10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) of the SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006

OR

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

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

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

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

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

Allegheny Energy, Inc.	¨
Monongahela Power Company	¨
Allegheny Generating Company	¨

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

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

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

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

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

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

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

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

	Aggregate market value of voting and non-voting common equity held by nonaffiliates of the registrants at June 30, 2006	Number of shares of common stock of the registrants outstanding at February 20, 2007
Allegheny Energy, Inc.	$6,095,989,273	164,445,354 ($1.25 par value)
Monongahela Power Company	None (a)	5,891,000 ($50 par value)
Allegheny Generating Company	None (b)	1,000 ($1.00 par value)

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

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

Documents Incorporated by Reference

Portions of the Allegheny Energy, Inc. definitive Proxy Statement for its 2007 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	Collectively, Monongahela, Potomac Edison and West Penn, which do business as Allegheny Power
Green Valley Hydro	Green Valley Hydro, LLC, a subsidiary of AE
Monongahela	Monongahela Power Company, a regulated subsidiary of AE
Potomac Edison	The Potomac Edison Company, a regulated subsidiary of AE
Registrants	Collectively, AE, Monongahela and AGC
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:

BTU	British Thermal Unit
CDD	Cooling Degree-Days
CDWR	California Department of Water Resources
Clean Air Act	Clean Air Act of 1970
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
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
RTO	Regional Transmission Organization
SEC	Securities and Exchange Commission
SOS	Standard Offer Service
T&D	Transmission and distribution
Virginia SCC	Virginia State Corporate Commission
West Virginia PSC	Public Service Commission of West Virginia

CONTENTS

Item 1.	Business	6
	Overview	6
	Special Note Regarding Forward-Looking Statements	14
	Allegheny’s Sales And Revenues	16
	Capital Expenditures	17
	Electric Facilities	18
	Fuel, Power And Resource Supply	23
	Regulatory Framework Affecting Allegheny	26
	Federal Regulation And Rate Matters	26
	Environmental Matters	36
	Employees	41
	Executive Officers Of The Registrants	42
Item 1A.	Risk Factors	43
Item 2.	Properties	53
Item 3.	Legal Proceedings	54
Item 4.	Submission Of Matters To A Vote Of Security Holders	56
Item 5.	Market For The Registrants’ Common Equity And Related Stockholder Matters	57
Item 6.	Selected Financial Data	59
Item 7.	Management’s Discussion And Analysis Of Financial Condition And Results Of Operations	62
Item 7A.	Quantitative And Qualitative Disclosures About Market Risk	122
Item 8.	Financial Statements And Supplementary Data	125
Item 9.	Changes In And Disagreements With Accountants On Accounting And Financial Disclosure	243
Item 9A.	Controls And Procedures	243
Item 9B.	Other Information	244
Item 10.	Directors And Executive Officers Of The Registrants	245
Item 11.	Executive Compensation	245
Item 12.	Security Ownership Of Certain Beneficial Owners And Management And Related Stockholder Matters	245
Item 13.	Certain Relationships And Related Transactions	245
Item 14.	Principal Accountant Fees And Services	245
Item 15.	Exhibits And Financial Statement Schedules	246
Supplemental Information To Be Furnished With Reports Filed Pursuant To Section 15(d) Of The Exchange Act By Registrants Which Have Not Registered Securities Pursuant To Section 12 Of The Exchange Act		246
Signatures		247

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

PART I

ITEM 1.    BUSINESS

OVERVIEW

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

Allegheny has two business segments:

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

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

The Delivery and Services Segment

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

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

• Monongahela was incorporated in Ohio in 1924. It conducts an electric T&D business that serves approximately 375,000 customers in northern West Virginia in a service area of approximately 12,400 square miles with a population of approximately 776,000. Monongahela’s Delivery and Services segment had operating revenues of $674.9 million and sold 10,351 million kWhs of electricity to retail customers in 2006. Monongahela also owns generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Asset Sales” below.

• 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 466,600 customers in a service area of about 7,300 square miles with a population of approximately 1.02 million. Potomac Edison had total operating revenues of $856.0 million and sold 12,902 million kWhs of electricity to retail customers in 2006.

• 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 707,000

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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 $1,210.5 million and sold 19,926 million kWhs of electricity to retail customers in 2006.

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

• TrAIL Company was incorporated in Maryland and Virginia in 2006 following PJM’s approval of a regional transmission expansion plan designed to maintain the reliability of the transmission grid in the Mid-Atlantic region. The transmission expansion plan includes 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.

• 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 $6.6 million in 2006.

During 2006, the Delivery and Services segment had operating revenues of $2,717.7 million and net income of $179.4 million. As of December 31, 2006, the Delivery and Services segment held $4.1 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 9, “Business Segments,” to the Consolidated Financial Statements.

The Generation and Marketing Segment

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

• AE Supply is a Delaware limited liability company formed in 1999. AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities. As of December 31, 2006, AE Supply owned or contractually controlled approximately 7,535 MWs of generation capacity. Effective as of January 1, 2007, AE Supply and Monongahela completed an intra-company transfer of assets (the “Asset Swap”) that realigned generation ownership and contractual arrangements within the Allegheny system. As discussed in greater detail under the heading “Electric Facilities” below, the purpose of the Asset Swap was to enable the securitization financing of a majority of the costs associated with the installation of flue gas desulfurization units and related pollution control equipment (“Scrubbers”) at Monongahela’s Fort Martin generation facility. Immediately following the Asset Swap, AE Supply owned or contractually controlled 6,876 MWs of generation capacity. See “Electric Facilities” below.

AE Supply markets its electric generation capacity to various customers and markets. Currently, the majority of the Generation and Marketing segment’s normal operating capacity is committed to supplying the PLR and other obligations of the Distribution Companies. AE Supply had total operating revenues of $1,492.9 million in 2006.

• Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment. As of December 31, 2006, Monongahela owned or contractually controlled 2,135 MWs of generation capacity. Immediately following the Asset Swap, Monongahela owned or contractually controlled 2,794 MWs of generation capacity. See “Electric Facilities” below.

Monongahela’s generation capacity supplies Monongahela’s Delivery and Services segment. In addition, in connection with the Asset Swap, AE Supply assigned to Monongahela its obligation to

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supply generation to meet Potomac Edison’s load obligations in West Virginia. Monongahela’s Generation and Marketing segment had operating revenues of $401.1 million in 2006.

• AGC was incorporated in Virginia in 1981. As of December 31, 2006, AGC was owned approximately 77% by AE Supply and approximately 23% by Monongahela. As a result of the Asset Swap, AGC currently 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 1,035 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC had total operating revenues of $65.3 million in 2006. See “Electric Facilities” below.

AE Supply is contractually obligated to provide Potomac Edison and West Penn with the power that they need to meet a majority of their PLR obligations. Monongahela is contractually obligated to provide Potomac Edison with the power that it needs to meet its load obligations in West Virginia. 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 obligations under these contracts. See “The Distribution Companies’ Obligations and the PJM Market” and “Fuel, Power and Resource Supply” below.

During 2006, the Generation and Marketing segment had operating revenues of $1,834.4 million and net income of $139.9 million. As of December 31, 2006, the Generation and Marketing segment held $4.1 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 9, “Business Segments,” to the Consolidated Financial Statements.

Intersegment Services

AESC was incorporated in Maryland in 1963 as a service company for AE. AESC employs substantially all of the employees who provide services to AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures, TrAIL Company and their respective subsidiaries. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had 4,362 employees as of December 31, 2006.

The Distribution Companies’ Obligations and the PJM Market

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

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

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

• Potomac Edison. In Maryland, the transition period for residential customers ends on December 31, 2008. The transition period for commercial and industrial customers ended on December 31, 2004. The generation rates that Potomac Edison charges residential customers in Maryland are capped through

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December 31, 2008, while the T&D rate caps for all customers expired on December 31, 2004. A statewide settlement approved by the Maryland PSC in 2003 extends Potomac Edison’s obligation to provide residential “standard offer service” (“SOS”) at market prices beyond the expiration of the transition periods. In December 2006, Potomac Edison proposed a rate stabilization and transition plan for its residential customers in Maryland that is intended to gradually transition customers from capped generation rates to generation rates based on market prices, while at the same time preserving for customers the benefit of previous rate caps. In Virginia, the transition period ends on December 31, 2010. See “Regulatory Framework Affecting Allegheny” below.

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

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

Potomac Edison and West Penn have contracts with AE Supply under which AE Supply provides Potomac Edison and West Penn with the majority of the power necessary to meet their PLR obligations. Additionally, Potomac Edison has a contract with Monongahela under which Monongahela provides Potomac Edison with the power necessary to meet its load obligations in West Virginia.

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 the power that they generate into the PJM market and purchase from the PJM market the power necessary to meet their obligations to supply power.

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

As an RTO, PJM coordinates the movement of electricity over the transmission grid in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. In April 2002, the Distribution Companies transferred functional control over their transmission systems to PJM.

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

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:

• Pursuing 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

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a new, 240-mile extra high-voltage transmission line extending from southwestern Pennsylvania, through West Virginia to northern Virginia, 210 miles of which is to be located in the Distribution Companies’ PJM zone. The line is 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 the line that will be located in the Distribution Companies’ PJM zone. Additionally, FERC approved four incentive rate treatments, which are intended to promote the construction of transmission facilities, for the transmission line, and PJM has requested that the DOE designate the project as a National Interest Electric Transmission Corridor. Allegheny currently is in the process of siting the transmission line and will seek requisite permits and regulatory approvals. PJM is considering additional transmission expansion initiatives, a number of which, as contemplated, would pass through Allegheny’s service territory.

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

Among other initiatives, AE Supply and Monongahela are currently blending lower-sulfur Powder River Basin (“PRB”) coal at several generation facilities and are working to implement the financing and construction of Scrubbers at the Hatfield’s Ferry generation facility in Pennsylvania and the Fort Martin generation facility in West Virginia, as well as other pollution control projects at other facilities. In 2006, Monongahela and Potomac Edison received approval from the West Virginia PSC to finance the majority of the cost of constructing Scrubbers at the Fort Martin generation facility through the securitization of a customer charge. Effective January 1, 2007, Allegheny completed the Asset Swap, an intra-company transfer of assets that realigned generation ownership and contractual arrangements within the Allegheny system in a manner that will facilitate the proposed securitization and the construction of the Fort Martin Scrubbers. In July 2006, AE Supply entered into construction contracts in connection with its plans to install Scrubbers at its Hatfield’s Ferry generation facility. See “Environmental Matters” and “Electric Facilities” below.

• Managing Transition to Market-based Rates.  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 will gradually move generation rates in Pennsylvania closer to market prices.

Allegheny is actively working to effectively manage a similar transition in Maryland. In December 2006, Allegheny filed a proposal with the Maryland PSC to transition residential customers from capped generation rates to generation rates based on market prices beginning in 2007 and ending in 2010. Under the proposed plan, residential customers would pay a distribution surcharge beginning on March 31, 2007. The proposed plan, including the application of the surcharge, would 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 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. Following public hearings, Allegheny filed an alternate proposal that would, among other things, provide customers with the ability to opt out of the surcharge. See “Regulatory Framework Affecting Allegheny” and “Fuel, Power and Resource Supply” below.

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

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For example, in July 2006, Monongahela and Potomac Edison filed a request with the West Virginia PSC to increase their West Virginia retail rates by approximately $100 million annually. If approved by the West Virginia PSC, this proposal would result in, among other things, a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a fuel cost recovery clause, and a $26 million decrease in base rates. See “Risks Relating to Regulation” below.

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 municipal customer loads in Maryland.

• Maximizing Operational Efficiency.  Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation facilities (those that utilize steam pressure in excess of 3,200 pounds per square inch). In 2007, Allegheny expects to complete a program, which it began in 2005, of planned extended maintenance outages at each of its 10 supercritical generating units, targeted at improving availability at those units. The units for which this planned maintenance has been completed already demonstrate improved performance.

Allegheny also is seeking to optimize operations and maintenance costs for its other generation facilities, T&D assets and related corporate functions, to reduce costs and to pursue other productivity improvements necessary to build a high performance organization.

For example, 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 contracts in place for the delivery of approximately 96% of its expected coal needs for 2007. See “Fuel, Power and Resource Supply” below.

• Achieving and Maintaining High Customer Satisfaction.  Allegheny continues to see high levels of satisfaction among its customers. For example, a leading independent survey firm ranked Allegheny first in customer satisfaction for residential customers in the eastern United States, as well as first among commercial and industrial customers in the northeast.

• Substantially Reducing and Proactively Managing Debt.  Between December 1, 2003 and December 31, 2006, Allegheny restructured much of its debt and reduced debt by approximately $2.425 billion. This restructuring effort included debt reductions of approximately $918 million in 2005 and $517 million in 2006.

Through these restructuring efforts, Allegheny secured more favorable terms and conditions with respect to much of its debt, including reduced interest rates. The resulting reductions in interest expense, coupled with the reductions in debt and general improvements in Allegheny’s financial condition, have led to multiple upgrades in Allegheny’s credit ratings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Changes in Credit Ratings” below and Note 4, “Capitalization,” to the Consolidated Financial Statements.

• Improving Liquidity.  Allegheny has improved its liquidity through prudent cash management, opportunistic sales of non-core assets, cutting costs and expenses, extending debt maturities and other financing strategies. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” below and Note 4, “Capitalization,” to the Consolidated Financial Statements.

• Disposing of Non-Core Assets.  Allegheny has reoriented its business to focus on its core businesses and assets. With the 2006 sale of its Gleason generation facility for approximately $23 million and of a

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related receivable for approximately $27 million, Allegheny completed its initiative to sell its significant non-core assets. Since 2004, Allegheny has completed a number of other significant sales of non-core assets, including:

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

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

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

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

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

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Liquidity and Capital Resources—Asset Sales” below and Note 7, “Discontinued Operations,” to the Consolidated Financial Statements.

Management’s priorities for 2007 include continued focus on improving operations, managing the transition to market-based rates and expanding Allegheny’s transmission system.

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Where You Can Find More Information

AE, Monongahela and AGC file or furnish Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements (for AE) and other information with or to the SEC. You may read and copy any document that the Registrants file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. These SEC filings are also available to the public from the SEC’s website at http://www.sec.gov.

The Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements, statements of changes in beneficial ownership and other SEC filings, and any amendments to those reports, that AE, Monongahela and AGC file with or furnish to the SEC under the Exchange Act are made available free of charge on AE’s website at http://www.alleghenyenergy.com as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. Audited annual financial statements for AE Supply, Potomac Edison and West Penn, none of which are reporting companies under the Exchange Act, also will be available on AE’s website. AE’s website and the information contained therein are not incorporated into this report.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

• financing plans;

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

• PLR and power supply contracts;

• results of litigation;

• results of operations;

• internal controls and procedures;

• capital expenditures;

• status and condition of plants and equipment;

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

• work stoppages by Allegheny’s unionized employees;

• capacity purchase commitments; and

• regulatory matters.

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

• plant performance and unplanned outages;

• volatility and changes in the price of power, coal, natural gas and other energy-related commodities;

• general economic and business conditions;

• changes in access to capital markets;

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

• environmental regulations;

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

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

• changes in the weather and other natural phenomena;

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

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

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

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• the loss of any significant customers or suppliers;

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

• inflationary and interest rate trends;

• the implementation of Allegheny’s outsourcing initiative or new enterprise resource planning system;

• the possibility of adverse consequences arising from governmental audits of Allegheny’s tax returns;

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

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

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

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ALLEGHENY’S SALES AND REVENUES

Generation and Marketing

The Generation and Marketing segment had operating revenues of $1,834.4 million and $1,703.3 million in 2006 and 2005, 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 9, “Business Segments,” to the Consolidated Financial Statements.

Delivery and Services

The Delivery and Services segment sold 43,179 million and 48,275 million kWhs of electricity to retail customers in 2006 and 2005, respectively. The Delivery and Services segment had operating revenues of $2,717.7 million and $2,845.5 million in 2006 and 2005, respectively. These revenues included revenue from electric sales and unregulated services. There were $1,430.6 million and $1,510.9 million of intersegment sales and revenues between the Generation and Marketing segment and the Delivery and Services segment in 2006 and 2005, respectively, which were eliminated for Allegheny’s consolidated results of operations. The following table describes the segment’s revenues from electric sales:

Revenues (in millions):	2006		2005
Retail electric:
Generation	$	1,688.0	$	1,783.9
Transmission		160.3		176.0
Distribution		682.8		711.0
Subtotal retail	$	2,531.1	$	2,670.9
Transmission services and bulk power		150.7		115.9
Other affiliated and nonaffiliated energy services		35.9		58.7
Total Delivery and Services revenues	$	2,717.7	$	2,845.5

Allegheny had operating revenues from discontinued operations of $218.5 million for the year ended December 31, 2005. These revenues primarily related to its natural gas T&D business in West Virginia, which was sold on September 30, 2005. Allegheny did not have any operating revenues from discontinued operations in 2006. 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 9, “Business Segments,” to the Consolidated Financial Statements.

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CAPITAL EXPENDITURES

Actual capital expenditures for 2006 and projected capital expenditures for 2007 and 2008 are shown in the following tables. The projected amounts and timing are subject to continuing review and adjustment, and actual capital expenditures may vary from these estimates.

Allegheny Consolidated Totals

	Actual		Projected
(In millions)	2006		2007		2008
Transmission and distribution facilities:
Transmission expansion (a)		3		90		240
Other transmission and distribution facilities		197		215		215
Environmental:
Fort Martin Scrubbers (b)		9		150		260
Hatfield Scrubbers (c)		64		390		285
Other		65		75		75
Other generation facilities		71		90		40
Other capital expenditures		38		20		5
Total capital expenditures	$	447	$	1,030	$	1,120
AFUDC and capitalized interest included above	$	12	$	30	$	50

Monongahela

	Actual		Projected
(In millions)	2006		2007		2008
Transmission and distribution facilities	$	50	$	55	$	60
Environmental:
Fort Martin Scrubbers (b)		9		150		260
Other		14		20		15
Other generation facilities		15		30		20
Other capital expenditures		3		5		—
Total capital expenditures	$	91	$	260	$	355
AFUDC and capitalized interest included above	$	2	$	5	$	5

AGC

	Actual		Projected
(In millions)	2006		2007		2008
Generation facilities and other	$	4	$	7	$	5

(a) Includes construction of the TrAIL Project, which has a target completion date of 2011 and estimated total cost of approximately $820 million, as well as other transmission projects requested by PJM.

