regulatory liability.

Virginia

During the 2007 session, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”), to re-regulate the provision of electric generation services in the Commonwealth beginning January 1, 2009. Until that time, Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Until December 31, 2008, Potomac Edison is the provider-of-last-resort (“PLR”) for those customers who do not choose an alternate generation supplier or whose alternate generation supplier does not deliver. After January 1, 2009, Potomac Edison will provide generation services to all of its customers in Virginia at regulated rates.

Potomac Edison had a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations through June 30, 2007 at the capped generation rates. In April 2007, Potomac Edison conducted a competitive bidding process to purchase its PLR requirements from the wholesale market for service beginning July 1, 2007, and AE Supply was the successful bidder with respect to a substantial portion of those requirements. Market prices for purchased power resulting from that bidding process, at which Potomac Edison began to purchase its PLR requirements on July 1, 2007, currently are higher, and likely will continue to be higher, than the rates Potomac Edison is currently allowed to recover from its retail customers. These higher market prices for power have resulted in increased purchased power costs by Potomac Edison and increased revenues to AE Supply since July 1, 2007.

In an April 2007 filing with the State Corporation Commission of Virginia (“Virginia SCC”), Potomac Edison requested to adjust its fuel factor and to implement a rate stabilization plan, including an increase in retail rates of approximately $103 million beginning July 1, 2007, to offset the impact of increased purchased power costs. Additionally, Potomac Edison filed a Motion for Interim Rates with the Virginia SCC on May 10, 2007. In June 2007, the Virginia SCC issued an order that denied Potomac Edison’s application and motion to establish interim rates, cancelled evidentiary hearings and dismissed the case. On July 6, 2007, Potomac Edison filed with the Virginia SCC a Motion for Suspension of Order and Motion for Interim Rates, which the Virginia SCC denied on August 7, 2007. On July 26, 2007, Potomac Edison filed an appeal of the decision denying Potomac Edison’s application and motion to establish interim rates to the Virginia Supreme Court and also asked the Virginia Supreme Court for relief pending appeal. The Court denied Potomac Edison’s motions and set the

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matter for review in the ordinary course. Potomac Edison then filed a new application for rate recovery of purchased power costs for load above 367 MW with the Virginia SCC on September 11, 2007, and is continuing to pursue its appeal for full cost recovery. On October 10, 2007, the Virginia SCC issued an order setting Potomac Edison’s new application for hearing on December 4, 2007.

On December 20, 2007, the Virginia SCC issued an order granting partial recovery of increased purchased power costs.

The commission’s order:

•

Granted a rate adjustment effective immediately that would permit the company to collect an additional $9.5 million (pre-tax) on an annualized basis through June 30, 2008, a substantially lower amount than the $42.3 million Allegheny requested,

•

Directed the company to implement deferred accounting effective immediately with respect to the over-or under-recovery of the increased purchase power costs approved in the order, and

•

Directed the company to file an application with the commission on or before July 1, 2008, for proposed recovery of purchased power costs for the 12-month period beginning July 1, 2008, including for treatment of any over- or under-recovery incurred under this order.

NOTE 5: REGULATORY ASSETS AND LIABILITIES

Certain of Allegheny’s regulated utility operations are subject to the provisions of SFAS 71. Regulatory assets represent probable future revenues associated with currently incurred costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities generally represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:


(In millions)	2007		2006
Regulatory assets, including current portion:
Income taxes (a)(b)	$	251.4	$	300.4
Pension benefits and postretirement benefits other than pensions (a)(c)		202.7		178.2
Pennsylvania stranded cost recovery		17.6		55.6
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		117.7		107.4
Unamortized loss on reacquired debt (a)(d)		35.3		39.6
Deferred ENEC charges		9.4		—
Other (e)		40.8		32.0

Subtotal		674.9		713.2

Regulatory liabilities, including current portion:
Net asset removal costs		396.4		421.4
Income taxes		36.8		38.9
SO₂ allowances		13.8		—
Fort Martin scrubber project—environmental control surcharge		33.4		—
Other		8.5		4.5

Subtotal		488.9		464.8

Net regulatory assets	$	186.0	$	248.4

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(a)	Does not earn a return.

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

(c)	Amount is being recovered over a period up to 13 years.

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

(e)	Includes certain amounts that do not earn a return with recovery periods up to 20 years.

Asset Removal Costs

In certain jurisdictions, depreciation rates include a factor representing the estimated costs associated with removing an asset from service upon retirement. The accrual builds up during the asset’s service life and is reduced when the actual cost of removal is incurred. The accumulated balance of such removal costs represents a regulatory liability. See Note 21, “Asset Retirement Obligations (“ARO”),” for a description of legal asset retirement obligations.

Income Taxes, Net

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

Pension and Other Postretirement Benefits

See Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for a discussion of regulatory assets relating to pension and other postretirement benefits.

Pennsylvania Stranded Cost Recovery and CTC Reconciliation

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 terms of a customer choice implementation agreement between the Pennsylvania PUC and West Penn, beginning in 1998 and through June 2008, West Penn was authorized to recover $670 million of Competitive Transition Charges (“CTC”) incurred as part of the transition to customer choice. West Penn’s customer bills include a CTC charge and West Penn recognizes revenue related to CTC charges through the end of the recovery period, estimated to be June 2008. Any difference between CTC charges recognized and the amount collected from customers is recorded as a regulatory asset for future collection. For 2007, 2006 and 2005, West Penn recorded pre tax income of approximately $52 million, $45 million and $56 million, respectively, related to CTC.

In 2005, the Pennsylvania PUC authorized West Penn to defer the difference between authorized and billed stranded cost recovery revenues, with an 11% return on the amounts deferred, for future full and complete recovery from customers over an extended transition period through 2010. This difference represents a separate regulatory asset (“Pennsylvania CTC Reconciliation”). Recovery of the Pennsylvania CTC Reconciliation regulatory asset will begin after the Pennsylvania stranded cost regulatory asset has been fully recovered. The amount of under-recovery of CTC during the transition period, if any, will be determined at the end of the transition period in 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 6: INCOME TAXES

Details of federal and state income tax expense from continuing operations were as follows:


(In millions)	2007			2006			2005
Income tax expense (benefit)—current:
Federal	$	(19.3	)	$	26.1		$	55.2
State		9.4			(16.5	)		(6.5	)

Total		(9.9	)		9.6			48.7
Income tax expense (benefit)—deferred:
Federal		251.3			175.1			4.8
State		13.0			(7.2	)		17.6

Total		264.3			167.9			22.4
Amortization of deferred investment tax credit		(3.6	)		(4.0	)		(6.3	)

Total income tax expense from continuing operations	$	250.8		$	173.5		$	64.8

On July 2, 2006, the Commonwealth of Pennsylvania budget for the 2006-2007 fiscal year was enacted. The budget included a provision that raised the annual limit on the amount of net operating loss carryforwards that may be used to reduce current year taxable income from $2 million per year to the greater of $3 million or 12.5% of apportioned Pennsylvania state taxable income per year, effective January 1, 2007. The carryforward limitation period remained unchanged at 20 years. Allegheny recorded a benefit during 2006 in the amount of $18.2 million for the state income tax effect, net of applicable federal income tax, reflecting the estimated portion of the loss carryforwards that will be realized during the carryforward period. During 2007, an additional benefit of $4.2 million, net of applicable federal income tax, was recorded as a result of estimated additional future Pennsylvania taxable income.

During 2006, Allegheny recorded a charge of $6.6 million, which was the effect of settling prior year audit issues.

During 2005, Allegheny determined that it had not claimed certain income tax deductions in its 2003 income tax returns relating to commodity trading contracts. Allegheny filed a claim for these additional deductions, which increased Allegheny’s recorded tax net operating loss carryforwards in the amount of approximately $210 million and decreased other recorded deferred tax assets in a similar amount, except for certain state income tax effects. Allegheny recorded a charge of $3.8 million during 2005 to write-off state deferred tax assets that will not be realized due to state limitations on the use of net operating loss carryforwards resulting from the filing of this claim.

On June 30, 2005, the state of Ohio enacted broad changes to its business tax system, including a phase-out of the state’s income-based franchise tax over a five-year period beginning in 2006. The phase-out of the franchise tax reduced the realizable benefit of recorded deferred tax assets by $1.9 million, and such deferred tax assets were written down by this amount in 2005. The franchise tax has been replaced by a gross receipts tax that is being phased-in over a five year period, which began on July 1, 2005. Effective with the December 31, 2005 sale of Monongahela’s T&D assets, Allegheny no longer has operations in Ohio. See Note 15, “Asset Sales,” for additional information.

Allegheny also recorded a $6.9 million charge during 2005 to decrease recorded deferred tax assets on deferred compensation due to changes in the timing of payments permitted under the American Jobs Creation Act of 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Investment tax credits have been deferred and are being amortized over the estimated service lives of the related property, plant and equipment.

The following table reconciles income tax expense calculated by applying the federal statutory income tax rate of 35% to “income from continuing operations before income taxes and minority interest” to “income tax expense”:


	2007					2006					2005
(In millions, except percent)	Amount			%		Amount			%		Amount			%
Income from continuing operations before income taxes and minority interest	$	666.1				$	494.8				$	140.5
Preferred dividend of subsidiary		0.7					1.2					4.1

Subtotal		666.8					496.0					144.6

Income tax expense calculated at the federal statutory rate of 35%		233.1		35.0			173.6		35.0			50.6		35.0
Increases (reductions) resulting from:
Rate-making effects of depreciation differences		7.6		1.0			6.9		1.4			7.5		5.2
Plant removal costs		(2.1	)	(0.3	)		(2.0	)	(0.4	)		(1.9	)	(1.3	)
State income tax, net of federal income tax benefit		17.5		2.6			14.9		3.0			7.2		5.0
Amortization of deferred investment tax credits		(3.6	)	(0.5	)		(4.0	)	(0.8	)		(6.3	)	(4.3	)
Reduction in tax benefits for deferred compensation		—		—			—		—			6.0		4.1
Change in estimated Pennsylvania net operating loss benefits		(4.2	)	(0.6	)		(18.2	)	(3.7	)		—		—
Changes in tax reserves related to uncertain tax positions and audit settlements		1.8		0.3			6.6		1.3			—		—
Other, net		0.7		0.1			(4.3	)	(0.8	)		1.7		1.1

Income tax expense	$	250.8		37.6		$	173.5		35.0		$	64.8		44.8

The income tax benefit for loss from discontinued operations differs from the amount calculated by applying the federal statutory income tax rate of 35% to the gross amount as set forth below:


(In millions)	2006		2005
Income (loss) from discontinued operations, before income taxes	$	3.7	$	(12.1	)

Income tax expense (benefit) calculated using the federal statutory rate of 35%	$	1.3	$	(4.2	)
State income tax expense (benefit), net of federal income tax effect		1.8		(1.8	)

Total income tax expense (benefit)	$	3.1	$	(6.0	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At December 31, the deferred income tax assets and liabilities consisted of the following:


(In millions)	2007			2006
Deferred income tax assets:
Recovery of transition costs	$	23.9		$	19.8
Unamortized investment tax credits		33.4			35.6
Postretirement benefits		65.4			100.6
Tax effect of net operating loss carryforwards		345.2			554.2
Fair value of derivative contracts		16.7			9.1
Valuation allowance on Pennsylvania net operating loss carryforwards		(15.7	)		(21.2	)
Other		82.9			73.0

Total deferred income tax assets		551.8			771.1

Deferred income tax liabilities:
Plant asset basis differences, net		1,548.8			1,506.0
Other		62.5			74.5

Total deferred income tax liabilities		1,611.3			1,580.5

Total net deferred income tax liability		1,059.5			809.4
Deferred income taxes included in current assets		286.4			127.5

Total long-term net deferred income tax liability	$	1,345.9		$	936.9

Allegheny recorded as deferred income tax assets the effect of net operating losses, which will more likely than not be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2025.

In June 2006, the FASB issued FIN 48, which prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on an income tax return. Under FIN 48, tax benefits should be recognized in the financial statements when it is more likely than not that the position will be sustained upon examination by the tax authorities based on the technical merits of the position. Such tax positions should be measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.

Allegheny adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation, Allegheny recognized a $17.7 million reduction to its January 1, 2007 balance of retained earnings.

Allegheny records interest and penalties associated with uncertain tax positions as a component of income tax expense. During 2007 Allegheny recognized an interest expense, net of tax, of approximately $0.2 million. Accrued interest, net of tax, related to uncertain tax positions was $16.9 million and $11.8 million at December 31, 2007 and January 1, 2007, respectively.

The gross FIN 48 reserve at December 31, 2007 was $81.7 million ($59.4 million net of the federal tax benefit for state tax reserves). Approximately $68.0 million of this reserve will not be resolved in the next 12 months and, therefore, has been classified as long term income taxes payable on the accompanying Consolidated Balance Sheet at December 31, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following represents an analysis of the changes in unrecognized tax benefits during 2007:


(In millions)	Amount
Balance at January 1, 2007	$	107.6
Additions based on tax positions related to the current year		32.7
Additions for tax positions of prior years		18.1
Reductions for tax positions of prior years		(3.3	)
Settlements		(52.2	)

Balance at December 31, 2007	$	102.9

If recognized, the portion of the unrecognized tax benefits that would reduce Allegheny’s effective tax rate was $42.5 million and $38.7 million at December 31, 2007 and January 1, 2007, respectively ($65.4 million and $58.9 million, respectively, before the federal income tax effects on state income tax positions).

The unrecognized tax benefit balance also included approximately $37.5 million and $48.7 million of tax positions at December 31, 2007 and January 1, 2007, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would impact the timing of cash payments to the taxing authorities.