(b) Construction of Scrubbers at the Fort Martin generation facility is expected to be completed during 2009 at an estimated total cost of approximately $550 million, excluding AFUDC of $5 million. Allegheny plans to fund $450 million of these costs through securitization of an environmental control surcharge to be collected from the West Virginia customers of Monongahela and Potomac Edison.

(c) Construction of Scrubbers at the Hatfield’s Ferry generating facility is expected to be completed during 2009 at an estimated total cost of approximately $725 million, excluding capitalized interest of $60 million.

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ELECTRIC FACILITIES

Generation Capacity

All of Allegheny’s owned or controlled generation capacity is part of the Generation and Marketing segment. Allegheny’s owned and controlled capacity as of January 1, 2007 was 9,670 MWs, of which 7,604 MWs (78.6%) were coal-fired, 891 MWs (9.2%) were natural gas-fired, 1,093 MWs (11.3%) were pumped-storage and hydroelectric and 82 MWs (0.8%) were oil-fired. 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.

2006 Capacity Acquisitions and Dispositions

Allegheny Energy Supply Hunlock Creek, LLC (“AE Hunlock”), a wholly owned subsidiary of AE, previously owned a 50% interest in Hunlock Creek Energy Ventures (“HCEV”), which owned and operated a 48 MW coal-fired generation facility and a 44 MW gas-fired combustion turbine generation facility located on real property in Hunlock Township, Luzerne County, Pennsylvania. UGI Hunlock Development Company (“UGI”) also owned a 50% interest in HCEV. UGI held a put option under which it could require AE Supply to purchase UGI’s 50% interest in either the coal-fired facility, the gas-fired facility, or both for a 90-day period beginning on January 24, 2006. AE, AE Hunlock, and AE Supply entered into an agreement dated March 1, 2006 with UGI, UGI Development Company (“UGI Development”), and HCEV under which HCEV distributed the coal-fired facility to UGI and AE Hunlock purchased UGI’s 50% interest in HCEV, thereby effectively obtaining the gas-fired facility. HCEV was dissolved, and the assets and liabilities of HCEV, including the gas-fired facility, were contributed to AE Supply. See Note 24, “HCEV Partnership Interest,” to the Consolidated Financial Statements.

In December 2006, AE Supply sold its Gleason generation facility, a 526 MW natural gas-fired peaking facility located in Gleason, Tennessee. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Asset Sales” below and Note 7, “Discontinued Operations” to the Consolidated Financial Statements.

Asset Swap and Proposed Securitization

In May 2005, the state of West Virginia adopted legislation permitting securitization financing for the construction of certain types of pollution control equipment at facilities owned by public utilities that are regulated by the West Virginia PSC, subject to the satisfaction of certain criteria. Effective January 1, 2007, AE Supply and Monongahela completed the Asset Swap, an intra-company transfer of assets that realigned generation ownership and contractual arrangements within the Allegheny system in order to, among other things, allow Monongahela to own 100% of the Fort Martin generation facility in West Virginia and, along with Potomac Edison, to finance the construction of Scrubbers at its Fort Martin generation facility through the securitization of a charge that Monongahela and Potomac Edison will impose on their retail customers in West Virginia.

As a result of the Asset Swap, Monongahela also owns 100% of the Albright, Rivesville and Willow Island generation facilities in West Virginia. In addition, Monongahela is contractually entitled to a greater proportion of the generation (189 additional MWs) 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 in Pennsylvania, 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, for an additional 13 MWs and 176 MWs, respectively. AE Supply also has contractual rights to a greater amount of generation from OVEC. In addition, AE Supply assigned to Monongahela the obligation to supply the generation to meet Potomac Edison’s load obligations in West Virginia.

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In 2006, the West Virginia PSC issued an Order that, as amended, authorizes Allegheny to securitize up to $450 million in construction costs associated with the construction of Scrubbers at the Fort Martin generation facility, plus $16.5 million in upfront financing costs and certain other costs. See “Regulatory Framework Affecting Allegheny” below and Note 26, “Subsequent Event—Asset Swap,” to the Consolidated Financial Statements.

The table below shows the nominal maximum operational generation capacity owned or controlled by Allegheny, as of January 1, 2007. This generation is included in the Generation and Marketing segment. Effective January 1, 2007, Allegheny completed the Asset Swap, which realigned generation ownership and contractual arrangements within the Allegheny system and which is reflected in the table below.

Nominal Maximum Operational Generation Capacity (MW)

	Units	Project Total	Regulated	Unregulated	Service Commencement Dates (a)
Stations			Monongahela	AE Supply and Other
Coal Fired-Supercritical (Steam):
Harrison (Haywood, WV)	3	1,972	405	1,567	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) (b)	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) (c)	6	1,035	427	608	1985; 2001
Lake Lynn (Lake Lynn, PA) (d)	4	52		52	1926
Green Valley Hydro (e)	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) (f)	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		9,670	2,794	6,876

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

(b) This figure 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

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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.

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

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

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

(f) Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply (“Buchanan”), is part-owner of Buchanan Generation LLC (“Buchanan Generation”). CNX Gas Corporation and Buchanan have equal ownership interests in 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 amounts shown in this table are included in the Delivery and Services segment, except that, effective January 1, 2007, the PURPA generation for which Monongahela contracts is part of the Generation and Marketing segment.

PURPA Stations	Project Total	Monongahela	Potomac Edison	West Penn	PURPA Contract Termination Date
Coal-Fired: Steam
AES Warrior Run (Cumberland, MD) (a)	180		180		02/10/2030
AES Beaver Valley (Monaca, PA)	125			125	12/31/2016
Grant Town (Grant Town, WV)	80	80			05/28/2036
West Virginia University (Morgantown, WV)	50	50			04/17/2027
Hydro:
Hannibal Lock and Dam (New Martinsville, WV)	31	31			06/01/2034
Allegheny Lock and Dam 6 (Freeport, PA)	7			7	06/30/2034
Allegheny Lock and Dam 5 (Freeport, PA)	6			6	09/30/2034
Total PURPA Capacity	479	161	180	138

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

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

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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, 2006:

	Underground	Above- Ground	Total Miles	Total Miles Consisting of 500-Kilovolt (kV) Lines	Number of Transmission and Distribution Substations
Monongahela	758	22,312	23,070	246	343
Potomac Edison	4,983	18,098	23,081	178	188
West Penn	2,782	24,198	26,980	276	595
AGC (a)	0	87	87	87	1
Total	8,523	64,695	73,218	787	1,127

(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.

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FUEL, POWER AND RESOURCE SUPPLY

Generation and Marketing Segment

Coal Supply

Allegheny consumed approximately 19 million tons of coal in 2006 at an average price of $37.95 per ton delivered. Allegheny purchased this coal primarily from mines in Pennsylvania, West Virginia and Ohio. However, Allegheny also purchases coal from other regions. During 2005, Allegheny initiated the blending of coal from the Powder River Basin, or “PRB” coal, with eastern bituminous coal at several generation facilities. The Powder River Basin is a major coal producing area in northeastern Wyoming and southeastern Montana. Allegheny currently intends to continue to blend PRB coal at several generation facilities.

Historically, Allegheny has purchased coal from a limited number of suppliers. Of Allegheny’s coal purchases in 2006, 66% came from subsidiaries of two companies, the larger of which represented 44% of the total tons purchased. As of February 20, 2007, Allegheny had contracts in place for the delivery of approximately 96% of the coal that Allegheny expects to consume in 2007, at an average price of approximately $40 per ton delivered. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties, may have negative effects on coal supplier performance.

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

Natural Gas Supply

AE Supply purchases natural gas to supply its natural gas-fired generation facilities. In 2006, AE Supply purchased its natural gas requirements principally in the spot market. One of AE Supply’s subsidiaries has a long-term natural gas agreement in place with a supplier. The natural gas provided under this agreement is used at the Buchanan generation facility.

Natural Gas Transportation Contracts

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

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

El Paso Transportation Contract.    AE Supply had a long-term agreement with El Paso Natural Gas Company for the transportation of natural gas under tariffs approved by FERC. This agreement provided for the

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transportation of gas from western Texas and northern New Mexico to the southern California border and was purchased for anticipated natural gas deliveries to a combined-cycle generation project that was contemplated in La Paz, Arizona. This project has been cancelled. In August 2003, AE Supply permanently turned back to the pipeline approximately 85% of its capacity obligation under this contract. In November 2004, AE Supply entered into a release for the balance of this capacity. This contract expired as of October 1, 2006.

Kern River Transportation Contract.    AE Supply has a long-term agreement with Kern River Gas Transmission Company for the transportation of natural gas under a tariff approved by FERC. This agreement provides for the transportation of 45,122 decatherms of natural gas per day through April 30, 2018 from Opal, Wyoming to southern California. This transportation agreement was purchased for anticipated natural gas deliveries into southern California and at the Las Vegas Cogeneration II combined-cycle generation facility in Las Vegas, Nevada, in which Allegheny’s participation was terminated in 2003. AE Supply has entered into long-term capacity releases for the full contract volume through October 30, 2008.

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 “Electric Facilities” above.

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

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

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agreements have been partially determined in Maryland but are still under development in Pennsylvania and Virginia and in Maryland, with respect to residential customers. AE Supply’s and Monongahela’s existing power sales agreements with West Penn and Potomac Edison will expire as set forth in the chart below.

Distribution Company	State	Expiration Date of Power Sale Agreement(a)
Potomac Edison	Maryland	December 31, 2008
Potomac Edison	Virginia	June 30, 2007
Potomac Edison	West Virginia	January 1, 2027
West Penn	Pennsylvania	December 31, 2010

(a) The power sales agreements reflected on the table are with AE Supply, except for Potomac Edison’s agreement with Monongahela to serve Potomac Edison’s 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 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.

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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 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 interlocking positions by directors and officers of public utilities.

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

The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales 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

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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. In addition, FERC has imposed standards of conduct governing communications between employees conducting transmission functions and employees engaged in wholesale power sale activities. These standards of conduct are intended to prevent transmission-owning utilities from giving their power marketing businesses preferential access to the transmission system and transmission information. FERC also has taken steps to encourage utilities to participate in RTOs, such as PJM, by transferring functional control over their transmission assets to RTOs.

Following FERC’s initiative to promote competition, a number of states, including Pennsylvania, Maryland 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 the implementation of retail competition (as in Virginia) or rejecting it outright (as in West Virginia). Delays, discontinuations or reversals of electricity marketing restructurings in states in which Allegheny operates could have a material adverse effect on its results of operation and financial condition.

All of Allegheny’s generation assets and power supply obligations are located within the PJM market, and PJM maintains functional control over the Distribution Companies’ transmission facilities. Changes in the PJM tariff, operating agreement, policies and/or market rules could adversely affect Allegheny’s financial results. These matters include changes involving: the terms, conditions and pricing of transmission services; construction of transmission enhancements; auction of long-term financial transmission rights and the allocation mechanism for the auction revenues; 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.

FERC actions with respect to the transmission rate design within PJM may impact the Distribution Companies. Beginning in July 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for these regions. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others. FERC concluded that neither the rate design proposals, nor the existing PJM rate design, had been shown to be just and reasonable. However, FERC ordered the continuation of the existing PJM rate design and the implementation of a transition charge for these regions through March 31, 2006 through filings made by transmission owners in both regions. 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

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payments to the Distribution Companies of $4.8 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 two 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. An initial decision was issued on July 13, 2006 by an administrative law judge, 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 Allegheny 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. The initial decision will not become effective until acted upon by FERC, which may accept, modify or reject the initial decision.

In August 2005, PJM filed at FERC to replace the current capacity market with a new Reliability Pricing Model (“RPM”) to address reliability concerns. On April 20, 2006, FERC issued an initial order that found PJM’s current capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that must be analyzed further before it can 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 would create a locational capacity market in PJM, in which PJM would procure 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 will be met either through purchases made in the proposed auctions or though commitments by load serving entities to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which will begin with the 2007-2008 PJM planning year.

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 load serving entities (“LSEs”) based on the LSEs’ 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. PJM recommended the creation of a new stakeholder process to determine whether this full funding mechanism should be changed subsequent to the 2007-2008 PJM planning year.

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Transmission Expansion

On February 28, 2006, the Distribution Companies requested PJM to include in the PJM Regional Transmission Expansion Plan (“RTEP”) a proposal by the Distribution Companies to construct the Trans-Allegheny Interstate Line (“TrAIL”). PJM’s RTEP identifies transmission system upgrades and enhancements, through a region-wide planning effort, to provide for the operational, economic and reliability requirements of PJM customers and to determine the best way to integrate transmission with generation and load response projects to meet load-serving obligations. TrAIL is designed to increase the west-to-east energy transfer capability of the PJM Transmission System. As originally proposed, it would have consisted of a 330-mile 500 kV transmission line traversing the Distribution Companies’ PJM zone from west to east. In June 2006, the PJM Board of Managers approved an RTEP that includes some elements of the TrAIL proposal in a 240-mile transmission line project, 210 miles of which are to be constructed in the Distribution Companies’ PJM zone. The Distribution Companies were designated by PJM to construct the portion of the line that will be located in the Distribution Companies’ PJM zone. PJM continues to consider as part of its 15-year RTEP process several transmission alternatives that may be constructed within the Distribution Companies’ PJM zone.

Concurrent with the submission of the TrAIL proposal to PJM, Allegheny and the Distribution Companies submitted a petition for declaratory order to FERC requesting four incentive rate treatments. Incentive rate treatments are intended to promote the construction of transmission facilities, such as the TrAIL proposal. Upon the PJM Board of Managers’ approval of the RTEP in June 2006, Allegheny requested FERC to authorize the incentive rate treatments with regard to the 210-mile transmission line to be constructed by the Distribution Companies or their affiliate in the PJM zone. On July 20, 2006, FERC approved the incentive rate treatments for the transmission line. On February 21, 2007, the Distribution Companies submitted to FERC a filing under Section 205 of the FPA to implement a formula tariff rate for TrAIL Company that includes the incentive rate treatment approved by FERC.

On March 6, 2006, the Distribution Companies filed a request with the DOE requesting an early designation for the route of TrAIL as a National Interest Electric Transmission Corridor pursuant to the Energy Policy Act. On August 8, 2006, the DOE published a congestion study in which the general area of the TrAIL Project was classified as a “critical congestion area” that merits further federal attention. In that study, the DOE requested comment by October 10, 2006 as to whether the designation of corridors in relation to the areas identified as congested in the study would be appropriate and in the public interest and, if so, how the geographic boundaries for those corridors should be established. The Distribution Companies submitted comments supporting the designation of a corridor for the Mid-Atlantic area necessary for the construction of the TrAIL Project. Allegheny cannot predict when a decision with regard to this matter will be forthcoming.

During 2006, PJM submitted to FERC three filings providing for the cost allocation of RTEP projects among PJM transmission zones. The filings include allocations for several project to be constructed by the Distribution Companies or by TrAIL Company. The allocations for the TrAIL Project have been protested by several intervenors. This proceeding is set for hearing in June 2007. Allegheny cannot predict the outcome of this hearing or when a decision with regard to this matter will be forthcoming.

PURPA

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 contract obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission. In February 2006, FERC finalized regulations that eliminate ownership restrictions for both new and existing facilities. A qualifying facility may now be owned by a traditional utility. The new rule also ensures that the thermal output of cogeneration facilities is used in a productive and beneficial manner.

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The Distribution Companies have committed to purchase 479 MWs of qualifying PURPA capacity. In 2006, PURPA capacity and energy purchases pursuant to these contracts totaled approximately $204.0 million. The average cost to the Distribution Companies of these power purchases was 5.4 cents/kWh. The Distribution Companies are currently authorized to recover substantially all of these costs in their retail rates. The Distribution Companies’ obligations to purchase power from qualified PURPA projects in the future may exceed amounts they are authorized to recover from their customers, which could result in losses related to the PURPA contracts.

State Rate Regulation

Pennsylvania

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

Joint Petition and Extension of Generation Rate Caps

In September 2004, West Penn, the Pennsylvania Office of Consumer Advocate, the Office of Small Business Advocate and The West Penn Power Industrial Intervenors filed a Joint Petition for Settlement and for Modification of the 1998 Restructuring Settlement (the “Joint Petition”). In March 2005, the parties filed an amendment to the Joint Petition, adding additional parties. By order dated May 11, 2005, the Pennsylvania PUC approved the amended Joint Petition.

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

Stranded Cost Securitizations

In November 1999, under authority granted by the Pennsylvania PUC in its order approving West Penn’s original restructuring settlement, West Penn Funding, LLC, a subsidiary of West Penn, issued $600 million aggregate principal amount of Transition Bonds, Series 1999-A in order to securitize a portion of the anticipated loss in value of its generation-related assets resulting from deregulation, which are known as “stranded costs.” In November 2003, West Penn requested approval to issue additional transition bonds up to $115 million to securitize the portion of West Penn’s stranded costs that are not recoverable on a timely basis due to operation of the generation rate cap. The 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.

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 amended Joint Petition described above, a Request for Proposal for full requirements wholesale electric power supply to serve load in 2009 and 2010 was issued May 31, 2005. AE Supply was the successful bidder and was awarded the contract on July 21, 2005. AE Supply filed a request with the FERC for authority to make these wholesale power sales, which FERC granted on October 25, 2005.

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Other Pennsylvania PUC Matters

Legislation enacted in 2004 requires the implementation of an alternative energy portfolio standard in Pennsylvania that will require electric distribution companies and retail electric suppliers in Pennsylvania to obtain certain percentages of their energy supplies from alternative sources. The new legislation includes an exemption from this requirement for companies, such as West Penn, that are operating within a transition period under the current regulations governing the transition to market competition in Pennsylvania. The full requirement will apply to those companies when the transition period ends. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative sources are not reasonably available. The law directs that all costs related to the purchase of electricity from alternative energy sources and payments for alternative energy credits will be fully recovered pursuant to an automatic energy adjustment clause. The Pennsylvania PUC initiated a proceeding in January 2005 regarding implementation and enforcement of the legislation.