The major jurisdictions in which Allegheny is subject to income tax are U.S. Federal, Pennsylvania, West Virginia, Maryland and Virginia. Allegheny files consolidated federal income tax returns, and those returns are currently under audit by the Internal Revenue Service (“IRS”) for the tax years 1998 through 2003. The 2004 through 2006 federal returns have been filed and are still subject to review. Several of Allegheny’s subsidiaries file returns in Pennsylvania. Returns filed with the Pennsylvania Department of Revenue for the tax years 2002 through 2006 are subject to review. Allegheny also files a consolidated West Virginia return. The consolidated West Virginia returns have been audited through 2004. The 2005 and 2006 returns remain subject to review. Several of Allegheny’s subsidiaries are also subject to tax in the state of Maryland. The Maryland returns for the tax years 2004 through 2006 remain subject to review. Additionally, certain Allegheny subsidiaries are subject to tax in Virginia. The Virginia returns for tax years 2004 through 2006 remain subject to review.

As stated above, the IRS is currently auditing Allegheny’s income tax returns for the tax years 1998 through 2003. These audits are anticipated to be completed within the next 12 months. During the audit period, Allegheny changed its method of applying the inventory capitalization rules from its traditional method to the simplified service cost method. The IRS has proposed adjustments related to the change in method that are timing in nature. Interest accrued on this position was $12.5 million, net of tax, at December 31, 2007. It is reasonably possible that a portion of this interest accrual will reverse in the next 12 months. Also, Allegheny filed various refund claims with the IRS primarily related to property type items, which were effectively settled with the IRS during 2007 and resulted in a net benefit of $3.3 million. Additionally, Allegheny has liabilities for uncertain positions taken on various state income tax returns that it files. The statute of limitations for some of these returns expired during 2007 and resulted in a benefit of approximately $0.8 million. Additionally, some of the state tax returns containing these positions have been audited by the respective states. These audits were resolved in favorable manner in the fourth quarter and resulted in a benefit of $4.3 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 7 : ASSET SWAP

Effective January 1, 2007, AE Supply and Monongahela completed an intercompany exchange of assets (the “Asset Swap”) that realigned generation ownership and contractual arrangements within the Allegheny system. As a result of the Asset Swap, Monongahela owns 100% of Fort Martin, which allowed Allegheny to securitize, through the issuance of environmental control bonds, an environmental control charge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. The proceeds of the sale of the environmental control bonds are being used to finance $450 million of the estimated $550 million in costs to construct the Scrubbers at Fort Martin.

As a result of the Asset Swap, Monongahela also owns 100% of the Albright, Rivesville and Willow Island generation facilities in West Virginia and is contractually entitled to a greater proportion of the generation from the Bath County, Virginia generation facility. Also as a result of the Asset Swap, AE Supply owns 100% of the Hatfield’s Ferry generation facility, which, prior to the Asset Swap, was jointly owned by AE Supply and Monongahela, and has a greater ownership interest in the Harrison and Pleasants generation facilities in West Virginia. AE Supply also received contractual rights to a greater amount of generation from OVEC. The Asset Swap resulted in a net transfer of 660 MWs of generation capacity from AE Supply to Monongahela. Additionally, Monongahela assumed from AE Supply the contractual obligation to provide power to Potomac Edison to serve its West Virginia load obligations. To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets directly into the PJM market and purchases directly from the PJM market the power necessary to meet its West Virginia jurisdictional customer load and its contractual obligations. These power purchases and sales were previously transacted with AE Supply.

In connection with the Asset Swap, AE Supply assumed a net amount of approximately $6 million in additional debt associated with outstanding pollution bonds. Monongahela will remain obligated to the note holders for the repayment of this debt. Additionally, AE Supply paid in advance of their scheduled maturities notes totaling approximately $16 million in the aggregate in connection with the redemption of certain pollution control bonds that, by their terms, were required to be redeemed as a result of the change in ownership of Fort Martin.

NOTE 8: DIVIDEND RESTRICTIONS

During 2006 and 2005, AE was not permitted to pay cash dividends on its common stock under the AE credit facility. During 2007, the AE credit facility was amended to allow payment of cash dividends on its common stock, subject to certain restrictions.

Under the terms of its credit facility, AE Supply may pay cash dividends to AE in an amount not to exceed the greater of (a) $25 million or (b) either 25% or 50% of AE Supply’s net income for the preceding fiscal year, depending on AE Supply’s leverage ratio as of the last day of the preceding fiscal year. AE Supply may also pay cash dividends to AE not to exceed $300 million to the extent such dividend is applied directly or indirectly by AE to make investments in a subsidiary.

Restricted net assets of AE Supply were approximately $894 million and $747 million at December 31, 2007 and 2006, respectively. There were no restricted net assets of unconsolidated subsidiaries at December 31, 2007 and 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 9: INCOME (LOSS) PER COMMON SHARE

The following table provides a reconciliation of the numerators and the denominators for the basic and diluted earnings per common share computations:


(In millions, except share and per share amounts)	2007			2006		2005
Basic Income (Loss) per Common Share:
Numerator:
Income from continuing operations	$	412.2		$	318.7	$	75.1
Redemption of preferred stock (a)		(1.1	)		—		(0.4	)

Income from continuing operations available for common shareholders		411.1			318.7		74.7
Income (loss) from discontinued operations		—			0.6		(6.1	)
Cumulative effect of accounting change		—			—		(5.9	)

Net income available for common shareholders	$	411.1		$	319.3	$	62.7

Denominator:
Weighted average common shares outstanding		166,021,597			164,184,165		155,016,346

Basic Income (Loss) per Common Share:
Income from continuing operations	$	2.48		$	1.94	$	0.48
Loss from discontinued operations		—			—		(0.04	)
Cumulative effect of accounting change		—			—		(0.04	)

Basic income per common share	$	2.48		$	1.94	$	0.40

Diluted Income (Loss) per Common Share:
Numerator:
Income from continuing operations	$	412.2		$	318.7	$	75.1
Redemption of preferred stock (a)		(1.1	)		—		(0.4	)

Income from continuing operations available for common shareholders		411.1			318.7		74.7
Income (loss) from discontinued operations		—			0.6		(6.1	)
Cumulative effect of accounting change		—			—		(5.9	)

Net income available for common shareholders	$	411.1		$	319.3	$	62.7

Denominator:
Weighted average common shares outstanding		166,021,597			164,184,165		155,016,346
Effect of dilutive securities:
Stock options (b)		2,723,934			2,611,827		1,366,238
Performance shares		—			30,668		53,557
Non-employee stock awards		61,330			47,470		25,200
Stock units		660,877			1,805,253		2,172,410
Convertible securities (c)		—			—		—

Total shares		169,467,738			168,679,383		158,633,751

Diluted Income (Loss) per Common Share:
Income from continuing operations	$	2.43		$	1.89	$	0.47
Loss from discontinued operations		—			—		(0.04	)
Cumulative effect of accounting change		—			—		(0.03	)

Diluted income per common share	$	2.43		$	1.89	$	0.40

(a)	See Note 11, “Capitalization and Short-Term Debt,” for information related to Monongahela’s redemption of preferred stock.

(b)	The dilutive share calculations for 2007, 2006 and 2005 exclude 48,578 shares, 350,645 shares and 826,371 shares, respectively, under outstanding stock options because the inclusion of these stock options under the treasury stock method would have been antidilutive.

(c)	For 2005, 7,614,991 shares issuable under convertible trust preferred securities were excluded from the denominator because their inclusion would have been antidilutive.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 10: STOCK-BASED COMPENSATION

Allegheny adopted SFAS 123R effective January 1, 2006 using the modified prospective transition method. Under this transition method, the fair value accounting and recognition provisions of SFAS 123R are applied to share-based awards granted or modified subsequent to the date of adoption, and prior periods presented are not restated. In addition, compensation expense is recognized in future periods for all share-based payment awards that were outstanding, but not yet vested, as of January 1, 2006, based on the same estimated grant date fair values and service periods used to prepare Allegheny’s SFAS 123 pro-forma disclosures, net of estimated forfeitures. Prior to the adoption of SFAS 123R, Allegheny accounted for stock-based compensation using the intrinsic value method accompanied by pro forma disclosures of net income and earnings per share as if Allegheny had applied the fair value method to all such compensation. The following table summarizes stock-based compensation expense recognized during 2007, 2006 and 2005:


(In millions)	2007		2006		2005
Stock options	$	7.3	$	7.9	$	—
Stock units		2.4		4.7		9.9
Other		1.0		1.3		0.7

Stock-based compensation expense included in operations and maintenance expense		10.7		13.9		10.6
Income tax benefit		4.3		5.6		4.3

Total stock-based compensation expense, net of tax	$	6.4	$	8.3	$	6.3

No stock-based compensation cost was capitalized in 2007, 2006 or 2005.

As indicated in the preceding table, prior to January 1, 2006, no stock-based compensation expense was recognized for stock options. Allegheny’s net income and income per share for 2005 would have been reduced to the pro forma amounts shown below if compensation expense had been determined using the fair value provisions of SFAS 123R:


(In millions, except per share amounts)	Year Ended December 31, 2005
Consolidated net income, as reported	$	63.1
Add:
Stock-based employee compensation expense included in consolidated net income, net of related tax effects		6.3
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		11.3

Consolidated net income, pro forma	$	58.1

Basic income per share:
As reported	$	0.40

Pro-forma	$	0.37

Diluted income per share:
As reported	$	0.40

Pro-forma	$	0.36

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Stock Options

Allegheny’s 1998 Long-Term Incentive Plan (“LTIP”), which was approved by AE’s shareholders, permits stock option awards, restricted share awards and performance awards representing up to 10 million shares of AE’s common stock. The exercise price, terms and other conditions applicable to stock option awards are generally determined by the Management Compensation and Development Committee of AE’s Board or the independent directors of the Board. The exercise price per share for each award is equal to or greater than the fair market value of a share of AE’s common stock on the grant date. Stock options vest in annual tranches on a pro-rata basis over the vesting period, which is typically one to five years, and become fully vested and exercisable upon a change in control. Stock options typically expire after 10 years. Except as may be provided in a separate agreement with any individual employee, in the event of termination of employment, options not exercisable at the time of termination will expire as of the date of termination. Except as may be otherwise provided in a separate agreement with any individual employee, exercisable options will expire 90 days from the date of termination, except in the event of termination due to retirement, disability or death. Exercisable options will expire three years after the date of termination in the case of retirement or disability, and in the case of death, the exercisable options will expire one year after the date of the participant’s death. Allegheny may permit the exercise of options or the payment of withholding taxes through the tender of previously acquired shares of AE common stock or through a reduction in the number of shares issuable upon option exercise. Stock option awards are expensed using the straight-line attribution method over the requisite service period of the last separately vesting tranche of the award.

Effective January 1, 2006, Allegheny records compensation expense for employee stock options based on the estimated fair value of the options on the date of grant using the Black-Scholes option-pricing model with the assumptions included in the table below. The annual risk-free interest rate was based on the United States Treasury yield curve at the time of the grant for a period equal to the expected term of the options granted. The expected term of the 2007 and 2006 stock option grants was calculated in accordance with Staff Accounting Bulletin 107 using the “simplified” method. The expected annual dividend yield assumption was based on AE’s current dividend rate. For options granted in the second half of 2007, AE used an expected dividend yield of approximately 1%. Prior to that the annual dividend yield assumption was zero. For stock options granted in 2007 and 2006, the expected volatility was based on both historical stock volatility and the volatility levels implied on the grant date by actively traded option contracts on Allegheny’s common stock. The following weighted-average assumptions were used to estimate the fair value of options granted during 2007, 2006 and 2005:


	2007			2006			2005
Annual risk-free interest rate		4.62	%		4.64	%		4.19	%
Expected term of the option (in years)		5.62			6.23			6.50
Expected annual dividend yield		0.20	%		—			—
Expected stock price volatility		24.77	%		28.89	%		35.00	%
Grant date fair value per stock option	$	17.23		$	14.36		$	9.40

Stock-based compensation expense recognized in the Consolidated Statements of Income for 2007 and 2006 in operations and maintenance expense was based on awards ultimately expected to vest, using an estimated annual forfeiture rate of 5%.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Stock option activity for the last three years was as follows:


	Stock Options		Weighted Average Exercise Price
Outstanding at December 31, 2004	6,159,774		$	16.659
Granted	440,000		$	21.584
Exercised	(199,969	)	$	14.708
Forfeited/Expired	(249,848	)	$	17.770

Outstanding at December 31, 2005	6,149,957		$	17.029
Granted	207,800		$	37.078
Exercised	(1,234,759	)	$	19.996
Forfeited/Expired	(452,660	)	$	23.574

Outstanding at December 31, 2006	4,670,338		$	16.504
Granted	31,000		$	52.359
Exercised	(1,445,969	)	$	18.290
Forfeited/Expired	(63,960	)	$	13.382

Outstanding at December 31, 2007	3,191,409		$	16.105

The grant-date fair value of stock options granted during 2007 and 2006 was $0.5 million and $3.0 million, respectively. The total pre-tax intrinsic value of stock options exercised during 2007 and 2006 was $56.6 million and $24.0 million, respectively, representing the difference between the market value of Allegheny’s stock at exercise and the exercise price of the options. The total pre-tax intrinsic value of options exercisable at December 31, 2007 and 2006 was $92.0 million and $68.7 million, respectively. Cash received by Allegheny from option exercises totaled $26.4 million and $24.7 million in 2007 and 2006, respectively. Allegheny issued new shares of its common stock to satisfy these stock option exercises. There was no cash tax benefit realized from tax deductions on stock options exercised during 2007 and 2006 because of existing tax net operating loss carryforwards.

The following table summarizes information about stock options outstanding and stock options exercisable at December 31, 2007:


	Options Outstanding						Options Exercisable
		Weighted-Average
Range of Exercise Prices	Outstanding as of December 31, 2007	Remaining Contractual Term (in Years)	Exercise Price		Aggregate Intrinsic Value (in millions) (a)		Exercisable as of December 31, 2007	Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions) (a)
$10.00 - $14.99	2,709,665	6.1	$	13.45	$	135.9	1,698,138	$	13.41	$	85.2
$15.00 - $19.99	124,744	7.1	$	19.04		5.6	44,010	$	19.25		2.0
$20.00 - $24.99	57,000	6.4	$	20.88		2.5	30,000	$	20.76		1.3
$25.00 - $29.99	60,000	7.9	$	28.49		2.1	15,000	$	28.49		0.5
$30.00 - $34.99	32,600	2.5	$	32.64		1.0	32,600	$	32.64		1.0
$35.00 - $39.99	93,400	8.3	$	36.55		2.5	23,600	$	37.53		0.6
$40.00 - $44.99	68,000	5.5	$	42.46		1.4	52,500	$	42.36		1.1
$45.00 - $49.99	26,000	5.7	$	47.12		0.4	15,000	$	46.26		0.3
$50.00 - $54.99	8,000	9.5	$	52.57		0.1	—	$	—		—
$55.00 - $59.99	12,000	9.5	$	55.96		0.1	—	$	—		—

Total	3,191,409	6.2	$	16.10	$	151.6	1,910,848	$	15.46	$	92.0

(a)	Represents the total pre-tax intrinsic value based on stock options with an exercise price less than AE’s closing stock price of $63.61 as of December 31, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of December 31, 2007, there was approximately $8.8 million of unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over a weighted-average period of approximately 1.1 years.

Allegheny records windfall tax benefits associated with share-based awards directly to stockholders’ equity only when realized. Accordingly, deferred tax assets have not been recognized for net operating loss carryforwards resulting from windfall tax benefits subsequent to January 1, 2006. The unrecorded windfall tax benefits from share-based awards were $24.2 million and $15.9 million for 2007 and 2006, respectively.

Stock Units

Allegheny’s Stock Unit Plan permits the grant to Allegheny’s key executives, at the time of hire, of stock units representing up to 4.5 million shares of AE’s common stock. Upon vesting, an executive may convert each stock unit into one share of AE common stock. These stock units vest in annual tranches on a pro-rata basis over the vesting period, which is typically three to five years, and become fully vested upon a change in control. Stock unit awards granted prior to January 1, 2006 are expensed using the graded-vesting method of FASB Interpretation No. 28. The fair value of each stock unit is equivalent to the market price of Allegheny’s stock on the date of grant. No stock units were granted during 2007.

Stock unit activity for the last three years was as follows:


	Number of Stock Units		Weighted-Average Grant Date Fair Value		Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2004	3,044,160		$	15.29	$	60.0

Units convertible at December 31, 2004	670,138		$	15.30	$	13.2

Outstanding at December 31, 2004	3,044,160		$	15.29
Granted	50,000		$	21.08
Units converted into 74,688 common shares	(87,654	)	$	15.23

Outstanding at December 31, 2005	3,006,506		$	15.39	$	95.2

Units convertible at December 31, 2005	1,292,622		$	15.30	$	40.9

Outstanding at December 31, 2005	3,006,506		$	15.39
Units converted into 1,168,854 common shares	(1,900,540	)	$	15.33
Forfeited	(60,000	)	$	18.97

Outstanding at December 31, 2006	1,045,966		$	15.29	$	48.0

Units convertible at December 31, 2006	107,220		$	15.30	$	4.9

Outstanding at December 31, 2006	1,045,966		$	15.29
Units converted into 373,395 common shares	(596,078	)	$	15.29
Dividends on unvested grants	1,167		$	60.66

Outstanding at December 31, 2007	451,055		$	15.40	$	28.7

Units convertible at December 31, 2007	—		$	—	$	—

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The total intrinsic value of stock units converted to shares of AE common stock during 2007 was $29.7 million. Allegheny issued new shares of its common stock in connection with the stock unit conversions. The actual number of common shares issued upon conversion of stock units was net of shares withheld to meet minimum income tax withholding requirements.

As of December 31, 2007, there was approximately $0.7 million of unrecognized compensation cost related to non-vested outstanding stock units, which is expected to be recognized over a weighted-average period of approximately four months.

Non-Employee Director Stock Plan

Under the Non-Employee Director Stock Plan, during 2007 each non-employee member of AE’s Board of Directors received on a quarterly basis, subject to his or her election to defer his or her receipt, shares of AE common stock with a value of up to $30,000 as determined based on the closing price of AE common stock on the last business day of each calendar quarter for services performed. In 2006 and 2005, each non-employee member of the Board received, subject to his or her election to defer his or her receipt, up to 1,000 shares of AE’s common stock for services performed during a calendar quarter. A maximum of 300,000 shares of AE’s common stock, subject to adjustments for stock splits, combinations, recapitalizations, stock dividends or similar changes in stock, may be issued under this plan. The 2007, 2006 and 2005 compensation of each non-employee director was 2,303 shares, 4,000 shares and 3,200 shares, respectively, of AE’s common stock. The amount of expense relating to this plan for 2007, 2006 and 2005 was $1.0 million, $1.3 million and $0.7 million, respectively, representing the market price on the date of grant.

Non-employee director stock plan share activity for the last three years was as follows:


	Number of Shares
Shares earned but not issued at December 31, 2004	14,893
Granted	25,600
Issued	(3,600	)

Shares earned but not issued at December 31, 2005	36,893
Granted	32,000
Issued	(4,000	)

Shares earned but not issued at December 31, 2006	64,893
Granted	18,424
Issued	(18,300	)
Dividends on earned but not issued shares	160

Shares earned but not issued at December 31, 2007	65,177

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 11: CAPITALIZATION AND SHORT-TERM DEBT

Allegheny’s consolidated capital structure, excluding short-term debt and minority interest, as of December 31, 2007 and 2006, was as follows:


	2007			2006
(In millions)	Amount		%	Amount		%
Long-term debt	$	4,039.3	61.4	$	3,585.2	63.0
Common equity		2,535.4	38.6		2,080.4	36.6
Preferred equity (a)		—	—		24.0	0.4

Total	$	6,574.7	100.0	$	5,689.6	100.0

(a)	On September 4, 2007, Monongahela redeemed all of the shares of its Cumulative Preferred Stock. See “Preferred Stock of Subsidiary” below for additional information.

Common Stock

AE issued 1.9 million and 2.4 million shares of common stock in 2007 and 2006, respectively, primarily in connection with stock option exercises and the settlement of stock units.

Preferred Stock of Subsidiary

On September 4, 2007, Monongahela redeemed its 4.40% Cumulative Preferred Stock, $100 par value, its 4.80% Cumulative Preferred Stock, Series B, $100 par value, its 4.50% Cumulative Preferred Stock, Series C, $100 par value and its $6.28 Cumulative Preferred Stock, Series D, $100 par value with an aggregate carrying value of $24.0 million. In connection with the cash redemption, Monongahela paid accrued dividends at the redemption date plus a redemption premium of approximately $1.1 million that was charged against other paid-in capital. This premium also reduced income per common share as shown in Note 9, “Income (Loss) Per Common Share.”

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Debt

Outstanding debt and scheduled debt repayments at December 31, 2007 were as follows:


(In millions)	2008			2009			2010			2011			2012			Thereafter			Total
AE Supply:
Medium—Term Notes	$	—		$	—		$	—		$	400.0		$	650.0		$	—		$	1,050.0
AE Supply Credit Facility		—			—			—			572.0			—			—			572.0
Pollution Control Bonds		—			—			—			—			1.3			267.2			268.5
Debentures—AGC		—			—			—			—			—			100.0			100.0

Total AE Supply	$	—		$	—		$	—		$	972.0		$	651.3		$	367.2		$	1,990.5

Monongahela:
Environmental Control Bonds (a)	$	15.0		$	10.6		$	11.1		$	11.6		$	12.2		$	284.0		$	344.5
First Mortgage Bonds		—			—			—			—			—			340.0			340.0
Medium—Term Notes		—			—			110.0			—			—			—			110.0
Pollution Control Bonds		—			—			—			—			6.0			64.2			70.2

Total Monongahela	$	15.0		$	10.6		$	121.1		$	11.6		$	18.2		$	688.2		$	864.7

West Penn:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0
Transition Bonds (a)		75.5			79.9			16.0			—			—			—			171.4
Medium—Term Notes		—			—			—			—			80.0			—			80.0

Total West Penn	$	75.5		$	79.9		$	16.0		$	—		$	80.0		$	420.0		$	671.4

Potomac Edison:
First Mortgage Bonds	$	—		$	—		$	—		$	—		$	—		$	420.0		$	420.0
Environmental Control Bonds (a)		4.9			3.5			3.7			3.8			4.1			94.8			114.8

Total Potomac Edison	$	4.9		$	3.5		$	3.7		$	3.8		$	4.1		$	514.8		$	534.8

TrAIL Company:
Short-Term Promissory Note	$	10.0		$	—		$	—		$	—		$	—		$	—		$	10.0

Total TrAIL	$	10.0		$	—		$	—		$	—		$	—		$	—		$	10.0

Unamortized debt discounts, premiums and terminated interest rate swaps		(1.4	)		(1.4	)		(1.4	)		(1.1	)		(0.6	)		(1.8	)		(7.7	)
Eliminations (b)		—			—			—			—			(1.3	)		(13.1	)		(14.4	)

Total consolidated debt	$	104.0		$	92.6		$	139.4		$	986.3		$	751.7		$	1,975.3		$	4,049.3

(a)	Amounts represent planned repayments based upon estimated surcharge collections from customers.

(b)	Amounts represent the elimination of certain pollution control bonds, for which Monongahela and AE Supply are co-obligors.

Certain of Allegheny’s properties are subject to liens of various relative priorities securing debt.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2007 Debt Activity

In September 2007, AE Supply amended its credit facility to increase the size of its revolving credit facility from $200 million to $400 million.

On December 24, 2007, TrAIL Company issued a $10.0 million promissory note that matures on September 12, 2008. Proceeds from the promissory note will be used to fund interim construction and other costs of the TrAIL Project pending completion of long-term financing for the project.

Allegheny made various other debt payments during 2007.

Issuances and repayments of indebtedness, during 2007 were as follows:


(In millions)	Issuances			Repayments
Monongahela:
Environmental Control Bonds	$	344.5		$	—
Pollution Control Bonds		—			15.5
Potomac Edison:
Environmental Control Bonds		114.8			—
West Penn:
First Mortgage Bonds		275.0			—
Transition Bonds (a)		5.5			79.9
AE Supply:
Pollution Control Bonds		222.5			237.1
AE Supply Credit Facility		—			175.0
TrAIL Company:
Short-Term Promissory Note		10.0			—
Eliminations (b)		(7.0	)		(5.3	)

Consolidated Total	$	965.3		$	502.2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(a)	The issuance amounts represent interest that was accrued and added to the principal amount of certain of the bonds.

(b)	Represents the elimination of certain pollution control bonds for which Monongahela and AE Supply are co-obligors.

See Note 7, “Asset Swap,” for debt changes resulting from the January 1, 2007 Asset Swap.

2006 Debt Activity

In September 2006, Monongahela issued $150 million aggregate principal amount of 5.70% First Mortgage Bonds that mature in 2017. Monongahela used the net proceeds from the sale of the $150 million aggregate principal amount of 5.70% First Mortgage Bonds, plus available cash on hand, to fund the repayment at maturity of the $300 million aggregate principal amount of 5.0% First Mortgage Bonds.

Allegheny made various other debt payments during 2006.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Issuances and repayments of indebtedness, by entity, during 2006 were as follows:


(In millions)	Issuances		Repayments
AE:
AE Credit Facility	$	219.1	$	219.1
2005 AE Credit Facility		—		199.0
Monongahela:
First Mortgage Bonds		150.0		300.0
AE Supply:
AE Supply Credit Facility		967.0		220.0
2005 AE Supply Term Loan		—		989.0
Potomac Edison:
First Mortgage Bonds		100.0		—
Medium-Term Notes		—		100.0
West Penn:
First Mortgage Bonds		145.0		—
Transition Bonds (a)		5.2		75.8

Consolidated Total	$	1,586.3	$	2,102.9

(a)	The issuance amounts represent interest that was accrued and added to the principal amount of certain of the bonds.

During 2008, AE Supply made payments of $125 million on its credit facility.

NOTE 12: DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

In accordance with SFAS 133, all derivatives, except those for which an exception applies, are recorded in Allegheny’s Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions are reported as derivative assets, and derivative contracts representing unrealized loss positions are reported as derivative liabilities. The fair values of derivative instruments are based primarily on exchange prices and broker quotes. If a quoted market price is not available, the estimated fair value is based on the best information available, including valuation models that utilize market and broker information and other market data and assumptions, reduced by appropriate valuation adjustments for items such as liquidity and credit quality. Derivative contracts that have been designated as normal purchases or normal sales under SFAS 133 are not subject to mark to market accounting treatment and their effects are included in earnings at the time of contract performance.

Certain derivative contracts that hedge an exposure to variability in expected future cash flows attributable to a particular risk or transaction have been designated as cash flow hedges. A portion of Allegheny’s hedge strategies include the use of derivative contracts to manage the variable price risk related to the forecasted sale of electricity. These contracts held at December 31, 2007 expire at various dates through 2008.

For cash flow hedges, changes in the fair value of the derivative contract are reported in accumulated other comprehensive income (loss), to the extent they are effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. Changes in any ineffective portion of the hedge are immediately recognized in earnings.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For derivative contracts that have not been designated as normal purchase or normal sales or designated as part of a hedging relationship, unrealized and realized gains and losses are included in revenues or expenses on the Consolidated Statements of Income, depending on relevant facts and circumstances.

During 2003 Allegheny entered into three interest rate swap agreements with an aggregate notional value of $343 million to substantially offset three existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions. These positions are accounted for using mark to market accounting through earnings. Net future cash outflows under these interest rate swap agreements are approximately $5 million to $6 million annually through September, 2011.