On May 24, 2006, the Pennsylvania PUC issued an Investigation Order for a generic investigation entitled “Policies to Mitigate Potential Electricity Price Increases.” The Pennsylvania PUC’s purpose for this proceeding is to address issues and develop policies to mitigate the effects of the higher electricity prices that may result with the expiration of the long-term generation price caps that are currently in place for many Pennsylvania utilities, including West Penn. An en banc hearing to assist the Pennsylvania PUC in developing policies to mitigate potential electricity price increases when rate caps end was held on June 22, 2006. A tentative order was issued in the proceeding on February 13, 2007, with comments due on March 5, 2007.

The Pennsylvania PUC is conducting an audit of the management efficiency of West Penn, as the Pennsylvania PUC is required by state law to do every five to eight years for all major Pennsylvania utilities. The last such audit of West Penn by the Pennsylvania PUC was completed in 2000. The audit is expected to be completed in 2007 and to concentrate on areas such as physical and information security, electric distribution system reliability, accounting controls and corporate governance.

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.

West Virginia

In 1998, the West Virginia legislature passed legislation directing the West Virginia PSC to determine whether retail electric competition was in the best interests of West Virginia and its citizens. In response, the West Virginia PSC submitted a plan to introduce full retail competition on January 1, 2001. The West Virginia legislature approved, but never implemented, this plan. In March 2003, the West Virginia legislature passed a bill that clarified the jurisdiction of the West Virginia PSC over electric generation facilities. Based on these actions, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West Virginia. In 2000, Potomac Edison received approval to transfer its West Virginia generation assets to AE Supply. The West Virginia PSC never acted on a similar petition by Monongahela, and Monongahela agreed to withdraw its petition.

Proposed Securitization and Scrubber Project

On May 4, 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

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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 a proposed restructuring of the ownership of certain of Allegheny’s generation assets, 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 that will be dedicated to the repayment of the bonds.

On September 8, 2006, Allegheny announced that the expected cost of installing the Scrubbers at the Fort Martin generation facility would be higher than previously estimated. Allegheny currently estimates construction costs associated with the project to be approximately $550 million, excluding certain related financing costs. This increase in cost estimates is due to a number of factors, including construction challenges caused by site-specific characteristics, necessary changes in material-handling equipment, increased costs associated with labor and specialty contractor services and higher material costs. There can be no assurance that Allegheny will not encounter additional costs related to these or other items.

On October 3, 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. The Petition requested that the West Virginia PSC reopen the Financing Order proceedings for the purposes of amending the Financing Order to increase the securitization financing authority for construction related costs to an amount up to $550 million and reduce the maximum amount of upfront financing costs (exclusive of costs for the West Virginia PSC’s financial advisor) that may be recovered from environmental control bond proceeds from $27 million to $23 million. In addition, Monongahela and Potomac Edison indicated in the Petition that a complete review and value engineering process was being performed on the Fort Martin Scrubbers project and that a supplement to the Petition updating and further refining the current project cost estimate would be submitted to the West Virginia PSC within 45 days. On November 13, 2006, Allegheny filed a Supplement to the Petition with the West Virginia PSC that detailed the construction cost estimate of $550 million.

On December 18, 2006, Allegheny reached a settlement agreement with all parties in the reopened cases and filed the agreement with the West Virginia PSC. The settlement agreement requested that the West Virginia PSC authorize Allegheny to securitize up to $450 million of the estimated construction costs, plus $16.5 million of upfront financing costs and certain other costs. The agreement also requested that Allegheny be 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 permits Allegheny to file for recovery of any costs exceeding the $450 million once the Scrubber is in commercial service. On January 17, 2007, the West Virginia PSC approved the settlement agreement.

Rate Case

On July 26, 2006, Monongahela and Potomac Edison 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 includes 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 $26.2 million decrease in base rates. The rate increase request is subject to approval by the West Virginia PSC. On August 22, 2006, the West Virginia PSC issued an Order suspending Monongahela’s and Potomac Edison’s proposed new rates until May 23, 2007 and establishing a procedural schedule for the proceeding. Consistent with the procedural schedule, Monongahela and Potomac Edison filed

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direct testimony in support of the rate request on September 8, 2006. On January 22, 2007, the West Virginia PSC Staff and intervenors in the proceeding filed testimony. Monongahela and Potomac Edison filed rebuttal testimony on February 5, 2007. Evidentiary hearings in the proceeding took place the week of February 12, 2007.

Maryland

Maryland adopted electric industry restructuring legislation in 1999, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation suppliers. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply 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. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates for all customers were capped through 2004 and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates).

In 2003, the Maryland PSC approved 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.

Power Purchase Agreement

Potomac Edison has a power purchase agreement with AE Supply to provide the amount of electricity necessary to meet the majority of Potomac Edison’s PLR retail obligations during the Maryland generation rate cap period. Potomac Edison will procure the wholesale electric supply services necessary to serve its PLR obligations after the expiration of the rate caps and before the expiration of its SOS obligations through a competitive bid process. Potomac Edison will be allowed to recover its costs for providing these services, including a return for its shareholder, through an administrative charge. In December 2005 and January 2006, AE Supply was awarded contracts under a competitive auction to sell power to Potomac Edison to serve approximately 1.3 million MWhs of generation and associated services for certain small commercial and industrial customers in Maryland beginning in June 2006. These contracts expire at various times in 2007 and 2008.

Rate Stabilization

In special session, the Maryland legislature passed emergency legislation on June 23, 2006, reconstituting the Maryland PSC, directing a Commission investigation into the proposed merger of FPL Group, Inc. and Constellation Energy Group, Inc. and approving a transition plan for residential customers of Baltimore Gas and Electric Company to move from capped rates to market-based default service rates. For Allegheny, the legislation requires the Commission to investigate options available to implement a rate mitigation or rate stabilization plan, including the renegotiation of a settlement agreement to allow a portion of the residential electric supply in Allegheny’s Maryland service territory to be procured at market rates earlier than otherwise

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provided in its settlement agreement, so that residential electricity rates are not exposed to volatile market conditions at one time, while ensuring that customers obtain the full value of the savings provided under the existing generation rate cap.

On December 29, 2006, Allegheny filed its proposed Rate Stabilization Ramp-Up Transition Plan with the Maryland PSC, which is designed to transition residential customers from capped rates to rates based on market prices beginning in 2007 and ending in 2010. Under the plan as originally proposed, residential customers would pay a distribution surcharge beginning in early 2007. The application of the surcharge would 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. On January 31, 2007, after a series of public hearings on the Ramp-Up Transition Plan, Allegheny filed supplemental testimony setting forth an alternative to its original proposal. The alternative proposal would allow customers the ability to opt out of participating in the plan and contains other adjustments to address points raised in the public hearings. On February 2, 2007, all 21 members of the western Maryland delegation to the Maryland legislature sent a letter to the Maryland PSC publicly endorsing Allegheny’s alternative plan and urging its prompt approval by the Maryland PSC. The Maryland PSC has scheduled an evidentiary hearing on the proposed plans for March 15, 2007.

Renewable Energy Portfolio Standard

Legislation enacted in 2004 requires the implementation of a renewable energy portfolio standard in Maryland. Beginning upon the later of the expiration of the transition period for any particular customer class served by a supplier or January 1, 2006, retail electricity suppliers in Maryland will have to obtain certain percentages of their energy supplies from renewable energy resources. The law provides that if renewable resources are too expensive, or are not available in quantities sufficient to meet the standard in any given year, suppliers can instead opt to pay a “compliance fee.” The law directs the Maryland PSC to allow electric suppliers to recover their costs from customers, including any compliance fees that they incur.

Virginia

Under the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”), Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Potomac Edison is the PLR for those customers who do not choose an alternate generation supplier or whose alternate generation supplier does not deliver. The Restructuring Act capped Potomac Edison’s generation rates until July 1, 2007, but was amended in 2001 to provide that the rate for PLR retail service would be priced at market beginning July 1, 2007 (the “2001 Amendment”). The Restructuring Act was amended again in 2004 to extend the capped generation rate period until December 31, 2010, but provided for utilities, such as Potomac Edison, to recover purchased power costs (the “2004 Amendment”). Potomac Edison has a power purchase agreement with AE Supply to provide it with the amount of electricity necessary to meet its PLR retail obligations until July 1, 2007 at the capped generation rates. Beginning July 1, 2007, Potomac Edison will purchase its PLR requirements from the wholesale market at market prices. Market prices for purchased power at that time may be higher than the rates Potomac Edison will be allowed to recover from its retail customers.

Specifically, Allegheny believes that, based on the 2001 Amendment and the 2004 Amendment, 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. However, based on a memorandum of understanding (“MOU”) between the Virginia State Corporation Commission (the “Virginia SCC”) and Potomac Edison entered into at the time of the transfer of Potomac Edison’s generation facilities to AE Supply in 2000, the Virginia SCC may find that the generation rates Potomac Edison is able to charge for a certain portion of the power it purchases, currently

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estimated to be approximately 2.2 million MWhs per year, would be limited to a price based upon a calculation of the cost to generate that power from the generation facilities that Potomac Edison previously owned. For the remainder of its power purchases, which Potomac Edison currently estimates to be approximately 1.1 million MWhs per year, Potomac Edison is permitted to petition the Virginia SCC to recover from its Virginia customers the market price of such MWhs beginning July 1, 2007. Thus, there can be no assurance that Potomac Edison will be able to recover any or all 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 may have a material adverse effect on Potomac Edison’s business, results of operations and financial condition.

Potomac Edison’s T&D rates in Virginia are capped through 2010, subject to certain exceptions. Prior to 2010, Potomac Edison has two opportunities to petition the Virginia SCC for changes to its T&D rates: the first prior to June 30, 2007, and the second 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 July 1, 2004 for T&D system reliability or to comply with state or federal environmental laws or regulations.

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ENVIRONMENTAL MATTERS

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

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

Global Climate Change

Allegheny’s generation facilities are primarily coal-fired facilities and, therefore, emit carbon dioxide as coal is consumed. Carbon dioxide, or “CO₂,” is one of the greenhouse gases implicated in global climate change. There is no current technology that enables control of such emissions from existing pulverized, coal-fired power plants, which constitute the majority of Allegheny’s generation fleet. At the same time, Allegheny takes its responsibility for environmental stewardship seriously and recognizes its obligation to its shareholders to address the issue of climate change. Despite the regulatory actions of some states and regional groups in 2006, Allegheny believes that the challenge presented by global climate change can only be resolved with global solutions. In addition, Allegheny believes that the United States must commit to a response that both encourages the development of technology and creates a workable control system. The U.S. Congress is moving towards the development of national legislation, yet the process is still in its infancy. As such, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures until the exact nature and requirements of a national regulation are known, and the capabilities of control or reduction technologies are more fully understood. Allegheny recognizes the possibility that federal legislation and implementing regulations addressing climate changes will be adopted some time in the future. Allegheny’s current strategy focuses on:

• developing an accurate CO₂ emissions inventory;

• improving the efficiency of its coal-burning fleet;

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

• following developing technologies for carbon sequestration;

• participating in carbon dioxide sequestration efforts (e.g., reforestation projects) both domestically and abroad; and

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

To the extent that legislation is introduced and programs are developed, Allegheny intends to aggressively advocate for a national approach that protects its generation fleet and investments, enhances the environment, and ensures continued energy supply for its customers. Allegheny’s management is following this issue closely and will take further appropriate action as the economics and legislation, if any, unfold.

Air Standards

Clean Air Act Compliance.  Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through 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

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emission controls, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.

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

The Clean Air Act mandates annual reductions of SO₂ and created a SO₂ emission allowance trading program. AE Supply and Monongahela comply with current SO₂ emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Based on current forecasts, Allegheny estimates that it may have exposure to the SO₂ allowance market in 2007 of about 30,000 to 50,000 tons and may have exposure in 2008 of between 85,000 and 120,000 tons. Monongahela’s exposure is expected to be approximately 70% and 50% of Allegheny’s exposure in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Allegheny continues to evaluate options for compliance, and current plans include the installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generation facilities by 2009 and the elimination of a Scrubber bypass at its Pleasants generation facility by 2008. In July 2006, AE Supply entered into construction contracts with The Babcock & Wilcox Company and Washington Group International in connection with its plans to install Scrubbers at its Hatfield’s Ferry generation facility.

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

AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. Allegheny estimates that its emission control activities, in concert with its inventory of banked allowances and future transactions, will facilitate its compliance with NOx limits established by the SIP through 2008. Based on these estimates, Allegheny estimates that it will have minimal exposure to the NOx allowance market through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities. Therefore, there can be no assurance that Allegheny’s need to purchase NO_X allowances for these periods will not vary from current estimates.

On March 15, 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”) establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and its strategy for compliance. The Pennsylvania Department of Environmental Protection (the “PA DEP”) proposed a more aggressive mercury control rule on June 24, 2006, which is going through the regulatory review process and which is expected to be finalized in the first quarter of 2007. Allegheny is assessing the proposed Pennsylvania rule to determine what, if any, effect it would have on Allegheny’s Pennsylvania 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.

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Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NO_X, requires that greater reductions in mercury emissions be made more quickly than would be required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative and participate in that coalition’s regional efforts to reduce CO₂ emission. The 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 by June 2007 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 will work with the MDE on the R. Paul Smith-specific regulations.

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

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology. There are three recent, significant federal court decisions that have addressed the application of NSR requirements to electric utility generation facilities: the Ohio Edison decision, the Duke Energy decision and the Alabama Power decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy and Alabama Power decisions support the industry’s understanding of NSR requirements. The U.S. Court of Appeals for the Fourth Circuit affirmed the Duke Energy decision on June 15, 2005. On May 15, 2006, the U.S. Supreme Court agreed to hear an appeal of the Fourth Circuit’s decision in the Duke Energy case. Oral argument took place on November 1, 2006, and a decision is expected by the summer of 2007. The Supreme Court’s decision may provide clarity on whether the industry’s or the government’s interpretation of 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.

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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 February 17, 2006, Allegheny filed a motion to dismiss the amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss. On June 30, 2006, Allegheny filed an answer to the plaintiff’s first amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies, and the liability phase of discovery should be completed by June 30, 2007.

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

Other Environmental Litigation

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

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 joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. These motions remain pending. 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 either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their

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obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties in these actions are seeking an allocation of responsibility for historic and potential future asbestos liability.

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

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2006, Allegheny had 828 open cases remaining in West Virginia and four open cases remaining in Pennsylvania.

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

Pending Initiatives

Particulates.  The EPA promulgated revisions to particulate matter and ozone standards in July 1997. In September 2006, the EPA lowered the ambient air standards for particulates. The EPA also has promulgated final regional haze regulations to improve visibility in national parks and wilderness areas. The effect on Allegheny of these regulations is unknown at this time, but could be substantial.

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

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EMPLOYEES

Substantially all of the registrants’ officers and employees are employed by AESC. As of December 31, 2006, AESC employed 4,362 employees. Of these employees, approximately 29% are subject to collective bargaining arrangements. Approximately 74% of the unionized employees are at the Distribution Companies and approximately 26% are at AE’s other subsidiaries. Approximately 1,063 employees are represented by System Local 102 of the Utility Workers Union of America (the “UWUA”). Allegheny entered into a new collective bargaining arrangement with UWUA Local 102 on May 1, 2006. Approximately 187 employees are represented by locals of the International Brotherhood of Electrical Workers (the “IBEW”). Collective bargaining arrangements with the IBEW expire at various dates during the first half of 2010. Each of the Registrants believes that current relations between it and its unionized and non-unionized employees are satisfactory.

On September 19, 2005, AE entered into a Professional Services Agreement 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.

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Executive Officers of the Registrants

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

Name	Age	AE	Monongahela	AGC
Paul J. Evanson (a)	65	Chairman, President, Chief Executive Officer and Director	Chairman, Chief Executive Officer and Director	Chairman, Chief Executive Officer and Director
Edward Dudzinski (b)	54	Vice President	Vice President
David M. Feinberg (c)	37	Vice President, General Counsel and Secretary	Vice President and Secretary	Vice President, Secretary and Director
David E. Flitman (d)	42	Vice President	President and Director
Thomas R. Gardner (e)	49	Vice President, Controller, Chief Accounting Officer and Chief Information Officer	Controller	Vice President and Controller
Philip L. Goulding (f)	47	Senior Vice President and Chief Financial Officer	Vice President and Director	Vice President and Director
Joseph H. Richardson (g)	57	Chief Operating Officer —Generation

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

(b) Edward Dudzinski has been Vice President, Human Resources, of AE since August 2004. He has also been a Vice President of Monongahela 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. He has also been Vice President, General Counsel and Secretary of Monongahela and AGC since 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) Thomas R. Gardner has been Vice President, Controller and Chief Accounting Officer of AE since October 2003 and has been Chief Information Officer of AE since June 2005. He has also been the Controller of Monongahela and a Vice President and the Controller of AGC since October 2003. Prior to joining Allegheny, Mr. Gardner was employed with Deloitte & Touche LLP from 1997 to 2003, most recently as a partner.

(f) Philip L. Goulding has been Senior Vice President and Chief Financial Officer of AE since July 2006. He has also been Vice President of Monongahela and AGC 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.

(g) Joseph. H. Richardson has been Chief Operating Officer—Generation of AE since July 2006. Mr. Richardson joined Allegheny in August 2003 as a Vice President of AE and as President and a director of Monongahela, Potomac Edison and West Penn. Prior to joining Allegheny, Mr. Richardson served as President and Chief Executive Officer and as a director of Global Energy Group from March 2002 to August 2003. Prior to that, he served as President and Chief Executive Officer and as a director of Florida Power Corporation.

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ITEM 1A.    RISK FACTORS

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

Risks Relating to Regulation

Allegheny is subject to substantial governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits and certificates may result in substantial costs to Allegheny, 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 the necessary authorizations, permits, approvals and certificates have been obtained for Allegheny’s existing operations and that Allegheny’s 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 “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.

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. Either result could have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition. In addition, any alleged violations of environmental laws and regulations may require Allegheny to expend significant resources defending itself against such alleged violations.

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 allowances. Allegheny continues to evaluate options for compliance, and current plans include the potential installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generation facilities by 2009 and the elimination of a Scrubber bypass at its Pleasants generation facility by 2008. 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.