The recorded fair values of derivative contracts at December 31, 2007 and 2006 were as follows:


	2007						2006
(In millions)	Current			Long- term			Current			Long- term
Derivative assets:
Power transaction cash flow hedges	$	—		$	—		$	1.2		$	—
Power transaction mark-to-market		—			—			0.2			—

Total derivative assets		—			—			1.4			—

Derivative liabilities:
Interest rate swaps		(6.4	)		(12.8	)		(5.9	)		(18.0	)
Power transaction cash flow hedges		(6.6	)		—			—			—
Power transaction mark-to-market		(0.4	)		—			—			—
Other derivatives		(0.7	)		—			—			—

Total derivative liabilities		(14.1	)		(12.8	)		(5.9	)		(18.0	)

Net fair value of derivative contracts	$	(14.1	)	$	(12.8	)	$	(4.5	)	$	(18.0	)

For 2007, 2006 and 2005, $3.2 million, $32.4 million and $20.6 million, respectively, of unrealized gains were included in operating revenues related to derivative transactions.

For 2007, 2006 and 2005, $3.8 million, $(27.2) million $(24.9) million, respectively, of realized gains (losses) were included in operating revenues related to derivative and normal purchase and normal sale transactions.

The following table shows the activity in accumulated other comprehensive income (loss) for derivative contracts that qualified as cash flow hedges. The entire accumulated other comprehensive loss balance at December 31, 2007 is expected to be reclassified to earnings over the next twelve months. The ineffective portion of the power transaction hedges for 2007 and 2006 was $(0.3) million and $1.3 million, respectively and was reflected in earnings.


(In millions)	2007			2006
Balance at January 1,	$	0.2		$	(31.5	)
Changes in fair value		(0.8	)		20.1
Reclasses from accumulated other comprehensive loss to net earnings		(3.7	)		11.6

Balance at December 31,	$	(4.3	)	$	0.2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 13: JOINTLY OWNED BATH COUNTY GENERATION FACILITY

AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,059 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC is consolidated by Allegheny through its subsidiary, AE Supply. AGC’s investment and accumulated depreciation in the Bath County generation facility, at December 31 were as follows:


(Dollars in millions)	2007			2006
Utility plant investment	$	837.1		$	835.6
Accumulated depreciation	$	330.7		$	318.1
Ownership %		40	%		40	%

NOTE 14: DISCONTINUED OPERATIONS

During 2004, Allegheny began efforts to sell Monongahela’s natural gas operations and AE Supply’s natural gas-fired peaking facilities (Lincoln, Wheatland and Gleason) and recorded impairment charges to adjust the carrying value of these assets to estimated net sales proceeds. The results of these operations were classified as discontinued operations in the accompanying Consolidated Statements of Income, and, through the dates on which these sales concluded, their assets and liabilities were classified as held for sale in the Consolidated Balance Sheets. See Note 15, “Asset Sales” for additional information. These asset sales were completed in 2006, and Allegheny had no income (loss) from discontinued operations in 2007.

The components of income (loss) from discontinued operations for 2006 and 2005 were as follows:


(In millions)	2006			2005
AE Supply:
Operating revenues	$	—		$	0.4
Operating expenses		7.3			7.2
Interest expense		(2.5	)		(10.2	)

Income (loss) before income taxes		4.8			(2.6	)
Income tax benefit (expense)		(1.8	)		2.6
Impairment charge, net of tax		(1.4	)		(7.2	)

Income (loss) from discontinued operations, net of tax	$	1.6		$	(7.2	)

Monongahela:
Operating revenues	$	—		$	218.1
Operating expenses		(1.7	)		(201.6	)
Other income		—			1.0
Interest expense		—			(6.1	)

Income (loss) before income taxes		(1.7	)		11.4
Income tax benefit (expense)		0.7			(3.4	)
Impairment charge, net of tax		—			(7.0	)

Income (loss) from discontinued operations, net of tax	$	(1.0	)	$	1.0

Consolidated:
Operating revenues	$	—		$	218.5
Operating expenses		5.6			(194.3	)
Other income		—			1.0
Interest expense		(2.5	)		(16.3	)

Income before income taxes		3.1			8.9
Income tax expense		(1.1	)		(0.8	)
Impairment charge, net of tax		(1.4	)		(14.2	)

Income (loss) from discontinued operations, net of tax	$	0.6		$	(6.1	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 15: ASSET SALES

On December 31, 2005, Monongahela completed the sale of its Ohio T&D assets to Columbus Southern Power Company (“Columbus Southern”) for net proceeds of $51.8 million. The purchase price for the assets was the net book value at the time of closing, plus $10.0 million, less certain property taxes. The sale included a power sales agreement under which Monongahela provided power to Columbus Southern for Monongahela’s former Ohio retail customers from the time of closing through May 31, 2007 at $45 per megawatt-hour, which at the time of the transaction was less than the projected market price for power. During 2005, Monongahela recorded a loss on the sale of $29.3 million based on the estimated value, at December 31, 2005, of Monongahela’s power sales agreement with Columbus Southern to provide power at below-market prices from January 1, 2006 through May 31, 2007, partially offset by approximately $8.0 million, representing the purchase price less net book value of the assets at December 31, 2005 and approximately $2.0 million in expenses associated with the sale.

On September 30, 2005, Monongahela completed the sale of its West Virginia natural gas operations to Mountaineer Gas Holdings Limited Partnership, a partnership composed of IGS Utilities LLC, IGS Holdings LLC and affiliates of ArcLight Capital Partners, LLC, for approximately $161.0 million and the assumption of approximately $87.0 million of long-term debt. The assets sold included all of the issued and outstanding capital stock of Mountaineer Gas and certain other assets related to the West Virginia natural gas operations.

During May 2005, Potomac Edison completed the sale of its Hagerstown, Maryland property for $10.6 million in net proceeds.

Following the sale of AE Supply’s Gleason generation facility, there were no assets classified as held for sale or liabilities associated with assets classified as held for sale at December 31, 2006.

NOTE 16: BUSINESS SEGMENTS

Allegheny manages and evaluates its operations in two business segments, the Delivery and Services segment and the Generation and Marketing segment. Monongahela operates in both segments. All other Allegheny subsidiaries operate in only one segment. The Delivery and Services segment includes the operations of Potomac Edison, West Penn, Allegheny Ventures, TrAIL Company, PATH, LLC and Monongahela’s electric T&D business. The Generation and Marketing segment includes the operations of AE Supply, AGC and Monongahela’s West Virginia generating assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Business segment information for Allegheny is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts.


(In millions)	Delivery and Services			Generation and Marketing			Other		Eliminations			Total
2007
External operating revenues	$	2,819.8		$	487.2		$	—	$	—		$	3,307.0
Internal operating revenues		9.4			1,654.1			—		(1,663.5	)		—

Total operating revenues	$	2,829.2		$	2,141.3		$	—	$	(1,663.5	)	$	3,307.0
Depreciation	$	143.8		$	114.5		$	—	$	—		$	258.3
Amortization	$	18.6		$	0.1		$	—	$	—		$	18.7
Operating income	$	253.9		$	563.4		$	—	$	—		$	817.3
Interest expense	$	73.5		$	119.9		$	—	$	(6.2	)	$	187.2
Income tax expense	$	78.4		$	172.4		$	—	$	—		$	250.8
Net income	$	117.7		$	294.5		$	—	$	—		$	412.2
Capital expenditures	$	300.9		$	547.5		$	—	$	—		$	848.4
Identifiable assets	$	4,579.1		$	5,256.3		$	277.3	$	(206.1	)	$	9,906.6

2006
External operating revenues	$	2,710.3		$	411.2		$	—	$	—		$	3,121.5
Internal operating revenues		7.4			1,423.2			—		(1,430.6	)		—

Total operating revenues	$	2,717.7		$	1,834.4		$	—	$	(1,430.6	)	$	3,121.5
Depreciation	$	135.9		$	121.8		$	—	$	—		$	257.7
Amortization	$	15.4		$	—		$	—	$	—		$	15.4
Operating income	$	319.8		$	412.5		$	—	$	—		$	732.3
Interest expense	$	80.6		$	192.7		$	—	$	(3.0	)	$	270.3
Income tax expense from continuing operations	$	80.2		$	93.3		$	—	$	—		$	173.5
Income from continuing operations	$	180.4		$	138.3		$	—	$	—		$	318.7
Income (loss) from discontinued operations, net of tax	$	(1.0	)	$	1.6		$	—	$	—		$	0.6
Net income	$	179.4		$	139.9		$	—	$	—		$	319.3
Capital expenditures	$	237.8		$	209.5		$	—	$	—		$	447.3
Identifiable assets	$	4,269.9		$	3,985.9		$	324.5	$	(27.9	)	$	8,552.4

2005
External operating revenues	$	2,836.1		$	201.8		$	—	$	—		$	3,037.9
Internal operating revenues		9.4			1,501.5			—		(1,510.9	)		—

Total operating revenues	$	2,845.5		$	1,703.3		$	—	$	(1,510.9	)	$	3,037.9
Depreciation	$	137.5		$	154.6		$	—	$	—		$	292.1
Amortization	$	16.1		$	—		$	—	$	—		$	16.1
Operating income	$	266.5		$	270.3		$	—	$	—		$	536.8
Interest expense	$	120.6		$	316.8		$	—	$	(1.0	)	$	436.4
Income tax expense from continuing operations	$	55.2		$	9.6		$	—	$	—		$	64.8
Income (loss) from continuing operations	$	112.2		$	(37.0	)	$	—	$	(0.1	)	$	75.1
Income (loss) from discontinued operations, net of tax	$	1.0		$	(7.2	)	$	—	$	0.1		$	(6.1	)
Cumulative effect of accounting change, net of tax	$	—		$	(5.9	)	$	—	$	—		$	(5.9	)
Net income (loss)	$	113.2		$	(50.1	)	$	—	$	—		$	63.1
Capital expenditures	$	184.8		$	121.7		$	—	$	—		$	306.5
Identifiable assets	$	4,222.2		$	4,055.7		$	310.7	$	(29.8	)	$	8,558.8

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NOTE 17: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains the SERP for executive officers and other senior executives.

Allegheny also provides subsidies for medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the postretirement benefits other than pensions, have retiree premiums based upon an age and years-of-service vesting schedule, include other plan provisions that limit future benefits and take into account certain collective bargaining arrangements. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006. The provisions of the postretirement health care plans and certain collective bargaining arrangements limit Allegheny’s costs for eligible retirees and dependents.

On September 29, 2006, the FASB issued SFAS 158. Allegheny adopted the recognition and disclosure provisions of SFAS 158 as of December 31, 2006. SFAS 158 required Allegheny to recognize the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligations) of its benefit plans in its December 31, 2006 consolidated balance sheet, with a corresponding adjustment to comprehensive loss, net of tax. In accordance with SFAS 158, at December 31, 2006, Allegheny also derecognized the Additional Minimum Pension Liability (“AML”) and related intangible assets previously recognized under SFAS 87, “Employers’ Accounting for Pensions.”

During 2006, Allegheny determined that a portion of the obligations related to pensions and postretirement benefits other than pensions are probable for future recovery under the regulatory ratemaking process in certain of Allegheny’s jurisdictions. Accordingly, a regulatory asset was recorded in the amount of $59.7 million related to the AML immediately prior to adoption of SFAS 158, with the offsetting credit to other comprehensive income, net of tax. In addition, upon adoption of SFAS 158, regulatory assets were recorded in the amounts of $42.4 million and $76.1 million relating to pension and postretirement benefits other than pensions, respectively. The remaining effects of adopting SFAS 158 were recorded as a charge to accumulated other comprehensive loss, net of tax, in stockholders’ equity.

The following table summarizes the effects of applying SFAS 158, in connection with SFAS 71, as well as the changes in accrued liabilities, intangible assets, regulatory assets and accumulated other comprehensive loss relating to Allegheny’s pension plans and postretirement benefit other than pension plans during 2006.


	December 31, 2006
(In millions)	Balance with AML from 2005			AML and SFAS 71 Adjustments			Sub-totals			SFAS 158 Adjustment			Consolidated Balance Sheet Amounts
Pension Plans:
Accrued pension liability	$	164.8		$	(39.4	)	$	125.4		$	87.8		$	213.2
Intangible asset	$	27.4		$	(4.8	)	$	22.6		$	(22.6	)	$	—
Regulatory asset	$	—		$	59.7		$	59.7		$	42.4		$	102.1
Accumulated other comprehensive loss, pre-tax	$	(186.9	)	$	94.3		$	(92.6	)	$	(68.0	)	$	(160.6	)
Postretirement Benefit Plans Other Than Pension Plans:
Accrued liability	$	111.2		$	—		$	111.2		$	96.1		$	207.3
Regulatory asset	$	—		$	—		$	—		$	76.1		$	76.1
Accumulated other comprehensive loss, pre-tax	$	—		$	—		$	—		$	(20.0	)	$	(20.0	)

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SFAS 158 did not change the determination of pension costs under prior accounting standards. Allegheny currently uses a measurement date of September 30 for its pension plans and postretirement benefits other than pension plans. Allegheny is required under SFAS 158 to change to a December 31 measurement date and will do so, as permitted by the pronouncement, beginning with the year ending December 31, 2008.