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Carbon dioxide, or “CO₂,” is one of the greenhouse gases implicated in global climate change. Allegheny’s generation facilities are primarily coal-fired facilities and, therefore, emit CO₂ as coal is consumed. Federal legislation and implementing regulations addressing climate change may be adopted some time in the future, and such legislation may include limits on emissions of CO₂. Allegheny can provide no assurance that such limits, if imposed, will be set at levels that can accommodate its generation facilities absent the installation of controls. Furthermore, there is no current technology that enables control of such emissions from existing pulverized, coal-fired power plants, which constitute the majority of Allegheny’s generation fleet. 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. 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. See “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. 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. See “Environmental Matters” above.

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

On January 6, 2005, AE Supply and Monongahela filed the West Virginia DJ Action. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia comply with the Clean Air Act. The Attorneys General filed a motion to dismiss the West Virginia DJ Action. It is possible that the EPA and other state authorities may join or move to transfer the West Virginia DJ Action. On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed the PA Enforcement Action. This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General.

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

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

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

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. Although we expect the deregulated electricity markets to remain competitive, other proposals to re-regulate our 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 we operate. 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” 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 by each state’s regulatory body. As a result, in certain states, Allegheny may not be able to recover increased, unexpected or necessary costs and, even if Allegheny is able to do so, there may be a significant delay between the time Allegheny incurs such costs and the time Allegheny is allowed to recover them. Any denial of, or delay in, cost recovery could have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Maryland

In Maryland, Potomac Edison’s residential customer rates are capped until December 31, 2008. Furthermore, Potomac Edison’s contract with AE Supply for generation services contains a limited exposure to changing market rates through the residential rate cap period. On June 23, 2006, the Maryland legislature, acting in a special session, passed emergency legislation that, among other things, requires the Maryland PSC to investigate options available to implement a rate mitigation or rate stabilization plan for Potomac Edison for the period after its capped residential rate expires on December 31, 2008, including the renegotiation of a settlement agreement to allow a portion of the residential electric supply in Potomac Edison’s Maryland service territory to be procured at market rates earlier than otherwise provided in its settlement agreement, so that residential electricity rates are exposed to market prices more gradually, rather than all at one time, while ensuring that customers obtain the full value of the savings provided under the existing rate cap.

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On December 29, 2006, Potomac Edison proposed a rate stabilization and transition plan for its Maryland residential customers, in accordance with the legislation passed by the Maryland legislature. Potomac Edison’s plan will gradually transition its residential customers from capped generation rates to generation rates based on market prices, while at the same time preserving for customers the benefit of previous rate caps. Potomac Edison’s proposed transition plan is subject to final approval by the Maryland PSC. Potomac Edison has requested that the Maryland PSC approve the plan to be effective beginning March 31, 2007. Allegheny can provide no assurance that the proposed plan will be implemented or that any alternative plan that may be implemented will not have an adverse effect on its business. See “Regulatory Framework Affecting Allegheny” above.

Virginia

Potomac Edison’s Virginia generation rates were originally capped until July 1, 2007, but this cap was extended by legislation until December 31, 2010. Potomac Edison has 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. Beginning July 1, 2007, Potomac Edison will purchase its PLR requirements from the wholesale market at market prices. Market prices for purchased power at that time may be significantly higher than the rates Potomac Edison will be allowed to recover from its retail customers.

Allegheny believes that 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. However, based upon a memorandum of understanding between the Virginia SCC and Potomac Edison entered into at the time of the transfer of Potomac Edison’s generation facilities to AE Supply in 2000, the Virginia SCC may find that the generation rates Potomac Edison is able to charge for a certain portion of the power that it purchases, currently estimated to be approximately 2.2 million MWhs per year, would be limited to a price based upon a calculation of the cost to generate that power from the generation facilities that Potomac Edison previously owned. For the remainder of its power purchases, which it currently estimates to be approximately 1.1 million MWhs per year, Potomac Edison is permitted to petition the Virginia SCC to recover from its Virginia customers the cost of purchasing such power beginning July 1, 2007. There can be no assurance that Potomac Edison will be able to recover any or all 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 may have an adverse affect on Allegheny’s business, results of operations and financial condition.

West Virginia

The West Virginia PSC sets Monongahela’s and Potomac Edison’s rates in West Virginia through traditional, cost-based regulated utility ratemaking. As part of Monongahela’s efforts to spur deregulation in West Virginia, which ultimately was not implemented, it agreed to terminate its fuel clause effective July 1, 2000. Thus, to recover increased, unexpected or necessary costs, including increased coal and other raw material costs, Monongahela must file for approval from the West Virginia PSC to recover such costs or to reinstate its fuel clause. There can be no assurance that Monongahela will be able to recover such costs or reinstate its fuel clause under the ratemaking process. Even if Monongahela is able to recover costs, there may be a significant delay between the time that it incurs such costs and the time that it is allowed to recover such costs. Any inability to recover, or delay in the recovery of, these costs could have a material adverse effect on Monongahela’s financial condition, cash flows and results of operations.

On July 26, 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 includes 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. The hearing in this matter was held the week of February 12, 2007. The new rates, as approved by the West Virginia PSC, will go into effect on May 23, 2007. Allegheny can provide no assurance that this rate increase request will be approved. Any failure to receive such an approval in whole or in part may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

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The TrAIL Project is subject to permitting and state regulatory approvals.

Allegheny may not construct TrAIL without the prior approval of the Pennsylvania PUC, the Virginia SCC, the West Virginia PSC and possibly the Maryland PSC. In addition, Allegheny has applied to the DOE to designate TrAIL as a National Interest Electric Transmission Corridor. Allegheny can provide no assurance that it will be able to obtain either the requisite state approvals or the National Interest Electric Transmission Corridor designation from the DOE. The inability to obtain any such state approval or the National Interest Electric Transmission Corridor designation may have an adverse affect on Allegheny’s business, results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny” 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 Related to Allegheny’s Leverage and Financing Needs

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

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

Although Allegheny reduced debt by approximately $2.4 billion between December 1, 2003 and December 31, 2006, Allegheny still has substantial leverage. At December 31, 2006, Allegheny had $3.6 billion of debt on a consolidated basis. Approximately $2.2 billion represented debt of AE Supply and AGC, and the remainder constituted debt of one or more of the Distribution Companies.

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

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

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• 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.

Allegheny may be unable to engage in desired financing transactions.

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

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

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

• volatility in the capital markets.

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

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

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

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

Allegheny relies on access to the capital markets as a source of liquidity and to satisfy any of its capital requirements that are not met by the cash flow from its operations. Capital market disruptions, or a downgrade in

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Allegheny’s credit ratings, 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.

Risks Relating to Allegheny’s Operations

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

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

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

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

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

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

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

Much of the value of Allegheny’s business consists of its portfolio of power generation and T&D assets. Allegheny’s ability to conduct its operations depends on the integrity of these assets. The cost of repairing damage to its facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events may exceed available

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insurance, if any, for repairs, which may adversely impact Allegheny’s results of operations and financial condition. Although Allegheny has taken, and will continue to take, reasonable precautions to safeguard these assets, Allegheny can make no assurance that its facilities will not face damage or disruptions or that it will 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, financial condition, cash flow and results of operations.

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

Additionally, Potomac Edison has a power supply agreement with Monongahela under which Monongahela is required to supply to Potomac Edison the power necessary for Potomac Edison to serve its West Virginia 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. Although Potomac Edison and Monongahela recently filed a request with the West Virginia PSC to increase their rates in West Virginia, it is possible that Potomac Edison may not be permitted to recover from its West Virginia customers the full cost of purchasing power under the terms of this agreement.

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

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

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Based on current forecasts, Allegheny estimates that it may have exposure to the SO₂ allowance market in 2007 of about 30,000 to 50,000 tons and may have exposure in 2008 of between 85,000 and 120,000 tons. The exposure of Monongahela is expected to be 70% and 50% of Allegheny’s exposure in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Fluctuations in the availability or cost of emission allowances could have a material adverse effect on Allegheny’s 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 and the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities. Allegheny’s ability to successfully and timely complete these projects 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, or expects to contract, 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 may in the future enter into additional such contracts with respect to these and other capital projects, including the TrAIL 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. 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 is currently involved in significant litigation that, if not decided favorably to Allegheny, could have a material adverse effect on its results of operations, cash flows and financial condition.

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

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

The Distribution Companies have been named as defendants in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at Allegheny-owned facilities where suitable alternative materials are not available. Allegheny’s management believes that any remaining asbestos at Allegheny-owned facilities is contained. The continued presence of asbestos and other regulated substances at Allegheny-owned facilities, however, could result in additional actions being brought against Allegheny. See “Legal Proceedings” below and Note 17, “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

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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. It is possible that Allegheny could incur a significant pension liability adjustment, or could be required to make significant additional cash contributions to its plan, which would reduce the cash available for business and other needs.

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

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 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 could negatively impact Allegheny’s performance.

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

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

Risks Relating to Operational Enhancements

Refocusing its business subjects Allegheny to risks and uncertainties.

Allegheny has implemented significant changes to its operations as part of its overall strategy to function as an integrated utility company, to the extent practicable and permissible under relevant regulatory constraints. For example, Allegheny has disposed of certain non-core assets, reduced the size of its workforce, made substantial changes to senior management and undertaken the implementation of a new company-wide enterprise resource planning system. Additional changes to Allegheny’s business will be considered as management seeks to strengthen financial and operational performance. These changes may be disruptive to Allegheny’s established organizational culture and systems. In addition, consideration and planning of strategic changes diverts management attention and other resources from day to day operations.

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

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

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ITEM 2.    PROPERTIES

Substantially all of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations. Substantially all of Monongahela’s, 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” below and Note 4, “Capitalization” to the Consolidated Financial Statements.

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

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ITEM 3.    LEGAL PROCEEDINGS

Nevada Power Contracts

On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with FERC against AE Supply seeking action by FERC to modify prices payable to AE Supply under three trade confirmations between Merrill Lynch and NPC. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with Merrill Lynch under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers. On December 19, 2002, the Administrative Law Judge (“ALJ”) issued findings that no contract modification was warranted. The ALJ determined in favor of NPC that AE Supply, rather than Merrill Lynch, was a proper subject of NPC’s complaint. On June 26, 2003, FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others. FERC did not decide whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, FERC issued an order, on rehearing, affirming its conclusion that the long-term contracts should not be modified. Snohomish County and other parties filed petitions for review of FERC’s June 26, 2003 order with the U.S. Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. On December 19, 2006, the Ninth Circuit issued an opinion remanding the case to FERC to determine, in accordance with the guidance set forth in the Ninth Circuit’s opinion, whether FERC utilized the appropriate standard of review in deciding various claims, including NPC’s complaint.

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

Sierra/Nevada

On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted claims against AE and AE Supply for: (a) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (b) conspiracy and (c) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada filed an amended complaint on May 30, 2003, which asserted a fourth cause of action against AE and AE Supply for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys’ fees and seeks in excess of $850 million under the RICO count. AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. Thereafter, plaintiffs filed a motion to stay the action, pending the outcome of certain state court proceedings in which they are seeking to reverse the Nevada PUC’s disallowance of expenses. On April 4, 2005, the District Court granted the stay motion, and the action is currently stayed. 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.

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 U.S. Court of Appeals for the Ninth Circuit to resolve all outstanding claims

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

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

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, for which it had granted Merrill Lynch summary judgment, and with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of contract. Following the trial, on July 18, 2005, the District Court entered an order: (a) ruling against AE and AE Supply on their fraudulent inducement and breach of contract claims; (b) requiring AE to pay $115 million plus interest to Merrill Lynch; and (c) requiring Merrill Lynch to return its equity interest in AE Supply to AE. On August 26, 2005, the Court entered its final judgment in accordance with its July 18, 2005 ruling. On September 22, 2005, AE and AE Supply filed a notice of appeal of the District Court’s judgment to the U.S. Court of Appeals for the Second Circuit, which heard oral argument on October 30, 2006. Although AE will not be required to pay Merrill Lynch the amount of the judgment while the appeal is pending, AE has posted a letter of credit to secure the judgment.

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

Putative Benefit Plan Class Actions

In February and March 2003, two putative class action lawsuits were filed against AE in U.S. District Courts for the Southern District of New York and the District of Maryland. The suits alleged that AE and a senior manager violated ERISA by: (a) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (b) failing to diversify plan assets; (c) failing to monitor investment

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alternatives; (d) failing to avoid conflicts of interest and (e) violating fiduciary duties. The ERISA cases were consolidated in the District of Maryland. On April 26, 2004, the plaintiffs in the ERISA cases filed an amended complaint, adding a number of current and former directors of AE as defendants and clarifying the nature of their claims. Allegheny has entered into an agreement to settle the consolidated ERISA class actions, and on February 13, 2007 the district court entered an order preliminarily approving the settlement. The proposed settlement remains subject to final court approval, following notice to class members. Under the proposed settlement, the consolidated ERISA class actions will be dismissed with prejudice in exchange for a cash payment of $4 million, of which approximately $3.9 million will be made by Allegheny Energy’s insurance carrier.

Suits Related to the Gleason Generation Facility

Allegheny Energy Supply Gleason Generation Facility, LLC, a subsidiary of AE Supply, is the defendant in a suit brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generation facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the generation facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generation facility. They seek a restraining order with respect to the operation of the plant and damages of $200 million. Mediation sessions were held on June 17, 2004 and February 22 and 23, 2006, but the parties did not reach settlement. On September 18, 2006, the Court heard oral argument on Allegheny’s summary judgment motions regarding the plaintiffs’ claims for, among other causes of action, property and punitive damages, and a decision from the Court on these motions is pending. The case has been set for trial on April 2, 2007. AE has undertaken property purchases and other mitigation measures. AE intends to vigorously defend against this action but cannot predict its outcome.

Harrison Fuel Litigation

On November 7, 2001, Harrison Fuel and its owner filed a lawsuit against Monongahela, “Allegheny Power” and AESC in the Circuit Court of Marion County, West Virginia. The lawsuit claims that Allegheny improperly and arbitrarily rejected bids from Harrison Fuel and other companies affiliated with its owner to supply coal to Allegheny. Plaintiffs seek damages of approximately $13 million. On January 5, 2007, the Court entered an order setting this case for trial on May 14, 2007. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

ICG Litigation

On December 28, 2006, AE Supply and Monongahela filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group and certain of its affiliates (collectively, “ICG”). The complaint asserts claims for breach of contract and negligent misrepresentation based on ICG’s failure to supply coal at the Harrison Power Station pursuant to its obligations under a long-term coal sales agreement. AE Supply and Monongahela intend to vigorously pursue this matter but cannot predict its outcome.

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 of AE, Monongahela or AGC during the fourth quarter of 2006.

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PART II

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

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

AE

“AYE” is the trading symbol for AE’s common stock on the New York and Chicago Stock Exchanges. As of February 20, 2007, there were 20,845 holders of record of AE’s common stock. The table below shows the high and low sales prices of AE’s common stock on the New York Stock Exchange for the periods indicated:

	2006				2005
	High		Low		High		Low
1st Quarter	$	36.46	$	31.33	$	21.28	$	18.25
2nd Quarter	$	37.61	$	33.01	$	25.85	$	20.28
3rd Quarter	$	42.50	$	36.97	$	31.35	$	25.25
4th Quarter	$	46.25	$	39.93	$	32.32	$	26.40

AE did not pay any dividends on its common stock during 2005 or 2006.

Monongahela

AE owns 100% of the outstanding shares of common stock of Monongahela. Monongahela paid a dividend on its common stock of approximately $10.01 million on March 31, 2006. Monongahela did not pay dividends on its common stock in the second, third or fourth quarters of 2006 or in 2005. Monongahela’s charter limits the payment of dividends on common stock.

AGC

As of December 31, 2006, Monongahela and AE Supply owned approximately 23% and 77%, respectively, of the outstanding shares of common stock of AGC. As a result of the Asset Swap, Monongahela and AE Supply currently own approximately 41% and 59%, respectively, of the outstanding shares of common stock of AGC. AGC paid dividends on its common stock of approximately $5 million, $8 million, $10 million and $8 million on March 31, 2006, June 30, 2006, September 30, 2006 and December 31, 2006, respectively. AGC paid dividends on its common stock of approximately $7.2 million, $9.0 million and $5.6 million on June 30, 2005, September 30, 2005 and December 31, 2005, respectively. AGC did not pay a dividend on its common stock for the first quarter of 2005.

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Performance Graph

The graph set forth below compares our cumulative total stockholder return on our common stock with the Dow Jones U.S. Electricity Index and the Standard & Poor’s 500 Index at each December 31 from 2001 to 2006. These graphs assume the investment of $100 in each on December 31, 2001, and the reinvestment of all dividends. The stock price performance included in these graphs is not necessarily indicative of future stock price performance.