The components of the net periodic cost for pension benefits and for postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents and the allocation by Allegheny, through AESC, of costs for pension benefits and postretirement benefits other than pensions were as follows:


	Pension Benefits									Postretirement Benefits Other Than Pensions
(In millions)	2007			2006			2005			2007			2006			2005
Components of net periodic cost:
Service cost	$	21.4		$	21.7		$	23.6		$	4.5		$	5.1		$	4.0
Interest cost		64.7			61.4			63.4			17.0			16.9			16.8
Expected return on plan assets		(73.0	)		(69.6	)		(69.2	)		(6.7	)		(7.0	)		(6.2	)
Amortization of unrecognized transition obligation		0.5			0.5			0.5			5.7			5.7			5.9
Amortization of prior service cost		3.2			3.5			3.6			—			—			—
Recognized actuarial loss		10.5			12.4			9.2			2.4			3.8			2.1

Subtotal		27.3			29.9			31.1			22.9			24.5			22.6
Curtailments and settlements		—			—			1.3			—			—			3.4

Net periodic cost	$	27.3		$	29.9		$	32.4		$	22.9		$	24.5		$	26.0

Allocation of net periodic cost:
Monongahela	$	8.7		$	7.7		$	10.0		$	7.0		$	6.8		$	9.0
AE Supply		6.4			9.0			9.0			4.5			5.6			5.2
West Penn		6.8			7.4			7.4			6.2			6.7			6.5
Potomac Edison		5.1			5.4			5.5			5.1			5.3			5.0
AE		0.3			0.4			0.5			0.1			0.1			0.3

Net periodic cost	$	27.3		$	29.9		$	32.4		$	22.9		$	24.5		$	26.0

Portion of net periodic cost above included in discontinued operations	$	—		$	—		$	1.7		$	—		$	—		$	2.6

For the years ended December 31, 2007, 2006 and 2005, Allegheny capitalized $14.1 million, $13.0 million and $12.2 million, respectively, of the above net periodic cost amounts to “Construction work in progress,” a component of “Property, plant and equipment, net.”

The net periodic cost for 2005 for pension benefits includes $1.0 million of curtailment charges due to the outsourcing of Allegheny’s information technology function. The net periodic cost for 2005 for postretirement benefits other than pensions includes $2.0 million of settlement charges due to the sale of Monongahela’s West Virginia natural gas operations and $1.1 million of curtailment charges due to the outsourcing of the information technology function.

Allegheny uses the market-related value of pension assets to determine the expected return on pension plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight line basis over a five-year period. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains

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and losses. Allegheny uses the fair value of assets to determine the expected return on postretirement benefits other than pension assets.

The amounts in accumulated other comprehensive loss, pre-tax, and regulatory assets that are expected to be recognized as components of net periodic cost during the next fiscal year are as follows:


(In millions)	Pension Benefits		Postretirement Benefits Other Than Pensions
Net actuarial loss	$	7.2	$	0.6
Net prior service cost		3.2		—
Net transition obligation		0.5		5.7

Total to be recognized in net periodic cost	$	10.9	$	6.3

The amounts accrued at December 31, using a measurement date of September 30, included the following components:


	Pension Benefits						Postretirement Benefits Other Than Pensions
(In millions)	2007			2006			2007			2006
Change in benefit obligation:
Benefit obligations at beginning of year	$	1,111.1		$	1,129.9		$	293.3		$	311.3
Service cost		21.4			21.7			4.5			5.2
Interest cost		64.7			61.4			17.0			16.8
Plan participants’ contributions		—			—			3.3			3.0
Actuarial (gain)/loss		(26.6	)		(31.1	)		(17.2	)		(17.0	)
Benefits paid		(66.9	)		(70.8	)		(22.8	)		(26.0	)

Benefit obligation at end of year		1,103.7			1,111.1			278.1			293.3

Change in plan assets:
Fair value of plan assets at beginning of year		897.8			839.5			83.7			81.5
Actual return on plan assets		97.4			62.9			12.6			7.7
PBGC premium refund		—			0.9			—			—
Plan participants’ contributions		—			—			3.3			3.0
Employer contribution		35.8			65.3			7.8			6.9
Benefits paid		(66.9	)		(70.8	)		(17.5	)		(15.4	)

Fair value of plan assets at end of year		964.1			897.8			89.9			83.7

Funded status prior to fourth quarter contribution		(139.6	)		(213.3	)		(188.2	)		(209.6	)
Employer contribution in the fourth quarter		0.1			0.1			3.4			2.3

Funded status at December 31	$	(139.5	)	$	(213.2	)	$	(184.8	)	$	(207.3	)

The SERP is a non-qualified pension plan, and Allegheny is therefore not obligated to fund the SERP obligation. The SERP obligation, which is included as a component of the pension benefit obligation, shown in the table above, was $5.4 million and $5.9 million at December 31, 2007 and 2006, respectively.

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Amounts recognized in the Consolidated Balance Sheets at December 31 were as follows:


	Pension Benefits						Postretirement Benefits Other Than Pensions
(In millions)	2007			2006			2007			2006
Noncurrent liabilities	$	(139.5	)	$	(213.2	)	$	(184.8	)	$	(207.3	)

Net amounts recognized at December 31	$	(139.5	)	$	(213.2	)	$	(184.8	)	$	(207.3	)

Amounts recognized in “Accumulated other comprehensive loss,” pre-tax, at December 31, that have not yet been recognized as components of net periodic benefit cost, were as follows:


	Pension Benefits						Postretirement Benefits Other Than Pensions
(In millions)	2007			2006			2007			2006
Net actuarial loss	$	176.8		$	238.4		$	36.5		$	62.0
Net prior service cost		18.3			21.5			—			—
Net transition obligation		2.3			2.8			28.4			34.1

Accumulated other comprehensive loss, pre-tax		197.4			262.7			64.9			96.1
Regulatory asset		(150.3	)		(102.1	)		(52.4	)		(76.1	)

Accumulated other comprehensive loss, pre-tax, recognized at December 31	$	47.1		$	160.6		$	12.5		$	20.0

Allegheny has determined that a portion of the unfunded pension and postretirement benefit obligations represents an incurred cost that qualifies for regulatory asset treatment under SFAS 71. Because future recovery of these incurred costs are probable for certain of its state jurisdictions, Allegheny has recorded regulatory assets in the amounts of $150.3 million for pension benefits and $52.4 million for postretirement benefits other than pensions at December 31, 2007. The 2007 increase in regulatory assets related to unfunded pension obligations relates to the acceptance of Allegheny’s accrual method for pension expense in the May 2007 West Virginia Rate Order, as a result of which, Allegheny established an additional regulatory asset in 2007 related to the West Virginia portion of the unfunded pension obligations.

The accumulated benefit obligation for all defined benefit pension plans was $1,014.6 million and $1,023.3 million at December 31, 2007 and 2006, respectively. The portion of the total accumulated benefit obligation related to the SERP was $4.3 million and $4.8 million at December 31, 2007 and 2006, respectively.

Information for pension plans with a projected benefit obligation and an accumulated benefit obligation in excess of plan assets was as follows:


	Pension Benefits
(In millions)	2007		2006
Projected benefit obligation	$	1,103.7	$	1,111.1
Accumulated benefit obligation	$	1,014.6	$	1,023.3
Fair value of plan assets	$	964.1	$	897.8

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The assumptions used to determine net periodic benefit costs for the years ended December 31, 2007, 2006 and 2005 are shown in the table below.


	Pension Benefits						Postretirement Benefits Other Than Pensions
	2007		2006		2005		2007		2006		2005
Discount rate	6.00	%	5.60	%	5.90	%	6.00	%	5.60	%	5.90	%
Expected long-term rate of return on plan assets (a)	8.50	%	8.50	%	8.50	%	8.50	%	8.50	%	8.50	%
Rate of compensation increase	3.60	%(b)	3.25	%	3.25	%	3.60	%(b)	3.25	%	3.25	%

(a)	Excluding administrative expenses.

(b)	Weighted-average rate for age graded scale.

The assumptions used to determine benefit obligations at December 31, 2007 and 2006 are shown in the table below:


	Pension Benefits				Postretirement Benefits Other Than Pensions
	2007		2006		2007		2006
Discount rate	6.40	%	6.00	%	6.40	%	6.00	%
Rate of compensation increase (a)	3.60	%	3.60	%	3.60	%	3.60	%

(a)	Weighted-average rate for age graded scale.

In selecting an assumed discount rate, Allegheny uses a modeling process that involves the hypothetical selection of high-quality bonds (AA- or better), the interest and principal payments on which match the timing and amount of Allegheny’s expected future benefit payments. Allegheny considers the results of this modeling process, as well as overall rates of return on high quality corporate bonds and changes in such rates over time, in determining its assumed discount rate.

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs in 2008 is 8.25%, which is net of administrative expenses.

Assumed health care cost trend rates at December 31 were as follows:


	2007		2006
Health care cost trend rate assumed for next year	9.5	%	9.0	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2017		2015

For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.5% beginning with 2008 and decreasing by 0.5% each year thereafter to an ultimate rate of 5.0%, and plan provisions that limit future medical and life insurance benefits. Because of the plan provisions that limit future benefits, changes in the assumed health care cost trend rate would have a limited

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effect on the amounts displayed in the tables above. A one-percentage-point change in the assumed health care cost trend rate would have the following effects:


(In millions)	1-Percentage-Point Increase		1-Percentage-Point Decrease
Effect on total of service and interest cost components	$	0.6	$	(0.6	)
Effect on accumulated postretirement benefit obligation	$	5.5	$	(4.9	)

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) became law. The federal government provides subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. The subsidy is 28% of eligible drug costs for retirees who are over age 65 and covered under Allegheny’s postretirement benefits other than pensions plan.

Allegheny’s plan actuary has determined that the prescription drug benefit offered under Allegheny’s postretirement benefits other than pensions plan is at least actuarially equivalent to Medicare Part D and therefore, starting in 2006, Allegheny is receiving the federal subsidy offered under the Medicare Act. Allegheny expects to receive subsidies of approximately $1.6 million to $2.1 million annually during the period from 2008 through 2012. Allegheny received a total subsidy of approximately $1.4 million for each of the years of 2007 and 2006.

Plan Assets

Allegheny’s pension plan asset allocations as of the measurement dates of September 30, 2007 and 2006, by asset category were as follows:


	Plan Assets at September 30,
	2007		2006
Asset Category:
Equity securities	51	%	50	%
Fixed income securities	47	%	49	%
Real estate investment trusts	2	%	1	%

Total	100	%	100	%

Allegheny’s postretirement benefits other than pension asset allocations as of the measurement dates of September 30, 2007 and 2006, by asset category were as follows:


	Plan Assets at September 30,
	2007		2006
Asset Category:
Equity securities	61	%	59	%
Fixed income securities	33	%	35	%
Other	6	%	6	%

Total	100	%	100	%

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As of September 30, 2007, the investment policy of the defined benefit pension plan specified a long-term target asset allocation objective of 45% equity securities, 50% fixed income securities and 5% real estate investment trusts. The investment policies for the assets associated with the postretirement benefits other than pension plans vary based on the particular structure of each plan. As of September 30, 2007, the investment policies of these plans specified a long-term target asset allocation ranging from 55% to 75% equity securities and from 25% to 45% fixed income securities. The asset allocations represent a long-term perspective. Under the plans’ investment policies, the allocations may vary from the stated objective within specified ranges. Market shifts, changes in the plan dynamics or changes in economic conditions may cause the asset mix to fall outside of the long-term policy range in a given period.

Contributions

Allegheny’s contributions to the pension plan 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 estimates that its contributions to the pension plan during 2008 will approximate $35 million. Allegheny also currently anticipates that it will contribute $15 million to $18 million during 2008 to fund postretirement benefits other than pensions. These anticipated contributions may change in the future if Allegheny’s assumptions regarding prevailing interest rates change, if actual investments under-perform or out-perform estimated returns, if actuarial assumptions or asset valuation methods change or if there are changes to employee benefit and tax laws.

In the third quarter of 2006, the Pension Protection Act of 2006 (the “Pension Protection Act”) was signed into law. The Pension Protection Act may affect the manner in which many companies, including Allegheny, administer their pension plans. The Pension Protection Act is effective January 1, 2008 and will require many companies to more fully fund their pension plans according to new funding targets, potentially resulting in greater annual contributions. Allegheny is currently assessing the impact that the new legislation will have on its pension funding in future years.

Estimated Future Benefit Payments

The following table shows estimated benefit payments to be made by Allegheny, including expected future service, as appropriate, and the estimated federal subsidy payments to be received by Allegheny:


	Pension Benefits		Postretirement Benefits Other Than Pensions
(In millions)	Pension Benefits		Benefit Payments		Expected Federal Subsidy
2008	$	66.6	$	21.7	$	1.6
2009	$	66.9	$	21.9	$	1.8
2010	$	67.3	$	22.0	$	1.9
2011	$	68.1	$	22.1	$	2.1
2012	$	69.4	$	22.0	$	1.7
2013 – 2017	$	376.9	$	114.3	$	—

ESOSP 401(k) Savings Plan

The Allegheny Energy Employee Stock Ownership and Savings Plan (“ESOSP”) was established as a non-contributory stock ownership plan for all eligible employees, effective January 1, 1976, and was amended in 1984 to include a savings program. All of Allegheny’s employees, subject to meeting eligibility requirements,

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may elect to participate in the ESOSP. Under the ESOSP, each eligible employee may elect to have from 2% to 15% of his or her compensation contributed to the ESOSP on a pre-tax basis. Starting July 1, 2007 some or all of these contributions may be made on a Roth 401(k) contribution basis. An additional 1% to 6% of compensation may be contributed on a post-tax basis. Participants direct the investment of contributions to specified mutual funds or AE common stock. Allegheny matches 50% of an employee’s first 6% of pre-tax salary deferrals and Roth 401(k) contributions into the ESOSP.

In 2007 and 2006, AE made ESOSP matching contributions in cash in the amount of $8.1 million and $7.5 million, respectively. In 2005, AE made matching contributions in the form of AE common stock, which consisted of 294,904 newly issued shares with a market value of $7.8 million. The fair value of these contributions was expensed, less amounts capitalized in “Construction work in progress.” The capitalized portions of these costs were $2.2 million, $1.9 million and $1.9 million in 2007, 2006 and 2005, respectively.