	Cumulative Total Return
	12/01	12/02	12/03	12/04	12/05	12/06
Allegheny Energy, Inc.	100.00	21.96	37.07	57.26	91.95	133.38
S & P 500	100.00	77.90	100.24	111.15	116.61	135.03
Dow Jones U.S. Electricity	100.00	77.33	96.72	120.28	140.57	169.88

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ITEM 6.    SELECTED FINANCIAL DATA

	Page No.
Allegheny Energy, Inc. and Subsidiaries	60
Monongahela Power Company and Subsidiaries	61
Allegheny Generating Company	61

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ITEM 6.    SELECTED FINANCIAL DATA

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Year ended December 31,	2006		2005			2004			2003			2002
(In millions, except per share data)
Operating revenues	$	3,121.5	$	3,037.9		$	2,756.1		$	2,182.3		$	2,743.8
Operating expenses	$	2,389.2	$	2,501.1		$	2,166.9		$	2,378.7		$	3,216.4
Operating income (loss)	$	732.3	$	536.8		$	589.2		$	(196.4	)	$	(472.6	)
Income (loss) from continuing operations	$	318.7	$	75.1		$	129.7		$	(308.9	)	$	(465.8	)
Income (loss) from discontinued operations, net of tax	$	0.6	$	(6.1	)	$	(440.3	)	$	(25.3	)	$	(36.4	)
Net income (loss)	$	319.3	$	63.1		$	(310.6	)	$	(355.0	)	$	(632.7	)
Earnings per share:
Income (loss) from continuing operations, net of tax
—basic	$	1.94	$	0.48		$	1.00		$	(2.44	)	$	(3.71	)
—diluted	$	1.89	$	0.47		$	0.99		$	(2.44	)	$	(3.71	)
Loss from discontinued operations, net of tax
—basic	$	—	$	(0.04	)	$	(3.40	)	$	(0.20	)	$	(0.29	)
—diluted	$	—	$	(0.04	)	$	(2.82	)	$	(0.20	)	$	(0.29	)
Net income (loss)
—basic	$	1.94	$	0.40		$	(2.40	)	$	(2.80	)	$	(5.04	)
—diluted	$	1.89	$	0.40		$	(1.83	)	$	(2.80	)	$	(5.04	)
Dividends declared per share	$	—	$	—		$	—		$	—		$	1.29
Short-term debt	$	—	$	—		$	—		$	53.6		$	1,132.0
Long-term debt due within one year (a)		201.2		477.2			385.1			544.9			257.2
Debentures, notes and bonds (a)		—		—			—			—			3,662.2
Total short-term debt (a)	$	201.2	$	477.2		$	385.1		$	598.5		$	5,051.4
Long-term debt (a)	$	3,384.0	$	3,624.5		$	4,540.8		$	5,127.4		$	115.9
Capital leases		26.0		16.4			23.8			32.5			39.1
Total long-term obligations (a)	$	3,410.0	$	3,640.9		$	4,564.6		$	5,159.9		$	155.0
Total assets	$	8,552.4	$	8,558.8		$	9,045.1		$	10,171.9		$	10,973.2

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

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Year ended December 31,	2006			2005		2004			2003		2002
(In millions)
Operating revenues	$	773.7		$	789.9	$	683.8		$	718.9	$	695.5
Operating expenses	$	650.6		$	765.0	$	637.0		$	633.8	$	621.5
Operating income	$	123.1		$	24.9	$	46.8		$	85.1	$	74.0
Income from continuing operations	$	70.1		$	9.2	$	16.4		$	72.0	$	32.4
Income (loss) from discontinued operations, net of tax	$	(1.0	)	$	1.0	$	(13.9	)	$	9.2	$	1.3
Net income (loss)	$	69.1		$	10.2	$	2.5		$	80.7	$	(81.7	)
Short-term debt	$	—		$	—	$	—		$	53.6	$	—
Long-term debt due within one year (a)		15.5			300.0		—			3.4		65.9
Notes and bonds (a)		—			—		—			—		690.1
Total short-term debt (a)	$	15.5		$	300.0	$	—		$	57.0	$	756.0
Long-term debt (a)	$	519.1		$	385.1	$	684.0		$	715.5	$	28.5
Capital leases		7.4			5.6		8.7			12.2		14.3
Total long-term obligations (a)	$	526.5		$	390.7	$	692.7		$	727.7	$	42.8
Total assets	$	1,744.3		$	1,859.2	$	2,081.4		$	2,073.1	$	2,042.2

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

ALLEGHENY GENERATING COMPANY

Year ended December 31,	2006		2005		2004		2003		2002
(In millions)
Operating revenues	$	65.3	$	66.6	$	69.2	$	70.5	$	64.1
Operating expenses	$	25.6	$	24.8	$	26.1	$	25.4	$	25.8
Operating income	$	39.7	$	41.9	$	43.1	$	45.1	$	38.3
Net income	$	24.8	$	31.1	$	27.4	$	20.8	$	18.6
Short-term debt	$	—	$	—	$	—	$	—	$	55.0
Long-term debt due within one year		—		—		—		—		50.0
Debentures (a)		—		—		—		—		99.3
Total short-term debt (a)	$	—	$	—	$	—	$	—	$	204.3
Long-term debt (a)	$	99.5	$	99.4	$	99.4	$	99.4	$	—
Long-term note payable to parent		—		—		15.0		30.0		—
Total long-term obligations (a)	$	99.5	$	99.4	$	114.4	$	129.4	$	—
Total assets	$	538.0	$	550.2	$	557.2	$	562.4	$	597.6

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

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

	Page No.
EXECUTIVE SUMMARY:
Business Overview	63
Key Indicators and Performance Factors	68
Operating Statistics	70
Primary Factors Affecting Allegheny’s Performance	70
Critical Accounting Policies and Estimates	70
RESULTS OF OPERATIONS:
Allegheny Energy, Inc. and Subsidiaries	74
Monongahela Power Company and Subsidiaries	95
Allegheny Generating Company	105
FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES:
Liquidity and Capital Requirements	106
Asset Sales	110
Dividends	111
Other Matters Concerning Liquidity and Capital Requirements	111
Cash Flows	114
Financing	119
Credit Ratings	120
RECENT ACCOUNTING PRONOUNCEMENTS	120

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

Overview

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

Allegheny has two business segments:

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

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

The Delivery and Services Segment

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

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

• 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. See “The Generation and Marketing Segment” below.

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, the purchaser of its electric T&D operations in Ohio, to serve Monongahela’s former Ohio service territory from January 1, 2006 until May 31, 2007. See “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, and it will own and operate the new transmission line.

• 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. Both ACC and AE Solutions are Delaware corporations. ACC develops fiber-optic projects.

The Generation and Marketing Segment

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

• AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities. AE Supply markets its electric generation capacity to

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various customers and markets. Currently, the majority of the Generation and Marketing segment’s normal operating capacity is committed to supplying certain obligations of the Distribution Companies, 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, in connection with the Asset Swap, AE Supply assigned to Monongahela its obligation to supply generation to meet Potomac Edison’s load obligations in West Virginia.

• AGC was owned approximately 77% by AE Supply and approximately 23% by Monongahela through December 31, 2006. As a result of the Asset Swap, AGC currently 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 1,035 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela.

AE Supply is contractually obligated to provide Potomac Edison and West Penn with the power that they need to meet a majority of their PLR obligations. Monongahela is contractually obligated to provide Potomac Edison with the power that it needs to meet its load obligations in West Virginia. 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 these contractual obligations. See “The Distribution Companies’ Obligations and the PJM Market” below.

For more information regarding 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 employees who provide services to AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures, TrAIL Company and their respective subsidiaries. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had 4,362 employees as of December 31, 2006.

The Distribution Companies’ Obligations and the PJM Market

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

Each of the states in Allegheny’s service territory other than West Virginia has, to some extent, deregulated its electric utility industry. Pennsylvania, Maryland and Virginia have instituted retail customer choice and are transitioning to market-based, rather than cost-based pricing for generation, although recent legislation under consideration in Virginia proposes some degree of re-regulation. 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.

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

• Potomac Edison.  In Maryland, the transition period for residential customers ends on December 31, 2008. The transition period for commercial and industrial customers ended on December 31, 2004. The generation rates that Potomac Edison charges residential customers in Maryland are capped through December 31, 2008, while the T&D rate caps for all customers expired on December 31, 2004. A statewide settlement approved by the Maryland PSC in 2003 extends Potomac Edison’s obligation to provide residential SOS at market prices beyond the expiration of the transition periods. In December 2006, Potomac Edison proposed a rate stabilization and transition plan for its residential customers in Maryland that is intended to gradually transition customers from capped generation rates to generation rates based on market prices while at the same time preserving for customers the benefit of previous rate caps. In Virginia, the transition period ends on December 31, 2010. See “Business—Regulatory Framework Affecting Allegheny” above.

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

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

Potomac Edison and West Penn have contracts with AE Supply under which AE Supply provides Potomac Edison and West Penn with the majority of the power necessary to meet their PLR obligations. Effective January 1, 2007, AE Supply assigned to Monongahela the power supply agreement with Potomac Edison to meet Potomac Edison’s load obligations in West Virginia in connection with the Asset Swap.

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 the power that they generate into the PJM market and purchase from the PJM market the power necessary to meet their obligations to supply power.

In connection with the sale of its electric T&D assets in Ohio, Monongahela agreed to sell power at a fixed price to Columbus Southern to serve Monongahela’s former Ohio service territory from January 1, 2006 through May 2007. Monongahela purchases the power required to meet this obligation from the PJM market.

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

For a more detailed discussion, see “Business—Fuel, Power and Resource Supply” and “Business—Regulatory Framework Affecting Allegheny” above.

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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:

• Pursuing 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 a new, 240-mile extra high-voltage transmission line extending from southwestern Pennsylvania, through West Virginia and possibly Maryland to northern Virginia, 210 miles of which is to be located in the Distribution Companies’ PJM zone. The line is 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 the line that will be located in the Distribution Companies’ PJM zone. Additionally, FERC approved four incentive rate treatments, which are intended to promote the construction of transmission facilities, for the transmission line, and PJM has requested that the DOE designate the project as a National Interest Electric Transmission Corridor. Allegheny currently is in the process of siting the transmission line and will seek requisite permits and regulatory approvals. PJM is considering additional transmission expansion initiatives, a number of which, as contemplated, would pass through Allegheny’s service territory.

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

Among other initiatives, AE Supply and Monongahela are currently blending lower-sulfur PRB coal at several generation facilities and are working to implement the financing and construction of Scrubbers at the Hatfield’s Ferry generation facility in Pennsylvania and the Fort Martin generation facility in West Virginia, as well as other pollution control projects at other facilities. In 2006, Monongahela and Potomac Edison received approval from the West Virginia PSC to finance the majority of the cost of constructing Scrubbers at the Fort Martin generation facility through the securitization of a customer charge. Effective January 1, 2007, Allegheny completed the Asset Swap, an intra company transfer of assets that realigned generation ownership and contractual arrangements within the Allegheny system in a manner that will facilitate the proposed securitization and the construction of the Fort Martin Scrubbers. In July 2006, AE Supply entered into construction contracts in connection with its plans to install Scrubbers at its Hatfield’s Ferry generation facility. See “Business—Environmental Matters” and “Business—Electric Facilities” above.

• Managing Transition to Market-based Rates.  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 will gradually move generation rates in Pennsylvania closer to market prices.

Allegheny is actively working to effectively manage a similar transition in Maryland. In December 2006, Allegheny filed a proposal with the Maryland PSC to transition residential customers from capped generation rates to generation rates based on market prices beginning in 2007 and ending in 2010. Under the proposed plan, residential customers would to pay a distribution surcharge beginning on March 31, 2007. The proposed plan, including the application of the surcharge, would 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

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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. Following public hearings, Allegheny filed an alternate proposal that would, among other things, provide customers with the ability to opt out of the surcharge. See “Business—Regulatory Framework Affecting Allegheny” and “Business—Fuel, Power and Resource Supply” above.

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

For example, in July 2006, Monongahela and Potomac Edison filed a request with the West Virginia PSC to increase their West Virginia retail rates by approximately $100 million annually. If approved by the West Virginia PSC, this proposal would result in, among other things, a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a fuel cost recovery clause and a $26 million decrease in base rates.

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 municipal customer loads in Maryland.

• Maximizing Operational Efficiency.  Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation facilities (those that utilize steam pressure in excess of 3,200 pounds per square inch). In 2007, Allegheny expects to complete a program, which it began in 2005, of planned extended maintenance outages at each of its 10 supercritical generating units, targeted at improving availability at those units. The units for which this planned maintenance has been completed already demonstrate improved performance.

Allegheny also is seeking to optimize operations and maintenance costs for its other generation facilities, T&D assets and related corporate functions, to reduce costs and to pursue other productivity improvements necessary to build a high performance organization.

For example, 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 contracts in place for the delivery of approximately 96% of its expected coal needs for 2007. See “Business—Fuel, Power and Resource Supply” above.

Achieving and Maintaining High Customer Satisfaction.  Allegheny continues to see high levels of satisfaction among its customers. For example, in 2006, a leading independent survey firm ranked Allegheny first in customer satisfaction for residential customers in the eastern United States, as well as first among commercial and industrial customers in the northeast.

• Substantially Reducing and Proactively Managing Debt.  Between December 1, 2003 and December 31, 2006, Allegheny restructured much of its debt and reduced debt by approximately $2.425 billion. This restructuring effort included debt reductions of approximately $918 million in 2005 and $517 million in 2006.

Through these restructuring efforts, Allegheny secured more favorable terms and conditions with respect to much of its debt, including reduced interest rates. The resulting reductions in interest expense,

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coupled with the reductions in debt and general improvements in Allegheny’s financial condition, have led to multiple upgrades in Allegheny’s credit ratings. See “Changes in Credit Ratings” below and Note 4, “Capitalization,” to the Consolidated Financial Statements.

• Improving Liquidity.  Allegheny has improved its liquidity through prudent cash management, opportunistic sales of non-core assets, cutting costs and expenses, extending debt maturities and other financing strategies. See “Liquidity and Capital Resources” below and Note 4, “Capitalization,” to the Consolidated Financial Statements.

• Disposing of Non-Core Assets.  Allegheny has reoriented its business to focus on its core businesses and assets. With the 2006 sale of its Gleason generation facility for approximately $23 million and a related receivable for approximately $27 million, Allegheny completed its initiative to sell its significant non-core assets. Since 2004, Allegheny has completed a number of other significant sales of non-core assets, including:

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

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

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

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

In addition, in December 2005, Monongahela sold its electric T&D assets in Ohio for net proceeds of approximately $52 million. See “Liquidity and Capital Resources—Asset Sales” below and Note 7, “Discontinued Operations,” to the Consolidated Financial Statements.

Management’s priorities for 2007 include continued focus on improving operations, managing the transition to market-based rates and expanding Allegheny’s transmission system.

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 2006, 2005 and 2004 was as follows:

	2006		2005		2004
Revenue per MWh sold	$	58.62	$	55.32	$	54.48

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.

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

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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 various unit groupings.

Equivalent Availability Factor (“EAF”).    The EAF measures the percentage of time that a generation unit is available to generate electricity if called upon in the marketplace. A unit’s availability is commonly less than 100%, primarily as a result of unplanned outages or scheduled outages for planned maintenance. Allegheny monitors EAF by individual unit, as well as by various unit groupings. One such grouping is all “supercritical” units. A supercritical unit utilizes steam pressure in excess of 3,200 pounds per square inch, 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 maintenance costs consist of normal recurring expenses related to the day-to-day on-going operation of the generation facility. Special maintenance includes outage related maintenance and projects that relate to all of the generating facilities.

The following table shows kWhs generated, EAFs and Station O&M related to the Generation and Marketing segment:

	2006			2005			2004			2006 % Increase (Decrease)		2005 % Increase (Decrease)
Supercritical Units:
EAF		84.3	%		82.8	%		75.6	%	1.5	%	7.2	%
Station O&M (in millions):
Base operations (a)	$	99.2		$	101.6		$	102.4		(2.4	)%	(0.8	)%
Special		79.2			95.1			99.5		(16.7	)%	(4.4	)%
Total Station O&M	$	178.4		$	196.7		$	201.9		(9.3	)%	(2.6	)%
All Generation Units:
kWhs generated (in millions)		48,606			48,100			46,162		1.1	%	4.2	%
EAF		86.9	%		85.4	%		82.4	%	1.5	%	3.0	%
Station O&M (in millions):
Base operations (a)	$	155.8		$	167.6		$	169.7		(7.0	)%	(1.2	)%
Special		91.3			113.9			125.6		(19.8	)%	(9.3	)%
Total Station O&M	$	247.1		$	281.5		$	295.3		(12.2	)%	(4.7	)%

(a) Reflects the reclassification of certain costs as described in Note 1, “Basis of Presentation,” to Allegheny’s Consolidated Financial Statements.

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Operating Statistics

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

	2006	2005	2004	2006 % Change		2005 % Change
Retail electricity sales (million kWhs)	43,179	48,275	47,201	(10.6	)%	2.3	%
HDD (a)	4,861	5,333	5,205	(8.9	)%	2.5	%
CDD (a)	781	1,087	789	(28.2	)%	37.8	%

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

Primary Factors Affecting Allegheny’s Performance

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

• changes in regulatory policies and rates,

• changes in the competitive electricity marketplace,

• coal plant availability,

• weather conditions,

• environmental compliance costs,

• changes in the PJM market, rules and policies,

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

• cost of fuel (natural gas and coal),

• wholesale commodity prices and

• labor costs.

Critical Accounting Policies and Estimates

Use of Estimates:  Allegheny prepares its financial statements in accordance with GAAP. Application of these accounting principles often requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure during the reporting period. Allegheny regularly evaluates its estimates, including those related to the calculation of the fair value of commodity contracts and derivative instruments, unbilled revenues, goodwill, provisions for depreciation and amortization, regulatory

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assets and liabilities, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Allegheny develops its estimates using GAAP on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

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

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

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

Excess of Cost Over Net Assets Acquired (Goodwill):  The goodwill of $367.3 million at December 31, 2006 and December 31, 2005 is associated with the 2001 acquisition of Allegheny’s former energy trading business and was attributable to the Generation and Marketing segment. There were no additions to, or disposals of, goodwill during 2006 and 2005. Allegheny tests goodwill for impairment at least annually. The annual impairment test used a discounted cash flow methodology to determine the fair value of the Generation and Marketing segment and indicated no impairment of goodwill. This test result reflects that AE Supply’s fleet of generation facilities, comprised primarily of low-cost coal-fired steam generation facilities, has a fair value in excess of the carrying value of those assets sufficient to cover goodwill, and no impairment of goodwill is required.

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 cycle 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. The unbilled revenue estimates are based on daily generation, purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses and the most recent consumer rates. A change in these estimates and assumptions could have a significant effect on Allegheny’s consolidated results of operations and financial position. A provision for uncollectible amounts is recorded as a component of operations and maintenance expense.

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Regulatory Accounting:  The Distribution Companies are subject to regulations that set the rates that they are permitted to charge customers. These rates are based on costs that the regulatory agencies determine the Distribution Companies 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. A change in these estimates and assumptions could have a significant effect on Allegheny’s results of operations and financial position.

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

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

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The following table shows the effect that a one percentage point increase or decrease in the 6.0% discount rate and the 8.25% expected rate of return, net of administrative expenses, on plan assets for 2007 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	$	(149.9	)	$	182.9
Net periodic pension and OPEB cost	$	(12.0	)	$	14.2
Change in expected rate of return on plan assets:
Net periodic pension and OPEB cost	$	(9.7	)	$	9.7

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 consistent with the development of 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, and no gain or loss is recognized. Replacements of minor items of property are expensed as maintenance.

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With the assistance of an independent third party, 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.

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

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

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ALLEGHENY ENERGY, INC.—RESULTS OF OPERATIONS

Income (Loss) Summary

(In millions)	Delivery and Services			Generation and Marketing
2006							Eliminations			Total
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
2005
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

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(In millions)	Delivery and Services			Generation and Marketing
2004							Eliminations			Total
Operating revenues	$	2,764.1		$	1,538.7		$	(1,546.7	)	$	2,756.1
Fuel		—			634.1			—			634.1
Purchased power and transmission		1,779.0			86.2			(1,536.8	)		328.4
Gain on sale of OVEC power agreement and shares		—			(94.8	)		—			(94.8	)
Deferred energy costs, net		0.2			—			—			0.2
Operations and maintenance		404.3			404.4			(9.9	)		798.8
Depreciation and amortization		148.8			150.6			—			299.4
Taxes other than income taxes		128.5			72.3			—			200.8
Total operating expenses		2,460.8			1,252.8			(1,546.7	)		2,166.9
Operating income		303.3			285.9			—			589.2
Other income and expenses, net		23.1			1.7			(0.3	)		24.5
Interest expense and preferred dividends		129.2			276.2			(0.2	)		405.2
Income from continuing operations before income taxes and minority interest		197.2			11.4			(0.1	)		208.5
Income tax expense (benefit) from continuing operations		79.9			(0.2	)		—			79.7
Minority interest in net loss of subsidiaries		—			(0.9	)		—			(0.9	)
Income from continuing operations		117.3			12.5			(0.1	)		129.7
Loss from discontinued operations, net of tax		(14.0	)		(426.4	)		0.1			(440.3	)
Net income (loss)	$	103.3		$	(413.9	)	$	—		$	(310.6	)

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ALLEGHENY ENERGY, INC.—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 $83.6 million in 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 effective January 1, 2006 as a result of a West Penn settlement approved by the Pennsylvania PUC,

• 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 kWh net of lost T&D revenues and

• increased MWhs generated.

The above increases were partially offset by a decrease in average market prices, the March 2006 assignment of AE Supply’s rights to generation from 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 revenues increased $281.8 million in 2005 compared to 2004, primarily due to:

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

• increased generation revenue due to warmer summer weather and higher PJM market prices during 2005, which enabled the dispatch of some of Allegheny’s smaller coal and gas generation facilities,

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

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

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

Operating Income

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.

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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, decreased cost of goods sold and services expenses, primarily due to reductions in costs associated with a completed construction services project and decreased salaries and wages expense due 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.

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

• a $334.2 million increase in operating expenses,

• partially offset by the $281.8 million increase in operating revenues discussed above.

Operating expenses increased primarily as a result of a non-recurring $94.8 million gain on the sale of a portion of AE’s equity interest in OVEC recorded during 2004, a $29.3 million loss recorded in 2005 in connection with the sale of Monongahela’s Ohio T&D assets, increases in fuel expense and purchased power and transmission expense. These increases were partially offset by a $63.6 million decrease in operations and maintenance expense. Fuel expense increased due to increased coal prices and an increase in MWhs generated at Allegheny’s coal-fired generation facilities. Purchased power and transmission expense increased as a result of the commencement in 2005 of market-based purchase contracts for large commercial and industrial customers in Maryland, increased prices to serve commercial and industrial customers in Ohio and increased MWhs purchased to service PLR load. The qualifying of certain contracts as normal purchase normal sale contracts also contributed to the increase in purchased power and transmission expense. Operations and maintenance expense decreased due to decreased contract work, primarily resulting from the receipt of insurance recoveries related to Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1, decreased outside service expense due to a reduction in the use of outside consultants and decreased insurance expenses as a result of reduced claims and lower premiums. These decreases were partially offset by increased special maintenance for planned and unplanned outages during the fourth quarter of 2005.

Income from Continuing Operations Before Income Taxes and Minority Interest

Income from continuing operations before income taxes and minority interest increased $354.3 million in 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.

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Income from continuing operations before income taxes and minority interest decreased $68.0 million in 2005 compared to 2004, primarily due to:

• the $52.4 million decrease in operating income discussed above and

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

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

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

Income Tax Expense

The effective tax rates for Allegheny's continuing operations were 35.0%, 44.8% and 37.3% for 2006, 2005 and 2004, respectively.

Income tax expense for 2006 was approximately equal to tax expense calculated at the federal statutory rate; however the following significant items occurred during the year:

• a change in Pennsylvania tax law enacted in July 2006 increased the availability of net operating loss carryforwards resulting in an $18.2 million decrease in income tax expense,

• which was partially offset by an increase in expense of $6.6 million for the effects of the results of prior year audit settlements.

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

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

• a $3.8 million charge to adjust state deferred income tax assets relating to 2003, as described in Note 11, “Income Taxes,” to the Consolidated Financial Statements and

• a $1.9 million charge to adjust state deferred income tax assets resulting from a change in Ohio tax law, as described in Note 11, “Income Taxes,” to the Consolidated Financial Statements,

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

See Note 11, “Income Taxes,” for additional information.

Discontinued Operations

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 and $440.3 million for the years ended December 31, 2005 and 2004, respectively, related to agreements to sell, or decisions to sell, certain non-core assets.

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

The $434.2 million decrease in losses from discontinued operations, net of tax in 2005 compared to 2004 was primarily due to approximately $425 million of net impairment charges recorded during the third and fourth quarters of 2004 related to AE Supply’s natural gas-fired peaking facilities and Monongahela’s West Virginia natural gas operations.

See Note 7, “Discontinued Operations,” for additional information.

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

Delivery and Services

The following table provides retail electricity sales information.

	2006	2005	2004	2006 % Change		2005 % Change
Retail electricity sales (million kWhs)	43,179	48,275	47,201	(10.6	)%	2.3	%
HDD (a)	4,861	5,333	5,205	(8.9	)%	2.5	%
CDD (a)	781	1,087	789	(28.2	)%	37.8	%

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

Operating Revenues

Operating revenues were as follows:

(In millions)	2006		2005		2004
Retail electric:
Generation	$	1,688.0	$	1,783.9	$	1,732.9
Transmission		160.3		176.0		178.6
Distribution		682.8		711.0		660.1
Total retail electric		2,531.1		2,670.9		2,571.6
Transmission services and bulk power		150.7		115.9		127.8
Other affiliated and nonaffiliated energy services		35.9		58.7		64.7
Total Delivery and Services revenues	$	2,717.7	$	2,845.5	$	2,764.1

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

• a $95.9 million decrease in generation revenue 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 decease 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.

• a $43.9 million decrease in T&D revenues primarily as a result of an $8.8 million decrease in revenue from 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.

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

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

• a $22.8 million aggregate increase in generation revenues as a result of increased customer usage due to increased HDD and CDD,

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

• a $50.9 million increase in distribution revenues as a result of increased usage due to warmer summer weather, a 1.3% increase in the average number of customers and the expiration of certain customer choice credits in West Virginia that were in effect during 2004.

The above increases were partially offset by a $34.5 million decrease due to the choice by certain Potomac Edison customers of alternate electricity generation providers, a significant reduction in electric usage by one industrial customer related to the curtailment of its operations in December 2005 and an $8.9 million decrease in revenues associated with the AES Warrior Run surcharge in Maryland, as described below under the heading, “AES Warrior Run PURPA Generation.”

Retail electric revenues include transmission and distribution revenues from customers who chose alternate generation suppliers. Less than 1% of Allegheny’s retail customers in Pennsylvania, Maryland and Virginia in 2006 and in Pennsylvania, Maryland, Virginia and Ohio in 2005 and 2004 chose alternate electricity generation suppliers. If a retail customer is served by an alternate electricity supplier, the transmission revenue is reflected in transmission and bulk power revenues.

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

Transmission services and bulk power revenues increased by $34.8 million in 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.

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

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

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

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

Other affiliated and nonaffiliated energy services revenues decreased $22.8 million in 2006 compared to 2005 and decreased $6.0 million in 2005 compared to 2004, 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), as well as purchases from qualifying facilities under PURPA. Purchased power and transmission consists of the following items:

(In millions)	2006		2005		2004
Other purchased power and transmission	$	1,569.2	$	1,669.7	$	1,581.2
From PURPA generation (a)		203.8		209.0		197.8
Total purchased power and transmission	$	1,773.0	$	1,878.7	$	1,779.0
(a) PURPA cost (cents per kWh sold)		5.4		5.3		5.2

West Penn and Potomac Edison have power purchase agreements with AE Supply, under which AE Supply provides West Penn and Potomac Edison with the majority of the power necessary to meet their PLR obligations. These agreements have both fixed-price and market-based pricing components. The amount of power purchased under certain of these agreements that is subject to the market-based pricing component generally increases each year through the applicable transition period. 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, effective January 1, 2007, Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela at overall Monongahela generation costs.

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. As part of the Asset Swap, effective January 1, 2007 and 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 its contractual obligations.

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

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

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

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

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• 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,

• 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 West Penn settlement with 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.

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

Purchased power from PURPA generation decreased $5.2 million in 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.

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

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, were as follows:

(In millions)	2006		2005			2004
Deferred energy costs, net	$	7.6	$	(1.5	)	$	0.2

Deferred energy costs, net, are primarily related to the recovery of net costs associated with purchases from the AES Warrior Run PURPA generation facility and the deferral of market-based generation costs, as described in the following sections under the headings “AES Warrior Run PURPA Generation,” “Grant Town PURPA Generation facility” and “Market-based Generation Costs.”

AES Warrior Run PURPA Generation

To satisfy certain of its obligations under PURPA, Allegheny, through 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 on Potomac Edison’s Consolidated Balance Sheets as deferred energy costs, pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge. Because the AES Warrior Run Surcharge represents a dollar-for-dollar recovery of net contract costs, AES Warrior Run Surcharge revenues or revenues from sales of AES Warrior Run output do not impact Potomac Edison’s net income.

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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 provides for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia PSC authorized Monongahela and Potomac Edison 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 will be tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge.

Market-based Generation Costs

Potomac Edison is authorized by the Maryland PSC to recover 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 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 increased $9.1 million in 2006 compared to 2005, primarily as a result of a $6.7 million increase in deferred costs related to the PURPA facilities described above and a $4.0 million increase in deferred costs related to market-based generation.

Deferred energy costs, net decreased $1.7 million in 2005 compared with 2004, primarily as a result of a $1.0 million decrease in deferred costs related to the PURPA facilities described above and a $0.7 million decrease in deferred costs related to market-based generation.

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)	2006		2005		2004
Operations and maintenance	$	344.0	$	388.5	$	404.3

Operations and maintenance expenses decreased $44.5 million in 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 services expenses, primarily due to costs associated with the implementation of Allegheny’s information technology initiatives.

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

• a $3.4 million decrease in salaries and wages as a result of decreases in the number of employees and decreases in severance costs,

• a $4.8 million decrease in contract work and outside services as a result of a reduction in the use of outside consultants, partially offset by certain costs associated with the implementation of Allegheny’s information technology initiatives,

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

• a $4.2 million decrease in uncollectible expense due to improved collections and increased use of security deposits,

• a $9.8 million decrease in cost of goods sold due to reductions in equipment procurement and subcontracting costs associated with a construction services project that was completed during the second quarter of 2006 and

• an $8.6 million decrease in insurance expenses resulting from a decrease in the amount of claims and a reduction in the amount of premiums paid,

• partially offset by approximately $15 million associated with an arbitration settlement and a $4.2 million increase in employee benefits expense.

For additional information regarding pension and OPEB expenditures, see Note 10, “Pension Benefits and Postretirement Benefits Other Than Pensions.”

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

(In millions)	2006		2005		2004
Depreciation and amortization	$	151.3	$	153.6	$	148.8

Depreciation and amortization expenses decreased $2.3 million in 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.

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

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

(In millions)	2006		2005		2004
Taxes other than income taxes	$	122.0	$	130.4	$	128.5

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

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

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

(In millions)	2006		2005		2004
Other income and expenses, net	$	22.2	$	24.2	$	23.1

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

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

See Note 20, “Other Income and Expenses, Net,” for additional details.

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

(In millions)	2006		2005		2004
Interest expense and preferred dividends	$	81.4	$	123.3	$	129.2

Interest expense and preferred dividends decreased $41.9 million in 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.

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

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

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

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

See Note 4, “Capitalization,” for additional information regarding Allegheny’s short-term and long-term debt.

Income Tax Expense

The effective tax rate for 2006 was 30.7%. Income tax expense for 2006 was lower than the tax expense calculated at the federal statutory tax rate, 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 tax expense calculated at the federal statutory tax rate, primarily due to the Delivery and Services segment’s share of consolidated tax savings.

The effective tax rate for 2004 was 39.9%. Income tax expense for 2004 was higher than the tax expense calculated at the federal statutory tax rate, primarily due to adjustments to record the effects of prior year tax return adjustments.

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

(In millions)	2006			2005		2004
Income (loss) from discontinued operations, net of tax	$	(1.0	)	$	1.0	$	(14.0	)

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

The $15.0 million decrease in loss from discontinued operations, net of tax in 2005 compared to 2004 was primarily a result of impairment charges on Monongahela’s West Virginia natural gas operations of $21.7 million, net of tax, recorded during 2004, compared to impairment charges on these assets of $7.0 million, net of tax, recorded during 2005.

See Note 7, “Discontinued Operations,” for additional information.

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Generation and Marketing:

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

	2006	2005	2004	2006 Change		2005 Change
Generation (million kWhs)	48,606	48,100	46,162	1.1	%	4.2	%

Operating Revenues

Operating revenues were as follows:

(In millions)	2006		2005		2004
Revenue from affiliates	$	1,423.2	$	1,501.5	$	1,491.8
Wholesale and other, net (a)		411.2		201.8		46.9
Total revenues	$	1,834.4	$	1,703.3	$	1,538.7

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

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

AE Supply 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. The amount of power sold under certain of these agreements that is subject to the market-based pricing component generally increases each year through the applicable transition period. 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, effective January 1, 2007, Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela at overall Monongahela generation costs.

Through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela sold the power that it generates 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. As part of the Asset Swap, effective January 1, 2007 and 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 its contractual obligations.

See Note 26, “Subsequent Event—Asset Swap,” for additional information.

The average rate at which the Generation and Marketing segment sold power to the Distribution Companies was $35.17, $33.01 and $32.41 per MWh for the years ended December 31, 2006, 2005 and 2004, respectively.

Revenue from affiliates decreased $78.3 million in 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,

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• 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.

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

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

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

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

Wholesale and other revenues, net:  The table below describes the significant components of wholesale revenues.

(In millions)	2006			2005 (a)			2004 (a)
PJM Revenue:
Generation sold into PJM	$	2,055.4		$	2,536.1		$	1,837.9
Power purchased from PJM		(1,662.4	)		(2,335.9	)		(1,916.5	)
Net		393.0			200.2			(78.6	)
Release of escrow proceeds		—			2.7			68.1
Cash flow hedges and trading activities:
Realized gains (losses)		(27.2	)		(24.9	)		59.9
Unrealized gains (losses)		32.4			20.6			(5.7	)
Net		5.2			(4.3	)		54.2	(b)
Other revenues		13.0			3.2			3.2
Total wholesale and other revenues	$	411.2		$	201.8		$	46.9

(a) Certain prior period amounts were reclassified from other revenues to power purchased from PJM to conform to the presentation in the current period.

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

Wholesale and other revenues increased $209.4 million in 2006 compared to 2005, primarily due to:

• an increase in net PJM revenues of $192.8 million,

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• a $9.5 million increase in net gains on cash flow hedges and trading revenues, primarily related to the settlement of cash flow hedges, partially offset by losses on mark-to-market purchase contracts and a reduction in contracts that were designated as normal purchase and normal sale during 2006 and

• a $9.8 million increase in other revenues, primarily due to the sales of other external load following contracts within the Allegheny Power service territory, the receipt of insurance proceeds related to the 2005 unplanned outage at Hatfield’s Ferry Unit No. 2 and proceeds from the sales of excess PRB coal,

• partially offset by a $2.7 million decrease related to the release of escrow proceeds during the third quarter of 2005 due to the release of a guarantee liability.

The increase in net PJM revenues is 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.

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

• a $278.8 million increase in net PJM revenues,

• partially offset by the receipt of $68.1 million associated with the sale of the CDWR contract and related hedge transactions that were recorded during 2004, $2.7 million related to the release of a guarantee liability during 2005 and a $58.5 million decrease in gains from trading activities, primarily due to the expiration on December 31, 2004 of an affiliated contract to sell the output from the AES Warrior Run PURPA generation facility into the wholesale market, which resulted in non-affiliated revenues of $51.7 million for 2004.

The increase in net PJM revenues is due to higher generation revenues relative to the cost to serve the PLR load. During 2005, the weighted average “round-the-clock” price for power in Allegheny’s region of PJM, the APS Zone of the PJM market, was approximately $58.50 per MWh, which represents an increase of approximately 45% compared to 2004. Also during 2005, total MWhs generated increased by 4.2% compared to 2004. This increase in total MWhs generated was due to increased average market prices and increased availability of Allegheny’s coal-fired plants as a result of the return to service of Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 in June 2004. In addition, power purchased from PJM expense increased due to higher average market prices, partially offset by lower MWhs as a result of no longer serving certain customer classes, primarily Potomac Edison’s commercial and industrial customers in Maryland. The Generation and Marketing segment also did not serve Monongahela’s large commercial and industrial customers in Ohio in 2005.

Fair Value of Contracts:  Allegheny qualifies certain of its commodity contracts under the “normal purchase and normal sale” scope exception under SFAS No. 133. As a result, Allegheny accounts for these contracts on the accrual method, rather than marking these contracts to market value. Allegheny uses derivative accounting for energy contracts that do not qualify under the scope exception. These energy contracts are recorded at fair value, which represents the net unrealized gain and loss on open positions, in the Consolidated Balance Sheets, after applying the appropriate counterparty netting agreements. The realized and unrealized revenues from energy trading activities are recorded on a net basis in “Operating revenues” in the Consolidated

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Statements of Operations. The fair value of the remaining trading portfolio consists primarily of interest rate swap agreements as of December 31, 2006. Changes in the fair value of the commodity cash flow hedges are reflected in other comprehensive income.

At December 31, 2006, the fair values of derivative contract assets and liabilities were $1.5 million and $24.0 million, respectively. At December 31, 2005, the fair values of derivative contract assets and liabilities were $9.3 million and $115.9 million, respectively.