Disability Benefits

Allegheny provides benefits to eligible employees who are unable to perform their work duties due to an injury or illness. These benefits include income replacement under the Allegheny Energy Long-Term Disability Plan and medical and life insurance benefits under Allegheny’s medical and life insurance plans. The benefits are paid in accordance with Allegheny’s established benefit practices and policies. The liability related to these disability benefits was $10.5 million at December 31, 2007 and $12.8 million at December 31, 2006.

NOTE 18: GOODWILL AND INTANGIBLE ASSETS

Allegheny had recorded goodwill of $367.3 million at December 31, 2007 and 2006 relating to its Generating and Marketing segment. There were no changes in recorded goodwill during 2007 and 2006. Goodwill is tested annually for impairment, but is not amortized. Absent any impairment indicators, Allegheny performs its annual impairment test during its third quarter in connection with its annual budgeting process using a discounted cash flow methodology. Our annual testing resulted in no impairment of goodwill during the years presented.

Intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:


	December 31, 2007				December 31, 2006
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Land easements, amortized	$	98.4	$	29.6	$	97.9	$	28.4
Land easements, unamortized		30.7		—		30.7		—
Software		65.2		12.7		47.0		31.1

Total	$	194.3	$	42.3	$	175.6	$	59.5

Amortization expense for intangible assets was $14.9 million in both 2007 and 2006 and was $14.7 million in 2005.

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Future amortization expense for intangible assets at December 31, 2007 is estimated as follows:


(In millions)	2008		2009		2010		2011		2012
Annual amortization expense	$	11.8	$	11.3	$	10.4	$	9.8	$	9.0

NOTE 19: ADVERSE POWER PURCHASE COMMITMENT LIABILITY

On May 29, 1998, the Pennsylvania PUC issued an order approving a transition plan for West Penn. This order was amended by a settlement agreement approved by the Pennsylvania PUC on November 19, 1998. West Penn recorded an extraordinary charge under the provisions of SFAS 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement 71,” in 1998 to reflect the disallowances of certain costs in the order. This charge included an estimated amount for an adverse power purchase commitment reflecting the commitment to purchase power at above-market prices. The adverse power purchase commitment liability is being amortized over the life of the commitment based on a schedule of estimated electricity purchases used to determine the amount of the charge.

As of December 31, 2007, Allegheny’s reserve for adverse power purchase commitments was $166.9 million, including a current liability of $17.1 million. Allegheny’s liability for adverse power purchase commitments decreased as follows:


(In millions)	2007		2006		2005
Amortization of liability for adverse power purchase commitments	$	17.3	$	17.2	$	16.7

These decreases in the reserve for adverse power purchase commitments are recorded as expense reductions in “Purchased power and transmission” on the Consolidated Statements of Income.

NOTE 20: REVIEW OF ESTIMATED REMAINING SERVICE LIVES AND DEPRECIATION PRACTICES

Allegheny completed a review of the estimated remaining service lives and depreciation practices relating to its unregulated generation facilities during the first quarter of 2006. As a result of this review, effective January 1, 2006, Allegheny prospectively extended the depreciable lives of its unregulated coal-fired generation facilities for periods ranging from 5 to 15 years to match the estimated remaining economic lives of these generation facilities. The extension of estimated lives reflected a number of factors, including the physical condition of the facilities, current maintenance practices and planned investments in the facilities. Allegheny also updated its property unit catalog and retirement unit definitions. These changes were considered in estimating the revised depreciation rates. The effect of these changes in accounting estimates decreased depreciation expense related to Allegheny’s unregulated coal-fired generation facilities by $35.8 million in 2006 compared to the amount that would have been reflected in such expenses had the estimates not been revised. Additionally, as certain activities now qualify for capitalization based on the revised retirement unit definitions, operations and maintenance expense decreased by $25.5 million in 2006, compared to the amounts that would have been reflected in such expenses had the estimates not been revised.

NOTE 21: ASSET RETIREMENT OBLIGATIONS (“ARO”)

Allegheny has AROs primarily related to ash landfills and underground and aboveground storage tanks and Conditional AROs related to asbestos contained in its generation facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”).

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The following is an analysis of the changes in the ARO liability in 2007:


(In millions)	ARO Liability
Balance at December 31, 2006	$	54.8
Accretion of the liability		6.1
New ARO liabilities:
Ash disposal monitoring facility		7.7
Wastewater treatment lagoon		1.0
Settlements of ARO liabilities:
Ash disposal site		(6.5	)
Asbestos removal		(1.5	)
Other		(0.6	)

Balance at December 31, 2007	$	61.0

Effective December 31, 2005, Allegheny adopted FIN 47. The effect on Allegheny’s Consolidated Statements of Income in 2005 of adopting FIN 47, which related solely to AE Supply, was a $9.3 million decrease in pre-tax income and a $5.9 million decrease in net income. These amounts were recorded within “Cumulative effect of accounting change.”

Allegheny believes it is probable that, for regulated companies, any difference between expenses recorded for AROs and Conditional AROs and expenses recovered currently in rates with respect to these assets will be recoverable in future rates and therefore defers these regulatory costs as regulatory assets or a reduction against related regulatory liabilities.

NOTE 22: FAIR VALUE OF FINANCIAL INSTRUMENTS

As of December 31, 2007 and 2006, the carrying amounts of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities and short-term debt are representative of fair value because of their short-term nature. The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year, and preferred stock of a subsidiary, at December 31, 2007 and 2006 were as follows:


	2007				2006
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	4,039.3	$	4,110.4	$	3,585.2	$	3,694.9
Preferred stock of subsidiary—Monongahela	$	—	$	—	$	24.0	$	21.3

The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The fair value of preferred stock was based on quoted market prices.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 23: OTHER INCOME AND EXPENSES, NET

Other income and expenses, net, consisted of the following:


(In millions)	2007		2006		2005
Interest and dividend income	$	15.2	$	18.3	$	14.3
Gain on the sale or exchange of real estate		8.9		1.3		1.7
Tax reimbursement on contributions in aid of construction		5.5		6.5		3.0
Equity component of AFUDC		2.7		1.7		1.4
Premium services		1.8		4.2		3.7
Coal brokering income, net		1.7		1.9		2.2
Cash received from a former trading executive’s forfeited assets		—		—		11.2
Proceeds from sale of America’s Fiber Network, LLC		—		—		5.5
Other		1.0		0.1		1.2

Total other income and expenses, net	$	36.8	$	34.0	$	44.2

NOTE 24: QUARTERLY FINANCIAL INFORMATION (Unaudited)


	2007 Quarter Ended (a)								2006 Quarter Ended (a)
(In millions, except per share amounts)	March 31		June 30		September 30		December 31		March 31			June 30			September 30			December 31
Operating revenues	$	847.6	$	826.5	$	846.6	$	786.3	$	845.6		$	722.2		$	816.6		$	737.0
Operating income	$	235.2	$	186.9	$	228.4	$	166.8	$	247.8		$	115.4		$	211.2		$	157.9
Income from continuing operations	$	109.7	$	77.0	$	115.0	$	110.4	$	114.2		$	32.0		$	110.7		$	61.8
Income (loss) from discontinued operations, net		—		—		—		—		(0.8	)		(0.9	)		(0.5	)		2.8

Net income	$	109.7	$	77.0	$	115.0	$	110.4	$	113.4		$	31.1		$	110.2		$	64.6

Basic earnings per common share:
Income from continuing operations	$	0.66	$	0.46	$	0.69	$	0.66	$	0.70		$	0.20		$	0.67		$	0.37
Income (loss) from discontinued operations, net		—		—		—		—		—			(0.01	)		—			0.02

Basic income per common share	$	0.66	$	0.46	$	0.69	$	0.66	$	0.70		$	0.19		$	0.67		$	0.39

Diluted earnings per common share:
Income from continuing operations	$	0.65	$	0.45	$	0.67	$	0.65	$	0.68		$	0.19		$	0.65		$	0.37
Income (loss) from discontinued operations, net		—		—		—		—		(0.01	)		(0.01	)		—			0.01

Diluted income per common share	$	0.65	$	0.45	$	0.67	$	0.65	$	0.67		$	0.18		$	0.65		$	0.38

(a)	Quarterly amounts may not total to full-year results due to rounding.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 25: GUARANTEES AND LETTERS OF CREDIT

In connection with certain sales, acquisitions and financings, and in the normal course of business, AE and certain of its subsidiaries enter into various agreements that may include guarantees or letters of credit. AE’s credit facility includes a $400 million revolving facility, any unutilized portion of which is available for the issuance of letters of credit. In addition, AE Supply’s credit facility includes a $400 million revolving credit facility, which can be used, if availability exists, to issue letters of credit. Guarantees and letters of credit were as follows:


	December 31, 2007				December 31, 2006
(In millions)	Amounts Recorded on the Consolidated Balance Sheet		Total Guarantees and Letters of Credit		Amounts Recorded on the Consolidated Balance Sheet		Total Guarantees and Letters of Credit
Guarantees:
Loans and other financing-related matters	$	—	$	10.2	$	—	$	8.4
Lease agreement		—		4.9		—		4.7
Purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services		—		41.0		—		20.4
Other		0.2		0.2		0.2		0.2

Total Guarantees	$	0.2	$	56.3	$	0.2	$	33.7

Letters of Credit:
Under AE’s Revolving Facility (a)	$	—	$	6.7	$	—	$	131.8
Other (b)		—		2.5		—		2.1

Total Letters of Credit	$	—	$	9.2	$	—	$	133.9

Total Guarantees and Letters of Credit	$	0.2	$	65.5	$	0.2	$	167.6

(a)

The December 31, 2007 amount is comprised of a letter of credit for $6.7 million issued in connection with a contractual obligation of Allegheny Ventures that expires in July 2008. The December 31, 2006 amount also included a letter of credit for $125.0 million on behalf of Allegheny as collateral to stay enforcement of the judgment in Allegheny’s litigation against Merrill Lynch and Co., Inc. (“Merrill Lynch”). The $125.0 million letter of credit was released during the quarter ended September 30, 2007 as the result of an August 31, 2007 federal appellate court ruling. See Note 27, “Commitments and Contingencies” for additional information.

(b)	These amounts were not issued under either AE’s credit facility or AE Supply’s credit facility.

NOTE 26: VARIABLE INTEREST ENTITIES

FIN 46R requires the primary beneficiary of a Variable Interest Entity (“VIE”) to consolidate the entity and also requires majority and significant variable interest investors to provide certain disclosures. A VIE is an entity the equity investors of which do not have a controlling interest or in which the equity investment at risk is insufficient to finance the entity’s activities without receiving financial support from the other parties.

Potomac Edison and West Penn each have a long-term electricity purchase contract with an unrelated independent power producer (“IPP”). As required by FIN 46R, Allegheny periodically requests from these IPPs the information necessary to determine whether they are VIEs or whether Allegheny is the primary beneficiary. Allegheny has been unable to obtain the requested information, which was determined by the IPPs to be proprietary.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Potomac Edison and West Penn had power purchases from these two IPPs in the amount of $104.6 million and $52.5 million, respectively, in 2007, $93.2 million and $47.4 million, respectively, in 2006 and $105.3 million and $44.6 million, respectively, in 2005.

Potomac Edison recovers the full amount, and West Penn recovers a portion, of the cost of the applicable power contract in their respective rates charged to consumers or through customer surcharges. Neither Potomac Edison nor West Penn is subject to any risk of loss associated with the applicable VIE, because neither of them has any obligation to the applicable IPP other than to purchase the power that the IPP produces according to the terms of the applicable electricity purchase contract.

The Consolidated Financial Statements include the accounts of PATH, LLC in accordance with the provisions of FIN 46R.

NOTE 27: COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Moreover, there is a gap between desired reduction levels in the current proposed legislation and the current capabilities of technology; no current commercial-scale technology exists to enable many of the reduction levels being proposed in national, regional and state proposals. Such technology may not become available within a timeframe consistent with the implementation of any future climate control legislation 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, it could cost as much as $3,000 per kW to replace existing coal-based power generation with fossil fuel stations capable of capturing and sequestering CO₂ emissions, and recent project announcements suggest that these costs could be substantially higher. However, exact estimates are difficult because of the variance in the legislative proposals and the current lack of deployable technology.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Because the 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 seven tasks:

•

developing an accurate CO₂ emissions inventory;

•

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

•

following developing technologies for clean-coal energy and for CO₂ emission controls at coal-fired power plants;

•

following developing technologies for carbon sequestration;

•

participating in CO₂sequestration efforts (e.g. reforestation projects) both domestically and abroad;

•

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

•

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

Clean Air Act Compliance. Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through 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 meets current emission standards for sulfur dioxide (“SO₂”) by using emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

Allegheny’s compliance with the Clean Air Act of 1990 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the United States Environmental Protection Agency (the “EPA”) on March 10, 2005 may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Based on current forecasts, Allegheny estimates that it may have exposure to the SO₂ allowance market in 2008 of between 85,000 to 120,000 tons and may have an exposure in 2009 of between 40,000 and 60,000 tons. Monongahela’s exposure is expected to be approximately 50% and 60% of Allegheny’s total exposure in 2008 and 2009, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Allegheny continues to evaluate and implement options for compliance; it completed the elimination of a partial Scrubber bypass at its Pleasants generation facility in December 2007, and current plans include the installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generation facilities by 2009.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Maryland operations and is working with the MDE on the R. Paul Smith-specific regulations. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions, and Maryland issued draft regulations to implement RGGI requirements in December 2007, subject to the review of the Maryland Legislative Review Committee. Allegheny is also assessing the reach and impact of those regulations on its Maryland operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 will occur during the first quarter of 2008.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Other Litigation

Nevada Power Contracts. On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with the 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, Nevada 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 the 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 September 25, 2007, the Supreme Court announced that it would hear the case on appeal. Briefing by all parties was completed by February 6, 2008 and oral argument before the Supreme Court was held on February 19, 2008.