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 AE Supply’s generation assets, PLR requirements and SFAS No. 133 scope exceptions under the normal purchase and normal sale election:

	Fair value of contracts at December 31, 2006
Classification of contracts by source of fair value (In millions)	Settlement by:
	2007			2008			2009			2010			2011			Total
Prices actively quoted	$	(4.5	)	$	(5.7	)	$	(5.4	)	$	(5.2	)	$	(1.7	)	$	(22.5	)
Prices provided by other external sources		—			—			—			—			—			—
Prices based on models		—			—			—			—			—			—
Total	$	(4.5	)	$	(5.7	)	$	(5.4	)	$	(5.2	)	$	(1.7	)	$	(22.5	)

The fair value of AE Supply’s contracts that are scheduled to settle by December 31, 2007 was a net liability of $4.5 million, primarily related to interest rate swaps.

See Note 5, “Derivative Instruments and Hedging Activities,” for additional information.

Changes in Fair Value:    Net unrealized gains of $32.4 million and $20.6 million in 2006 and 2005, respectively, were recorded on the Consolidated Statements of Operations in “Operating revenues” to reflect the change in fair value of the derivative contracts. The following table provides a summary of changes in the net fair value of AE Supply’s derivative contracts:

(In millions)	2006			2005
Net fair value of derivative contract liabilities at January 1,	$	(106.6	)	$	(80.1	)
Changes in fair value of cash flow hedges		51.7			(47.1	)
Unrealized gains on contracts, net		32.4			20.6
Net fair value of derivative contract liabilities at December 31,	$	(22.5	)	$	(106.6	)

As shown in the table above, the net fair value of AE Supply’s derivative contracts increased by $84.1 million in 2006, compared to 2005. The increase in the fair value was primarily due to settlements on interest rate and cash flow commodity contracts and changes in the fair values of commodity contracts.

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)	2006		2005		2004
Fuel	$	842.7	$	759.1	$	634.1

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Total fuel expense increased by $83.6 million in 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.

Total fuel expense increased by $125.0 million in 2005 compared to 2004, primarily due to a $114.3 million increase in coal expense. The increase in coal expense was due to an increase in the average price of coal of approximately $4.50 per ton, from approximately $30.00 per ton to approximately $34.50 per ton, and a 1.2 million ton increase in the amount of coal burned. The increase in the amount of coal burned was primarily due to a 4.2% increase in total MWhs generated as a result of increased availability at Allegheny’s coal-fired plants.

See Note 1, “Basis of Presentation,” for information regarding a reclassification made between “Operations and maintenance” expense and “Fuel” expense during 2006.

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

(In millions)	2006		2005		2004
Purchased power and transmission	$	33.2	$	81.0	$	86.2

Purchased power and transmission expenses decreased $47.8 million in 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.

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

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 and recorded a total gain on the sale of $94.8 million. During 2006, AE recorded an additional $6.1 million gain, which represents the release of escrowed proceeds due to the fulfillment of certain post-closing commitments.

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)	2006		2005		2004
Operations and maintenance	$	349.0	$	356.2	$	404.4

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

• a $14.5 million decrease in other operation and maintenance expense, primarily due to $6.4 million reversal of a guarantee liability associated with the Hunlock Creek Energy Ventures (“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,

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• 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 and increased planned maintenance costs and an $8.0 million increase in outside services expense associated with the implementation of Allegheny’s information technology initiatives.

Operations and maintenance expenses decreased $48.2 million in 2005 compared to 2004, primarily due to:

• a $37.2 million decrease in contract work and outside services expenses as a result of the receipt of insurance recoveries related to Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 and decreased outside services expense due to a reduction in the use of outside consultants,

• a $6.4 million decrease in insurance expense as a result of reduced claims and lower premiums and

• a $4.8 million decrease in rent expense as the result of certain non-recurring impairment charges recorded during 2004 related to New York office space and lease cancellation fees incurred during 2004.

See Note 22, “Guarantees and Letters of Credit” and Note 24, “HCEV Partnership Interest,” for additional information related to the HCEV partnership interest transaction. See Note 1, “Basis of Presentation,” for information regarding a reclassification made between “Operations and maintenance” expense and “Fuel” expense during 2006.

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

(In millions)	2006		2005		2004
Depreciation and amortization	$	121.8	$	154.6	$	150.6

Depreciation and amortization expense decreased $32.8 million in 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 3, “Review of Estimated Remaining Service Lives and Depreciation Practices.”

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

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

(In millions)	2006		2005		2004
Taxes other than income taxes	$	81.3	$	82.1	$	72.3

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

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

• a $3.7 million increase in local property taxes, primarily due to favorable settlements recorded during 2004 and

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

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

(In millions)	2006		2005		2004
Other income and expenses, net	$	14.8	$	21.1	$	1.7

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Other income and expenses, net decreased $6.3 million in 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.

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

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

(In millions)	2006		2005		2004
Interest expense and preferred dividends	$	193.1	$	318.2	$	276.2

Interest expense and preferred dividends decreased $125.1 million in 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.

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

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

• $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

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

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

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

For additional information regarding Allegheny’s short-term and long-term debt, see Note 4, “Capitalization.” For additional information regarding the litigation involving Merrill Lynch, see Note 25, “Commitments and Contingencies.”

Income Tax Expense

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

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The effective tax rate for 2005 was (37.7)%. The effective tax rate was due to income tax expense on losses from continuing operations before income taxes and minority interest due to net operating loss carryforward rules and the Generation and Marketing segment’s share of consolidated tax savings.

The effective tax rate for 2004 was (2.1)%. The effective tax rate was due to an income tax benefit recorded on income from continuing operations before income taxes and minority interest due to the Generation and Marketing segment’s share of consolidated tax savings and adjustments to record the effects of prior year tax return adjustments.

Minority Interest:  Minority interest, which primarily represents an equity interest in AE Supply, was $2.6 million, $0.6 million and $(0.9) million in 2006, 2005 and 2004, respectively.

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

(In millions)	2006		2005			2004
Income (loss) from discontinued operations, net of tax	$	1.6	$	(7.2	)	$	(426.4	)

Loss from discontinued operations, net of tax decreased $8.8 million in 2006 compared to 2005, primarily due to increased income reflecting adjustments associated with the sale 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.

Loss from discontinued operations, net of tax decreased $419.2 million in 2005 compared to 2004, primarily due to approximately $404 million of impairment charges that were recorded during the third quarter of 2004 related to AE Supply’s natural gas-fired peaking facilities.

See Note 7, “Discontinued Operations,” for additional information.

Cumulative Effect of Accounting Changes, Net:  In connection with its adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations (“FIN 47”), Allegheny recorded a charge of $5.9 million, net of income taxes, as the cumulative effect of an accounting change as of December 31, 2005.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES—RESULTS OF OPERATIONS

Income (Loss) Summary

(In millions)	Delivery and Services			Generation and Marketing			Eliminations			Total
2006
Operating revenues	$	674.9		$	401.1		$	(302.3	)	$	773.7
Fuel		—			178.0			—			178.0
Purchased power and transmission		413.5			89.2			(302.3	)		200.4
Deferred energy costs, net		(2.0	)		—			—			(2.0	)
Operations and maintenance		96.6			75.5			—			172.1
Depreciation and amortization		30.6			35.0			—			65.6
Taxes other than income taxes		15.7			20.8			—			36.5
Total operating expenses		554.4			398.5			(302.3	)		650.6
Operating income		120.5			2.6			—			123.1
Other income and expenses, net		6.2			9.3			—			15.5
Interest expense		23.5			17.4			—			40.9
Income (loss) from continuing operations before income taxes		103.2			(5.5	)		—			97.7
Income tax expense from continuing operations		25.4			2.2			—			27.6
Income (loss) from continuing operations		77.8			(7.7	)		—			70.1
Loss from discontinued operations, net of tax		(1.0	)		—			—			(1.0	)
Net income (loss)	$	76.8		$	(7.7	)	$	—		$	69.1
2005
Operating revenues	$	691.4		$	415.5		$	(317.0	)	$	789.9
Fuel		—			153.1			—			153.1
Purchased power and transmission		460.9			126.6			(317.0	)		270.5
Loss on sale of Ohio T&D assets		29.3			—			—			29.3
Operations and maintenance		115.5			80.6			—			196.1
Depreciation and amortization		31.5			34.8			—			66.3
Taxes other than income taxes		26.2			23.5			—			49.7
Total operating expenses		663.4			418.6			(317.0	)		765.0
Operating income (loss)		28.0			(3.1	)		—			24.9
Other income and expenses, net		4.2			8.7			—			12.9
Interest expense		25.1			18.3			—			43.4
Income (loss) from continuing operations before income taxes		7.1			(12.7	)		—			(5.6	)
Income tax benefit from continuing operations		(1.3	)		(13.5	)		—			(14.8	)
Income from continuing operations		8.4			0.8			—			9.2
Income from discontinued operations, net of tax		1.0			—			—			1.0
Net income	$	9.4		$	0.8		$	—		$	10.2

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(In millions)	Delivery and Services			Generation and Marketing			Eliminations			Total
2004
Operating revenues	$	669.0		$	312.8		$	(298.0	)	$	683.8
Fuel		—			123.5			—			123.5
Purchased power and transmission		428.5			57.0			(298.0	)		187.5
Operations and maintenance		117.9			92.2			—			210.1
Depreciation and amortization		31.4			34.4			—			65.8
Taxes other than income taxes		27.0			23.1			—			50.1
Total operating expenses		604.8			330.2			(298.0	)		637.0
Operating income (loss)		64.2			(17.4	)		—			46.8
Other income and expenses, net		2.4			6.7			—			9.1
Interest expense		24.8			18.5			—			43.3
Income (loss) from continuing operations before income taxes		41.8			(29.2	)		—			12.6
Income tax expense (benefit) from continuing operations		11.4			(15.2	)		—			(3.8	)
Income (loss) from continuing operations		30.4			(14.0	)		—			16.4
Loss from discontinued operations, net of tax		(13.9	)		—			—			(13.9	)
Net income (loss)	$	16.5		$	(14.0	)	$	—		$	2.5

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MONONGAHELA POWER COMPANY—CONSOLIDATED RESULTS

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

Operating Revenues

Operating revenues decreased $16.2 million in 2006 compared to 2005, primarily due to:

• decreased revenues related to a decrease in average market prices and

• decreased revenues related to milder weather and lower industrial customer usage,

• partially offset by Monongahela’s agreement to provide power to Columbus Southern as of January 1, 2006 under a fixed price power supply agreement at a higher rate per kWh net of lost T&D revenues and increased MWhs generated.

Operating revenues increased $106.1 million in 2005 compared to 2004, primarily due to:

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

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

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

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

Operating Income

Operating income increased $98.2 million in 2006 compared to 2005, due to:

• a $114.4 million decrease in operating expenses,

• partially offset by the $16.2 million decrease in total operating revenues discussed above.

The decrease in total operating expenses was primarily due to a $70.1 million decrease in purchased power and transmission expenses, primarily as a result of reduced rates on purchased power related to a supply agreement with Columbus Southern to serve Monongahela’s former Ohio service territory and a $29.3 million loss on the sale of Ohio T&D assets that was recorded in 2005.

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

• a $128.0 million increase in operating expenses,

• partially offset by the $106.1 million increase in total operating revenues discussed above.

Operating expenses increased primarily as a result of a $29.3 million loss recorded in connection with the sale of Monongahela’s Ohio T&D assets and increases in fuel and purchased power and transmission expenses.

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These increases were partially offset by decreased operations and maintenance expenses. Fuel expense increased, primarily due to increased coal prices and an increase in MWhs generated at Monongahela’s jointly-owned coal-fired plants. Purchased power and transmission expense increased, primarily due to congestion charges and increases in the prices for purchased power from PJM for Monongahela’s large commercial and industrial customers in Ohio. Operations and maintenance expense decreased, primarily due to decreased contract work resulting from insurance recoveries related to Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 and decreased outside services expense due to a reduction in the use of outside consultants, as well as reduced salaries and wages expense due to a decreased number of employees.

Income from Continuing Operations Before Income Taxes

Income from continuing operations before income taxes increased $103.3 million in 2006 compared to 2005, primarily due to the $98.2 million increase in operating income discussed above.

Income from continuing operations before income taxes decreased $18.2 million in 2005 compared to 2004, primarily due to the $21.9 million decrease in operating income discussed above.

Income Tax Expense

The effective tax rates for Monongahela's continuing operations were 28.2%, 264.3% and (30.2)% for 2006, 2005 and 2004, respectively.

Income tax expense for 2006 was lower than the income tax expense calculated at the federal statutory rate primarily due to allocation of consolidated tax savings to Monongahela.

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

• the allocation of consolidated tax savings to Monongahela and

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

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

See Note 8, “Income Taxes,” for additional information.

Discontinued Operations

Monongahela recorded income (loss) from discontinued operations, net of tax of $(1.0) million, $1.0 million and $(13.9) million in 2006, 2005 and 2004, respectively, relating to Monongahela’s West Virginia natural gas operations.

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

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

See Note 4, “Discontinued Operations” for additional information.

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MONONGAHELA POWER COMPANY—DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:

Delivery and Services

The following table provides retail electricity sales information:

	2006	2005	2004	2006 Change		2005 Change
Retail electricity sales (million kWhs)	10,351	12,280	12,125	(15.7	)%	1.3	%
HDD (a)	4,444	4,688	4,762	(5.2	)%	(1.6	)%
CDD (a)	780	1,238	786	37.0	%	57.5	%

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

Operating Revenues

Operating revenues were as follows:

(In millions)	2006		2005		2004
Retail electric:
Generation	$	355.7	$	411.5	$	402.7
Transmission		33.8		40.0		39.0
Distribution		185.7		206.2		188.0
Total retail electric		575.2		657.7		629.7
Transmission services and bulk power		89.1		23.9		31.1
Other affiliated and non-affiliated energy services		10.6		9.8		8.2
Total Delivery and Services revenues	$	674.9	$	691.4	$	669.0

Retail electric revenues decreased $82.5 million in 2006 compared to 2005, primarily due to:

• a $55.8 million decrease in generation revenues as a result of a $47.7 million decrease related to the sale of Monongahela’s Ohio service territory on December 31, 2005 and decreased usage due to milder weather and lower industrial customer demand and

• a $26.7 million decrease in T&D revenues primarily as a result of decreased customer usage due to milder weather and the sale of Monongahela’s Ohio service territory on December 31, 2005.

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

• an $8.8 million increase in generation revenues as a result of increased customer usage as a result of warmer summer weather and

• an $18.2 million increase in distribution revenues as a result of increased MWhs sold due to increased customer demand and the expiration of certain customer choice credits in West Virginia that were in effect during 2004.

Transmission services and bulk power increased $65.2 million in 2006 compared to 2005, primarily due to bulk power sales related to a fixed price power supply agreement with Columbus Southern to serve Monongahela’s former Ohio service territory, partially offset by a reduction in transmission revenue related to the expiration of a third-party transmission capacity contract.

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

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Operating Expenses

Purchased Power and Transmission:   Purchased power and transmission consists of the following items:

(In millions)	2006		2005		2004
Other purchased power and transmission	$	351.6	$	403.0	$	371.9
From PURPA generation (a)		61.9		57.9		56.6
Total purchased power and transmission	$	413.5	$	460.9	$	428.5
(a) PURPA cost (cents per kWh)		4.6		4.4		4.3

Other purchased power and transmission primarily consists of Monongahela’s Delivery and Services segment’s purchases of energy from Monongahela’s Generation and Marketing segment to service its load requirements. For further information, see the discussion under the heading “Generation and Marketing” below.

Other purchased power and transmission decreased $51.4 million in 2006 compared to 2005, primarily due to reduced rates on purchased power relating to a supply agreement with Columbus Southern to serve Monongahela’s former Ohio service territory and reduced demand as a result of milder weather and lower industrial customer usage.

Other purchased power and transmission increased $31.1 million in 2005 compared to 2004, primarily due to a 7.4% increase in the price per MWh purchased and an increase in MWhs purchased. The increase in MWhs was the result of customer growth and increased usage, and the increase in price per MWh purchased was due to purchases of power from PJM at higher market prices to meet the needs of Monongahela’s large commercial and industrial customers in Ohio. Purchased power and transmission in 2006 included $66.2 million of costs associated with serving commercial and industrial customers in Ohio, from PJM.

Purchased power from PURPA generation increased $4.0 million in 2006 compared to 2005, primarily due to an increase in rates at the Grant Town PURPA generation facility.

Loss on Sale of Ohio T&D Assets:  During 2005, Monongahela recorded a $29.3 million loss on the sale of its Ohio T&D assets. This loss was based on the estimated value 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 estimated net book value of the assets at the time of closing and approximately $2.0 million in expenses associated with the sale.

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

(In millions)	2006			2005		2004
Deferred energy costs, net	$	(2.0	)	$	—	$	—

Deferred energy costs, net, are primarily related to the recovery of net costs associated with purchases from the Grant Town PURPA generation facility, as described in the following section under the heading “Grant Town PURPA Generation facility.”

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 provides for an increase in the price of energy that Monongahela is acquiring until 2017.

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The West Virginia PSC authorized Monongahela and Potomac Edison 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 will be tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge.

Deferred energy costs, net decreased $2.0 million for the 2006 compared to 2005, primarily as a result of decreased deferred costs related to the Grant Town PURPA generation facility.

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)	2006		2005		2004
Operations and maintenance	$	96.6	$	115.5	$	117.9

Operations and maintenance expenses decreased $18.9 million in 2006 compared to 2005, primarily due to:

• a $9.6 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, an October 2005 snowstorm, which did not recur in 2006 and a reduction in employees due to the sale of the Ohio T&D assets on December 31, 2005, partially offset by certain outside service costs associated with the outsourcing of Allegheny’s information technology function,

• a $3.3 million decrease in contract expenses related to vegetation control due to a decrease in tree trimming during 2006,

• a $2.9 million decrease in contract work related to an October 2005 snowstorm, which did not recur in 2006 and

• a $1.6 million environmental insurance settlement and release.

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

• a $1.4 million decrease in contract expenses related to vegetation control due to a decrease in contractor expenditures resulting from a decrease in the size of the area covered during 2005 and

• a $2.4 million decrease in insurance expense as a result of reduced claims and lower premiums,

• partially offset by a $1.5 million increase in other service expenses as a result of costs associated with transition services relating to the sale of Monongahela’s West Virginia natural gas operations in 2005.