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

Sierra/Nevada. On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in United States District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). Sierra/Nevada has alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada has asserted claims against AE and AE Supply for: (a) wrongful hiring and supervision; (b) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (c) conspiracy and (d) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada’s most recent complaint seeks damages in excess of $850 million, including compensatory damages, punitive damages, attorneys’ fees and treble damages. AE and AE Supply have filed motions to dismiss the lawsuit, which have been pending since 2003. The lawsuit had been stayed since 2005, pending the outcome of certain state court proceedings in which Sierra/Nevada was seeking to reverse the Nevada PUC’s disallowance of expenses. On July 20, 2006, the Nevada Supreme Court reversed the Nevada PUC’s disallowance of the $180 million in deferred energy expenses, which formed the basis of the plaintiffs’ claims. An announcement was made on March 23, 2007 that the Nevada PUC approved two settlements relating to the requested disallowance, and those

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

state court proceedings that were the focus of the prior stay have been closed. A scheduling order was then entered in this lawsuit that, among other things, sets a trial date of July 8, 2008. The parties are engaged in discovery and awaiting a ruling from the District Court on the previously filed motions to dismiss.

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

Claim 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 demand to AE Supply in the amount of approximately $190 million was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit to resolve all outstanding claims of alleged price manipulation in the California energy markets during 2000 and 2001. No complaint has been filed against Allegheny. Allegheny believes that all issues in connection with AE Supply sales to CDWR were resolved by a settlement in 2003 and otherwise believes that the California parties’ demand is without merit.

Allegheny intends to vigorously defend against this claim but cannot predict its outcome.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On January 25, 2008, AE and AE Supply entered into a settlement agreement with Merrill Lynch. Under the settlement agreement, Merrill Lynch will convey to AE its minority equity interest in AE Supply, and AE will make a cash payment of $50 million to Merrill Lynch. In addition, the litigation will be dismissed and the parties will release their respective claims in the litigation.

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. Allegheny is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.

Construction and Capital Program

Allegheny estimates that its capital expenditures will approximate $1,350 million in 2008 and $1,175 million in 2009, including amounts relating to significant multiple year environmental control and transmission expansion projects. Capital expenditure levels in 2008 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. See “Environmental Matters and Litigation—Clean Air Act Matters,” above.

Leases

Allegheny has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles, computer equipment, communication lines and buildings.

Total capital and operating lease rent payments of $18.5 million, $17.8 million and $22.5 million were recorded as rent expense in 2007, 2006 and 2005, respectively. Allegheny’s estimated future minimum lease payments for capital and operating leases, with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are:


(In millions)	2008		2009		2010		2011		2012		Thereafter		Total		Less: amount representing interest and fees		Present value of net minimum capital lease payments
Capital Leases	$	11.7	$	9.5	$	8.8	$	6.8	$	4.3	$	6.5	$	47.6	$	17.6	$	30.0
Operating Leases	$	3.5	$	3.4	$	3.3	$	3.3	$	3.5	$	12.7	$	29.7	$	—	$	—

The carrying amount of assets recorded under capitalized lease agreements included in “Property, plant and equipment, net” at December 31, consisted of the following:


(In millions)	2007		2006
Equipment	$	47.0	$	32.9
Building		0.2		0.3

Property held under capital leases	$	47.2	$	33.2

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PURPA

The Energy Policy Act of 2005 (the “Energy Policy Act”) amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contractual obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission. This amendment has no impact on Allegheny’s current long-term power purchase agreements under PURPA.

Allegheny’s regulated utilities are committed to purchasing the electrical output from 479 MWs of qualifying PURPA capacity. PURPA capacity and energy purchases in 2007, 2006 and 2005 were $224.5 million, $203.8 million and $209.0 million, respectively, before amortization of West Penn’s adverse power purchase commitment. The average cost of these power purchases was approximately 5.9, 5.4 and 5.3 cents per kilowatt-hour (“kWh”) in 2007, 2006 and 2005, respectively.

The table below reflects Allegheny’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2007. The commitments were calculated based on expected PURPA purchased power prices at December 31, 2007, without giving effect to possible price changes that could occur as a result of any future CO₂ emissions regulation or legislation. Actual values can vary substantially depending upon future conditions.


(In millions)	kWhs	Amount
2008	3,862.6	$	238.6
2009	3,855.6		244.5
2010	3,920.8		255.5
2011	4,006.3		265.9
2012	3,947.6		272.6
Thereafter	58,243.3		4,142.4

Total	77,836.2	$	5,419.5

Fuel Purchase and Transportation Commitments

Allegheny has entered into various long-term commitments for the procurement and transportation of fuel (primarily coal and lime) to supply its generation facilities. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Allegheny’s fuel expense was $930.8 million, $842.7 million and $759.1 million in 2007, 2006 and 2005, respectively, of which, $802.9 million, $764.3 million and $664.1 million, respectively, related to coal and lime expense. In 2007, Allegheny purchased approximately 35% of its coal from one vendor. Total estimated long-term fuel purchase and transportation commitments (primarily coal and lime) at December 31, 2007 were as follows:


(In millions)	Total
2008	$	716.1
2009		536.5
2010		473.8
2011		482.0
2012		423.6
Thereafter		2,608.6

Total	$	5,240.6

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Uncertain Tax Positions

At December 31, 2007, Allegheny had certain FIN 48 liabilities recorded related to uncertain tax positions. Estimated settlement of these liabilities is as follows:


(In millions)	Amount
2008	$	14.5
2009		6.6
2010		16.4
2011		5.6
2012		41.6
Thereafter		—

Total	$	84.7

Other Purchase Obligations

Unless extended by AE, the Professional Service Agreement with Electronic Data Systems Corporation and EDS Information Services, LLC related to certain of Allegheny’s technology functions will expire on December 31, 2012. Expected cash payments relating to the Professional Service Agreement are as follows:


(In millions)	2008		2009		2010		2011		2012		Thereafter		Total
Other purchase obligations	$	27.6	$	26.9	$	25.8	$	24.0	$	23.2	$	—	$	127.5

NOTE 28: SUBSEQUENT EVENT

As discussed in Note 27, “Commitments and Contingencies,” on January 25, 2008 Allegheny and Merrill Lynch entered into a settlement agreement that resolved litigation between the two parties. The case related to a dispute regarding Allegheny’s purchase of Merrill’s Global Energy Marketing trading business in 2001. As a result of this settlement, Allegheny reversed its previously recorded accrued interest liability of $54.7 million through a credit to interest expense during the fourth quarter of 2007.

Under the settlement agreement, Merrill Lynch will convey to AE its minority equity interest in AE Supply, and AE will make a cash payment of $50 million to Merrill Lynch. In addition, the litigation will be dismissed and the parties will release their respective claims in the litigation.

168

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

of Allegheny Energy, Inc.

In our opinion, the accompanying consolidated balance sheets and the consolidated statements of capitalization and the related consolidated statements of income, stockholders’ equity and comprehensive income and cash flows present fairly, in all material respects, the financial position of Allegheny Energy, Inc. and its subsidiaries (the “Company”) at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and financial statement schedules and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 6, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007. As discussed in Note 17, the Company changed the manner in which it presents pension and other postretirement benefits as of December 31, 2006. As discussed in Note 21, the Company changed the manner in which it accounts for conditional asset retirement obligations as of December 31, 2005.

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

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

PricewaterhouseCoopers LLP

February 27, 2008

169

S-1

SCHEDULE I

ALLEGHENY ENERGY, INC. (Parent Company)

Condensed Financial Statements


Statements of Income:
	Year ended December 31,
(In thousands)	2007			2006			2005
Operating revenues	$	—		$	—		$	—
Operating expenses		5,783			6,839			5,241

Operating loss		(5,783	)		(6,839	)		(5,241	)

Equity in earnings of subsidiaries		384,927			348,314			200,319
Other income and expenses, net		4,364			3,072			1,743
Interest expense (benefit)		(48,571	)		23,131			132,148

Income before income taxes		432,079			321,416			64,673
Income tax expense		19,865			2,095			1,608

Net income	$	412,214		$	319,321		$	63,065


Statements of Cash Flows:
	Year ended December 31,
(In thousands)	2007			2006			2005
Net cash provided by operating activities	$	97,075		$	137,951		$	155,442
Cash flows from investing activities:
Notes receivable from subsidiaries		(72,253	)		4,895			887
Contributions to subsidiaries		(17,125	)		(13,911	)		—
Return of capital from subsidiaries		—			—			88,000

Net cash provided by (used in) investing activities		(89,378	)		(9,016	)		88,887

Cash flows from financing activities:
Issuance of long-term debt, net of $1.1 million and $9.1 million in debt issuance costs, respectively		—			217,997			459,861
Retirement of long-term debt		—			(418,071	)		(670,000	)
Exercise of stock options		26,447			24,691			2,941
Cash dividends paid on common stock		(25,003	)		—			—

Net cash provided by (used in) financing activities		1,444			(175,383	)		(207,198	)

Net increase (decrease) in cash and cash equivalents		9,141			(46,448	)		37,131
Cash and cash equivalents at beginning of period		9,631			56,079			18,948

Cash and cash equivalents at end of period	$	18,772		$	9,631		$	56,079

Cash dividends received from consolidated subsidiaries	$	67,564		$	147,702		$	244,491



Balance Sheets:
	As of December 31,
(In thousands)	2007			2006
ASSETS
Current assets	$	107,574		$	54,492
Investments and other assets		2,488,099			2,089,492
Deferred charges		4,514			8,302

Total assets	$	2,600,187		$	2,152,286

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	92,524		$	71,389
Deferred credits and other liabilities		(27,688	)		502
Stockholders’ equity		2,535,351			2,080,395

Total liabilities and stockholders’ equity	$	2,600,187		$	2,152,286

See accompanying Notes to Condensed Financial Statements.

170

ALLEGHENY ENERGY, INC. (Parent Company)

NOTES TO CONDENSED FINANCIAL STATEMENTS

NOTE 1: BASIS OF PRESENTATION

Pursuant to rules and regulations of the Securities and Exchange Commission (SEC), the unconsolidated condensed financial statements of Allegheny Energy, Inc. (AE) do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Form 10-K.

AE has accounted for the earnings of its subsidiaries under the equity method in these unconsolidated condensed financial statements. Stockholders’ equity reflects accumulated other comprehensive loss of $40.2 million and $107.2 million at December 31, 2007 and 2006, respectively.

171

S-2

SCHEDULE II

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

For Years Ended December 31, 2007, 2006 and 2005


			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses (a)		Charged to Other Accounts (b)		Deductions (c)		Balance at End of Period
Allowance for uncollectible accounts:
Year Ended 12/31/07	$	14,590,972	$	17,324,986	$	3,571,084	$	21,234,983	$	14,252,059
Year Ended 12/31/06	$	16,778,240	$	14,992,661	$	4,011,475	$	21,191,404	$	14,590,972
Year Ended 12/31/05	$	19,854,168	$	14,386,601	$	5,018,081	$	22,480,610	$	16,778,240

(a)	Amount charged to bad debt expense.

(b)	Collection of accounts previously written off.

(c)	Uncollectible accounts written off during the year

172

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Effective February 27, 2008, AE dismissed PricewaterhouseCoopers LLP (“PwC”) as its independent registered public accounting firm. AE previously announced that the Audit Committee of AE’s Board of Directors (the “Audit Committee”) had determined on October 3, 2007, that PwC would be dismissed as AE’s independent registered public accounting firm effective upon PwC’s completion of its procedures regarding the financial statements of AE for the year ended December 31, 2007 and this Form 10-K in which such financial statements are included. PwC completed its procedures on February 27, 2008, coincident with the filing of this Form 10-K.

PwC’s reports on the financial statements of AE as of and for the years ended December 31, 2007 and 2006 did not contain any adverse opinion or a disclaimer of opinion, nor were such reports qualified or modified as to uncertainty, audit scope or accounting principles. During the years ended December 31, 2007 and 2006, and through February 27, 2008, (1) there were no disagreements with PwC on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which, if not resolved to the satisfaction of PwC, would have caused PwC to make reference thereto in connection with its reports on the financial statements of AE for such years, and (2) there were no “reportable events” as defined in Item 304(a)(1)(v) of Regulation S-K.

Also as previously announced, on October 3, 2007, the Audit Committee selected Deloitte & Touche LLP (“Deloitte”) to serve as AE’s independent registered public accounting firm for the year ending December 31, 2008. This appointment followed a proposal and selection process conducted by the Audit Committee. During the years ended December 31, 2007 and 2006, and through February 27, 2008, AE did not consult with Deloitte regarding any of the matters or events set forth in Item 304(a)(2)(i) or (ii) of Regulation S-K.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures. AE carried out an evaluation, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, of the effectiveness of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, as of December 31, 2007 (the “Evaluation Date”). These disclosure controls and procedures are designed to provide reasonable assurance to the registrant’s management and board of directors that information required to be disclosed by us in the reports filed under the Exchange Act is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, the principal executive officer and principal financial officer of AE have concluded that its disclosure controls and procedures as of December 31, 2007 were effective, at the reasonable assurance level, to ensure that (a) material information relating to AE is accumulated and made known to its management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure and (b) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

As an accelerated filer, AE is required to meet the requirements under Section 404 of the Sarbanes-Oxley Act of 2002. See “Management’s Report on Internal Control Over Financial Reporting,” below.

Management’s Report on Internal Control Over Financial Reporting. AE’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. AE’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. AE’s internal control over financial reporting includes those policies and procedures that:

(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of AE’s assets;

173

(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that AE’s receipts and expenditures are being made only in accordance with authorizations of its management and directors; and

(3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the AE’s assets that could have a material effect on the financial statements.

AE’s management assessed the effectiveness of AE’s internal control over financial reporting as of December 31, 2007. In making this assessment, AE’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control-Integrated Framework.”

Based on this assessment, management concluded that, as of December 31, 2007, AE’s internal control over financial reporting is effective based on those criteria.

The effectiveness of AE’s internal control over financial reporting as of December 31, 2007 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report, which appears herein.

Changes in Internal Control over Financial Reporting: There have been no changes in AE’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) that have materially affected, or are reasonable likely to materially affect, internal control over financial reporting during the three months ended December 31, 2007.

ITEM 9B. OTHER INFORMATION

Not Applicable.

174

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS

The information required by this Item (other than the information set forth below) is contained in AE’s Proxy Statement for its 2008 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors,” “Executive Compensation” and “Security Ownership—Section 16(a) Beneficial Ownership Reporting Compliance,” and is incorporated herein by reference.

Executive Officers

The information required by this Item with respect to the registrant’s executive officers is contained in Item 1 of Part I of this Form 10-K under the section “Executive Officers.”

Code of Business Conduct and Ethics

Allegheny maintains a Code of Business Conduct and Ethics for its directors, officers and employees in order to promote honest and ethical conduct and compliance with the laws and regulations to which Allegheny is subject. All directors, officers and employees of Allegheny are expected to be familiar with the Code of Business Conduct and Ethics and to adhere to its principles and procedures.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is contained in AE’s Proxy Statement for the 2008 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors” and “Executive Compensation” and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

175

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



(a)(1)(2)		The financial statements and financial statement schedules filed as part of this Report are set forth under Item 8. Reference is made to the index on page 180.

176

SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


ALLEGHENY ENERGY, INC.

By:		/s/ Paul J. Evanson
		(Paul J. Evanson, Chairman, President and Chief Executive Officer)

Date: February 27, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated.


	Signature	Title	Date
(i)	Principal Executive Officer:

	/s/ Paul J. Evanson (Paul J. Evanson)	Chairman and President, Chief Executive Officer	February 27, 2008

(ii)	Principal Financial Officer:

	/s/ Philip L. Goulding (Philip L. Goulding)	Senior Vice President and Chief Financial Officer	February 27, 2008

(iii)	Principal Accounting Officer:

	/s/ William F. Wahl, III (William F. Wahl, III)	Vice President, Controller and Chief Accounting Officer	February 27, 2008

(iv)	Directors:

	/s/ H. Furlong Baldwin (H. Furlong Baldwin)	/s/ Ted J. Kleisner (Ted J. Kleisner)

	/s/ Eleanor Baum (Eleanor Baum)	/s/ Christopher D. Pappas (Christopher D. Pappas)

	/s/ Paul J. Evanson (Paul J. Evanson)	/s/ Steven H. Rice (Steven H. Rice)	February 27, 2008

	/s/ Cyrus F. Freidheim, Jr. (Cyrus F. Freidheim, Jr.)	/s/ Gunnar E. Sarsten (Gunnar E. Sarsten)

	/s/ Julia L. Johnson (Julia L. Johnson)	/s/ Michael H. Sutton (Michael H. Sutton)

177

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in Registration Statements on Form S-3 (Nos. 33-36716, 33-57027, 33-49791, 333-41638, 333-49086, 333-56786, 333-82176, 333-121083 and 333-123697) and on Form S-8 (Nos. 333-65657, 333-31610, 33-40432, 333-113660, 333-117117 and 333-119397) of Allegheny Energy, Inc. of our report dated February 27, 2008 relating to the financial statements, financial statement schedules and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 27, 2008

178

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Energy, Inc., a Maryland corporation, do hereby constitute and appoint PAUL J. EVANSON and PHILIP L. GOULDING, and each of them, a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2007, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratifies and confirms all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

Dated: February 27, 2008



/s/ H. Furlong Baldwin (H. Furlong Baldwin)				/s/ Ted J. Kleisner (Ted J. Kleisner)

/s/ Eleanor Baum (Eleanor Baum)				/s/ Christopher D. Pappas (Christopher D. Pappas)

/s/ Paul J. Evanson (Paul J. Evanson)				/s/ Steven H. Rice (Steven H. Rice)

/s/ Cyrus F. Freidheim, Jr. (Cyrus F. Freidheim, Jr.)				/s/ Gunnar E. Sarsten (Gunnar E. Sarsten)

/s/ Julia L. Johnson (Julia L. Johnson)				/s/ Michael H. Sutton (Michael H. Sutton)

179

EXHIBIT INDEX

(Rule 601(a))


	Documents	Incorporation by Reference
3.1	Charter of the Company, as amended, September 16, 1997	Form 10-K of the Company (1-267), December 31, 1997, exh. 3.1
3.1a	Articles Supplementary, dated July 15, 1999 and filed July 20, 1999	Form 8-K of the Company (1-267), July 20, 1999, exh. 3.1
3.1b	Articles of Amendment, dated March 18, 2003	Form 10-K of the Company (1-267), December 31, 2002, exh. 3.1c
3.1c	Articles Supplementary to Articles of Incorporation, dated July 19, 2004	Form 10-Q of the Company (1-267), June 30, 2004, exh. 3.1
3.2	Amended & Restated By-laws of the Company, as adopted December 6, 2007	Form 8-K of the Company (1-267), filed December 12, 2007, exh. 3.1
10.1	Amended and Restated Revised Plan for Deferral of Compensation of Directors	Form 8-K of the Company (1-267), filed October 6, 2006, exh. 99.1
10.2	Amended and Restated Revised Plan for Deferral of Compensation of Directors	Form 10-Q of the Company (1-267), filed November 7, 2007, exh. 10.4
10.3	Allegheny Energy Amended and Restated Supplemental Executive Retirement Plan	Form 10-K of the Company (1-267), December 31, 2005, exh. 10.4
10.4	Allegheny Energy Amended and Restated Supplemental Executive Retirement Plan	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.8
10.5	Executive Life Insurance Program and Collateral Assignment Agreement	Form 10-K of the Company (1-267), December 31, 1994, exh. 10.5
10.6	Restricted Stock Plan for Outside Directors	Form 10-K of the Company (1-267), December 31, 1998, exh. 10.7
10.7	Amended and Restated Restricted Stock Plan for Outside Directors	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.3
10.8	Deferred Stock Unit Plan for Outside Directors	Form 10-K of the Company (1-267), December 31, 1997, exh. 10.8
10.9	Allegheny Energy, Inc. 2004 Non-Employee Director Stock Plan	Schedule 14A Definitive Proxy Statement of the Company (1-267), filed April 4, 2004, Annex A
10.10	Allegheny Energy, Inc. Annual Incentive Plan	Schedule 14A Definitive Proxy Statement of the Company (1-267), filed April 4, 2004, Annex B
10.11	Allegheny Energy, Inc. Amended and Restated Annual Incentive Plan	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.7
10.12	Form of Stock Option Agreement	Form 10-K of the Company (1-267), December 31, 2004 exh. 10.12
10.13	Stock Unit Plan	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.13
10.14	Amended and Restated Stock Unit Plan	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.7
10.15	Form of Stock Unit Agreement	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.14
10.16	Allegheny Energy, Inc. 1998 Long-Term Incentive Plan revised as of January 1, 2004	Form 10-Q of the Company (1-267), March 31, 2004, exh. 10.1
10.17	Allegheny Energy, Inc. 1998 Long-Term Incentive Plan amended and restated as of January 1, 2008	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.5
10.18	Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-267), December 31, 2002, exh. 10.13
10.19	Employment Contract of Vice President	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.15

180

EXHIBIT INDEX

(Rule 601(a))

181


	Documents	Incorporation by Reference
10.20	Amendment to Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.17
10.21	Employment Agreement of Vice President, Human Resources	Form 8-K of the Company (1-267), filed January 6, 2006, exh. 10.1
10.22	Amendment to Employment Contract of Senior Vice President and Chief Financial Officer	Form 8-K of the Company (1-267), filed July 19, 2006, exh. 10.1
10.23	Amendment to Employment Contract of Chief Operating Officer—Generation	Form 8-K of the Company (1-267), filed July 19, 2006, exh. 10.2
10.24	Change in Control Agreement, dated July 7, 2006, between Allegheny Energy Service Corporation and Vice President	Form 8-K of the Company (1-267), filed July 19, 2006, exh. 10.3
10.25	Change in Control Agreement, dated October 18, 2006, between Allegheny Energy Service Corporation and Vice President and General Counsel	Form 8-K of the Company (1-267), filed October 24, 2006, exh. 10.1
10.26	Letter Agreement, dated October 18, 2006, between Allegheny Energy Service Corporation and Vice President and General Counsel	Form 8-K of the Company (1-267), filed October 24, 2006, exh. 10.2
10.27	Letter Agreement, dated August 3, 2006, between Allegheny Energy Service Corporation and Vice President	Form 10-Q of the Company (1-267), June 30, 2006, exh. 10.3
10.28	Amended and Restated Non-Employee Director Stock Plan	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.2
10.29	Amended and Restated Nonqualified Deferred Compensation Plan	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.9
10.30	Amendment to Employment Agreement of Senior Vice President and Chief Financial Officer	Form 10-Q of the Company (1-267), November 7, 2007, 10.10
10.31	Amendment to Employment Agreement of Vice President	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.11
10.32	Amendment to Change in Control Agreement of Vice President and General Counsel	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.12
10.33	Amendment to Change in Control Agreement of Vice President	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.13
10.34	Amendment to Change in Control Agreement of Vice President and Controller	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.14
10.35	Amendment to Severance Agreement of Vice President and General Counsel	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.15
10.36	Amendment to Severance Agreement of Vice President	Form 10-Q of the Company (1-267), November 7, 2007, exh. 10.16
10.37	$967,000,000 Credit Agreement, dated as of May 2, 2006, among Allegheny Energy Supply Company, LLC, certain banks, financial institutions and other institutional lenders, Citigroup Global Markets Inc., as Joint Lead Arranger and Joint Book Runner, Banc of America Securities LLC, as Joint Lead Arranger and Joint Book Runner, Bank of America, N.A., as Co-Syndication Agent, The Bank of Nova Scotia, as Joint Lead Arranger, Joint Book Runner and Co-Syndication Agent, and Citicorp USA, Inc., as Administrative Agent.	Form 8-K of the Company (1-267), filed May 8, 2006, exh. 10.1
10.38	Security Agreement dated as of May 2, 2006, by and among Allegheny Energy Supply Company, LLC, Citicorp USA, Inc., as Administrative Agent and Citibank, N.A., as Collateral Agent.	Form 8-K of the Company (1-267), filed May 8, 2006, exh. 10.2

EXHIBIT INDEX

(Rule 601(a))


	Documents	Incorporation by Reference
10.39	Amendment No. 1, dated September 11, 2007, to Credit Agreement, dated as of May 2, 2006, among Allegheny Energy Supply Company, LLC, certain banks, financial institutions and other institutional lenders and Citicorp USA, Inc., as Administrative Agent.	Form 8-K of the Company (1-267), filed September 17, 2007, exh. 10.1
10.40	$579 million Credit Agreement, dated as of May 22, 2006, by and among Allegheny Energy, Inc., Allegheny Energy Supply Company, LLC, certain banks, financial institutions and other institutional lenders, Citigroup Global Markets Inc., as Joint Lead Arranger and Joint Book Runner, Credit Suisse, Cayman Islands Branch, as Joint Lead Arranger, Joint Book Runner and Syndication Agent and Citicorp North America, Inc., as administrative agent.	Form 8-K of the Company (1-267), filed May 25, 2006, exh. 10.1
10.41	Amendment No. 1, dated September 11, 2007, to Credit Agreement, dated as of May 22, 2006, among Allegheny Energy, Inc., Allegheny Energy Supply Company, LLC, certain banks, financial institutions and other institutional lenders and Citicorp North America, Inc., as Administrative Agent.	Form 8-K of the Company (1-267), filed September 17, 2007, exh. 10.2
10.42	EPC Agreement No. 1001 dated July 12, 2006, between Allegheny Energy Supply Company, LLC and The Babcock & Wilcox Company covering Flue Gas Desulfurization Project at Hatfield’s Ferry Units 1, 2 and 3	Form 10-Q of the Company (1-267), filed August 8, 2006, exh. 10.1
10.43	EPC Agreement No. 1002 dated July 13, 2006, between Allegheny Energy Supply Company, LLC and Washington Group International covering Balance of Plant for Flue Gas Desulfurization Project at Hatfield’s Ferry Units 1, 2 and 3	Form 10-Q of the Company (1-267), filed August 8, 2006, exh. 10.2
10.44*	Alliance Agreement for Engineering, Construction and Project Management for the Trans-Allegheny Interstate Line Project, dated February 28, 2007, by and between Trans-Allegheny Interstate Line Company and Kenny Construction Company	Form 10-Q of the Company (1-267), filed May 8, 2007, exh. 10.1
10.45*	Limited Liability Agreement of Potomac-Appalachian Transmission Highline, LLC, dated as of September 1, 2007	Form 10-Q of the Company (1-267), filed November 7, 2007, exh. 10.1
10.46	Subsidiaries’ Indentures described below
12	Computation of ratio of earnings to fixed charges	Filed herewith
21	Subsidiaries of AE:

	Name of Company	State of Organization
	Allegheny Energy Service Corporation—100%	Maryland
	Allegheny Ventures, Inc.—100%	Delaware
	Monongahela Power Company—100%	Ohio
	The Potomac Edison Company—100%	Maryland and Virginia
	West Penn Power Company—100%	Pennsylvania
	Allegheny Energy Supply Company, LLC—98.025%	Delaware
	Allegheny Energy Supply Hunlock Creek, LLC—100%	Delaware
	Allegheny Energy Transmission, LLC—100%	Delaware
	Green Valley Hydro, LLC—100%	Virginia
	Ohio Valley Electric Corporation—3.50%	Ohio
23	Consent of Independent Registered Public Accounting Firm	See page 178 herein.

182

EXHIBIT INDEX

(Rule 601(a))


	Documents	Incorporation by Reference
24	Powers of Attorney	See page 179 herein.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith

*	Confidential treatment has been requested from the commission for portions of this document.

183

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Allegheny Energy (AYE) Inactive 10-K2007 FY Annual report

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