Taxes Other Than Income Taxes:  Taxes other than income taxes were as follows:

(In millions)	2006		2005		2004
Taxes other than income taxes	$	15.7	$	26.2	$	27.0

Taxes other than income taxes decreased $10.5 million in 2006 compared to 2005, primarily due to:

• a $5.9 million decrease as the result of the conclusion of a tax audit and

• a $3.4 million decrease in gross receipts tax due to the sale of Monongahela’s Ohio electric T&D assets on December 31, 2005.

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

(In millions)	2006		2005		2004
Other income and expenses, net	$	6.2	$	4.2	$	2.4

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Other income and expenses, net increased $2.0 million in 2006 compared to 2005 and increased $1.8 million in 2005 compared to 2004, primarily as a result of increased interest income on investments due to higher investment balances and higher interest rates.

Interest Expense:  Interest expense was as follows:

(In millions)	2006		2005		2004
Interest expense	$	23.5	$	25.1	$	24.8

Interest expense decreased $1.6 million in 2006 compared to 2005, primarily due to the October 2005 refinancing at lower interest rates of $70.0 million of Monongahela’s outstanding First Mortgage Bonds and the October 2006 repayment of $300 million aggregate principal amount of 5.0% First Mortgage Bonds, using available cash on hand and the net proceeds from the September 2006 issuance of $150 million aggregate principal amount of 5.70% First Mortgage bonds.

Income Tax Expense

The effective tax rate for 2006 was 24.6%. Income tax expense for 2006 was lower than the tax expense calculated at the federal statutory tax rate, primarily due to the effects of resolving state audit issues.

The effective tax rate for 2005 was (17.8)%. The effective tax rate was due to an income tax benefit recorded on income from continuing operations before income taxes and minority interest due to the Delivery and Services segment’s share of consolidated tax savings and recording the effects of prior year tax return adjustments.

The effective tax rate for 2004 was 27.3%. Income tax expense for 2004 was lower than the tax expense calculated at the federal statutory tax rate, primarily due to the Delivery and Services segment’s share of consolidated tax savings and recording the effects of prior year tax return adjustments.

Generation and Marketing

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

	2006	2005	2004	2006 Change		2005 Change
Generation (million kWhs)	10,807	10,382	9,434	4.1	%	10.0	%

Operating Revenues

Operating revenues were as follows:

(In millions)	2006		2005		2004
Revenue from affiliates	$	294.5	$	301.6	$	317.6
Wholesale and other, net		106.6		113.9		(4.8	)
Total operating revenues	$	401.1	$	415.5	$	312.8

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

Through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela sold the power that it generates from its West Virginia jurisdictional assets to AE Supply at PJM market prices and

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purchased from AE Supply, at PJM market prices, the power necessary to meet its West Virginia jurisdictional customer load. Monongahela recorded these transactions with AE Supply as either affiliated revenue or purchased power and transmission expense, depending on energy requirements as determined on an hourly basis. Prior to January 2005, a power sales agreement with AE Supply covering these transactions contained a pricing mechanism that included financial transmission rights (“FTR”) and congestion values. As part of the Asset Swap, effective January 1, 2007 and 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 its contractual obligations.

Total operating revenues decreased $14.4 million in 2006 compared to 2005 due to average price decreases as well as a decrease in the number of Monongahela’s customers as a result of the sale of its Ohio T&D assets on December 31, 2005.

Total operating revenues increased $102.7 million in 2005 compared to 2004 due to a $118.7 million increase in wholesale and other, net revenues, partially offset by a $16.0 million decrease in revenues from affiliates. Wholesale and other, net revenues increased primarily due to the change in the allocation of revenues under Monongahela’s affiliated contract with AE Supply related to financial transmission rights and congestion. Revenues from affiliates decreased primarily due to the change in the allocation of revenues under Monongahela’s affiliated contract with AE Supply. This decrease was partially offset by increased revenue resulting from the Generation and Marketing segment’s portion of additional power sold to Monongahela’s Delivery and Services segment to serve its load requirements in West Virginia. These requirements were previously met through purchases by the Delivery and Services segment from a third party.

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 and fuel handling and residual disposal costs. Fuel expense was as follows:

(In millions)	2006		2005		2004
Fuel	$	178.0	$	153.1	$	123.5

Total fuel expense increased $24.9 million in 2006 compared to 2005, primarily due to a $22.4 million increase in coal expense. The increase in coal expense was due to an increase in the average price of coal of $3.03 per ton and a 0.3 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 BTU PRB coal and a 4.1% increase in MWh generated.

Total fuel expense increased $29.6 million in 2005 compared to 2004, primarily due to a $27.6 million increase in coal expense. The increase in coal expense was primarily due to an increase in average prices and a 10.0% increase in MWhs generated as a result of increased availability at Monongahela’s coal-fired generation facilities.

See Note 1, “Basis of Presentation,” for information regarding a reclassification made between “Operations and maintenance” expense and “Fuel” expense during 2006.

Purchased Power and Transmission:   Purchased power and transmission was as follows:

(In millions)	2006		2005		2004
Purchased power and transmission	$	89.2	$	126.6	$	57.0

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Purchased power and transmission decreased $37.4 million in 2006 compared to 2005, primarily due to a decrease in affiliated purchases to service load requirements.

Purchased power and transmission increased $69.6 million in 2005 compared to 2004, primarily due to higher congestion charges and additional purchases to service load requirements of Monongahela’s Delivery and Services segment in West Virginia that were previously obtained from a third party.

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)	2006		2005		2004
Operations and maintenance	$	75.5	$	80.6	$	92.2

Operations and maintenance expenses decreased $5.1 million in 2006 compared to 2005, primarily due to a $4.1 million decrease in contract work as a result of decreased special maintenance.

Operations and maintenance expenses decreased $11.6 million in 2005 compared to 2004. This decrease was primarily due to a $9.4 million decrease in contract work expenses, primarily due to the receipt of insurance recoveries related to Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 and a reduction in planned outage weeks at Hatfield’s Ferry and Pleasants, as well as decreased outside services expense due to a reduction in the use of outside consultants.

See Note 1, “Basis of Presentation,” for information regarding a reclassification made between “Operations and maintenance” expense and “Fuel” expense during 2006.

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

(In millions)	2006		2005		2004
Taxes other than income taxes	$	20.8	$	23.5	$	23.1

Taxes other than income taxes decreased $2.7 million in 2006 compared to 2005, primarily as the result of a decrease in the taxes applicable to generation assets.

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

(In millions)	2006		2005		2004
Other income and expenses, net	$	9.3	$	8.7	$	6.7

Other income and expenses, net, increased $2.0 million in 2005 compared to 2004, primarily due to increased equity earnings in AGC and increased interest income.

See Note 14, “Other Income and Expenses, Net,” for additional information.

Income Tax Expense

The effective tax rate for 2006 was (39.1)%. The effective tax rate was due to income tax expense on losses from continuing operations before income taxes due to the effects of a prior year federal tax return issue.

The effective tax rate for 2005 was 106.1%. Income tax expense for 2005 was higher than the tax expense calculated at the federal statutory tax rate, primarily due to the effects of prior year tax return adjustments.

The effective tax rate for 2004 was 52.0%. Income tax expense for 2004 was higher than the tax expense calculated at the federal statutory tax rate, primarily due to the effects of prior year tax return adjustments.

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ALLEGHENY GENERATING COMPANY—RESULTS OF OPERATIONS

Income Summary

(In millions)	2006		2005		2004
Operating revenues	$	65.3	$	66.6	$	69.2
Operating income	$	39.7	$	41.9	$	43.1
Income before income taxes	$	33.4	$	34.7	$	34.7
Net income	$	24.8	$	31.1	$	27.4

Operating Revenues:

AGC’s only operating asset is an undivided 40% interest in the Bath County, Virginia pumped-storage hydroelectric station and its connecting transmission facilities.

Pursuant to an agreement, AE Supply and Monongahela purchase all of AGC’s capacity at prices based on a “cost-of-service formula” wholesale rate schedule (the “revenue requirements”) approved by FERC. AE Supply and Monongahela purchase power capacity from AGC on a proportional basis, based on their respective equity ownership of AGC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment.

Operating revenues were as follows:

(In millions)	2006		2005		2004
Operating revenues	$	65.3	$	66.6	$	69.2

Operating revenues decreased $1.3 million in 2006 compared to 2005, primarily as a result of decreased expenditure recoveries. Expenditure recovery is determined on the basis of the “cost-of-service” formula described above. The decrease in such recoveries resulted from a decrease in income tax expense.

Operating revenues decreased $2.6 million in 2005 compared to 2004, primarily as a result of decreased expenditure recoveries on operations and maintenance expenditures.

Operating Expenses

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

(In millions)	2006		2005		2004
Operations and maintenance	$	5.6	$	4.6	$	6.2

Operations and maintenance expenses increased $1.0 million in 2006 compared to 2005 due to increased billings from the operator of the Bath County, Virginia pumped-storage hydroelectric station.

Operations and maintenance expenses decreased $1.6 million in 2005 compared to 2004, primarily due to a charge recorded during 2004 to write-down inventory.

Interest Expense:  Interest expense was as follows:

(In millions)	2006		2005		2004
Interest expense	$	7.2	$	7.4	$	8.5

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Interest expense decreased $1.1 million in 2005 compared to 2004, primarily due to $15.0 million in affiliated long-term debt repayments during 2005.

Income Tax Expense

The effective tax rates for AGC’s continuing operations were 25.9%, 10.3% and 21.0% for 2006, 2005 and 2004, respectively.

The effective income tax rates differ from the statutory tax rates, primarily due to the effect of state income taxes, benefits derived from the allocation of consolidated tax savings to AGC, the amortization of deferred investment tax credits and depreciation.

See Note 5, “Income Taxes,” for additional information.

Liquidity and Capital Requirements—Allegheny

To meet cash needs for operating expenses, the payment of interest, retirement of debt, acquisitions and construction programs, Allegheny has historically used internally generated funds (net cash provided by operations less common and preferred dividends) and external financings, including the sale of common and preferred stock, debt instruments, installment loans and lease arrangements. Certain AE subsidiaries also utilize short-term borrowings through Allegheny’s internal money pool (as described below). 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.

Both Allegheny and AE Supply manage short-term obligations with cash on hand and amounts available under revolving credit facilities. AE and AE Supply manage excess cash through Allegheny’s internal money pool, and Monongahela, Potomac Edison and West Penn manage both excess cash and short-term obligations through the money pool. The money pool provides funds to approved AE subsidiaries at the lower of the Federal Reserve’s previous day’s federal funds effective interest rate, or the Federal Reserve’s previous day’s 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.

At December 31, 2006 and 2005, AE had cash and cash equivalents of $114.1 million and $262.2 million, respectively and restricted cash balances of $12.9 million and $21.6 million, respectively. The restricted cash balances include transition charges collected by West Penn and collateral deposits received as security related to certain contractual obligations.

At December 31, 2006 and 2005, AE had collateral deposits of $39.4 million and $147.8 million, respectively. These deposits are posted as security with counterparties for various transactions. These amounts are included in “Current assets” on the Consolidated Balance Sheets.

At December 31, 2006 and 2005, AE had posted cash collateral of $15.3 million and $41.3 million, respectively, as security for surety bonds issued by a third party. These funds are invested in a temporary investment fund and are included in the caption “Other” within the “Investments and Other Assets” section of the Consolidated Balance Sheets.

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At December 31, 2006, Allegheny’s total borrowing capacity under AE and AE Supply’s 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 (a)	$	400.0	$	—	$	131.8	(b)	$	268.2
AE Supply Revolving Facility		200.0		—		—			200.0
Total	$	600.0	$	—	$	131.8		$	468.2

(a) Allegheny has agreed to maintain $35 million of availability under the AE Revolving Facility to stay enforcement of the judgment in its litigation against Merrill Lynch while an appeal is pending.

(b) This amount is comprised of a letter of credit for $125.0 million that expires in June 2007 and was issued on September 23, 2005, on behalf of Allegheny as collateral to stay enforcement of the judgment in Allegheny’s litigation against Merrill Lynch while an appeal is pending and a letter of credit for $6.8 million issued due to an Allegheny Ventures contractual obligation that expires in July 2007. AE Supply also has a $2.1 million letter of credit outstanding that expires in February 2007, is collateralized by cash and was not issued under either AE’s revolving credit facility or the AE Supply’s revolving facility.

Allegheny’s consolidated capital structure, including short-term debt and liabilities associated with assets held for sale and excluding minority interest, as of December 31, 2006 and 2005, was as follows:

	2006			2005
(In millions)	Amount		%	Amount		%
Debt	$	3,585.2	63.0	$	4,101.7	70.5
Common equity		2,080.4	36.6		1,695.3	29.1
Preferred equity		24.0	0.4		24.0	0.4
Total	$	5,689.6	100.0	$	5,821.0	100.0

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”). The AE Supply Credit Facility matures in 2011 and has a current interest rate equal to the London Interbank Offered Rate (“LIBOR”) plus 0.75%, with decreases in the rate possible if AE Supply’s credit ratings improve from current levels. Proceeds from the AE Supply Credit Facility were used to refinance $967 million outstanding under the 2005 AE Supply 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 and has an initial interest rate equal to LIBOR plus 1%, with decreases in the rate possible if AE’s credit ratings improve from current levels. 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, which 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.

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In September 2006, Monongahela issued $150 million aggregate principal amount of 5.70% First Mortgage Bonds, which 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, which 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.

See Note 26, “Subsequent Event—Asset Swap,” for debt changes resulting from the January 1, 2007 Asset Swap.

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
Total AE	$	219.1	$	418.1
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
Total AE Supply	$	967.0	$	1,209.0
Potomac Edison:
First Mortgage Bonds	$	100.0	$	—
Medium-Term Notes		—		100.0
Total Potomac Edison	$	100.0	$	100.0
West Penn:
First Mortgage Bonds	$	145.0	$	—
Transition Bonds (a)		5.2		75.8
Total West Penn	$	150.2	$	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.

2005 Debt Activity

In April 2005, the holders of $295.0 million of the outstanding $300.0 million in Trust Preferred Securities issued by Capital Trust accepted AE and Capital Trust’s tender offer and consent solicitation. Under the terms of the offer, for each $1,000 in liquidation amount of Trust Preferred Securities tendered, a holder received 83.33 shares of AE common stock and $160 in cash. On April 22, 2005, AE issued an aggregate of 24.6 million shares of its common stock and $47.2 million in cash to the holders of the tendered Trust Preferred Securities. The $47.2 million cash payment was expensed during the second quarter of 2005. In addition, AE received the required consents from holders of the Trust Preferred Securities for amendments to the indenture governing AE’s 11 ⁷/8% Notes due 2008.

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The holder of the remaining $5.0 million in liquidation amount of Trust Preferred Securities converted its Trust Preferred Securities into 416,650 shares of AE common stock on May 3, 2005.

On June 16, 2005, AE and AE Supply (together, the “Borrowers”) entered into a $700 million credit facility (the “2005 AE Credit Facility”) comprised of a $400 million senior unsecured revolving credit facility (the “2005 Revolving Facility”) and a $300 million senior unsecured term loan (the “2005 Term Facility”). On August 1, 2005, AE used the proceeds of the 2005 Term Facility to refinance the aggregate principal outstanding amount under AE’s 7.75% Notes due August 1, 2005.

Loans under the 2005 AE Credit Facility bore interest, depending on the type of loan requested by the Borrowers, at a rate equal to either (i) the higher of the rate announced publicly by Citibank in New York, from time to time, as Citibank’s base rate or 0.50% above the Federal Funds Rate (as defined in the Credit Agreement) (the “Base Rate”), plus the applicable margin, which was between 1.50% and 0.50% for Base Rate loans, or (ii) the Eurodollar Rate (as defined in the Credit Agreement), plus the applicable margin, which was between 2.50% and 1.50% for Eurodollar Rate-based loans. The applicable margin for LIBOR borrowings was 2.00% at December 31, 2005. On January 18, 2006, the margin for LIBOR borrowings was reduced to 1.50% as a result of increased Standard & Poor’s (“S&P”) credit ratings on certain of AE’s debt. With respect to each letter of credit, the relevant Borrower was required to pay to the Administrative Agent a letter of credit fee equal to the applicable margin, which ranged from 2.50% to 1.50%, times the daily maximum amount available to be drawn under such letter of credit. In each case of a Base Rate loan, Eurodollar Rate loan or letter of credit, the applicable margin varied depending upon S&P and Moody’s Investors Service, Inc.’s (“Moody’s”) ratings of certain of AE’s public debt. The Borrowers’ ability to request and maintain Eurodollar Rate loans was subject to certain limitations. The 2005 AE Credit Facility was refinanced during 2006, as discussed above under the heading “2006 Debt Activity.”

On July 21, 2005, AE Supply and certain of its subsidiaries entered into a secured term loan facility (the “2005 AE Supply Term Loan”) of $1.07 billion. The 2005 AE Supply Term Loan had an initial interest rate equal to LIBOR plus 1.75%. On January 18, 2006, the margin for LIBOR borrowings was reduced to 1.50% as a result of increased S&P credit ratings on certain of AE Supply’s debt. Proceeds from the 2005 AE Supply Term Loan were used, in part, to refinance approximately $738 million outstanding under a 2004 AE Supply loan. Proceeds from the 2005 AE Supply Term Loan were also used on August 22, 2005 to redeem AE Supply’s 10.25% Senior Notes due 2007, which had a principal amount outstanding of approximately $331 million. Also on August 22, 2005, AE Supply used cash on hand to redeem its 13.0% Senior Notes due 2007, which had a principal amount outstanding of approximately $35 million. AE Supply expensed premiums and costs associated with the redemption of its 10.25% Senior Notes and 13.0% Senior Notes in the amount of $32.6 million during the three months ended September 30, 2005. The 2005 AE Supply Term Loan was refinanced during 2006, as discussed above under the heading “2006 Debt Activity.”

On August 15, 2005, Potomac Edison issued $145 million of 5.125% First Mortgage Bonds due 2015. Approximately $143 million of the proceeds, together with available cash, was used to redeem Potomac Edison’s $65 million of outstanding 7.75% First Mortgage Bonds due 2025 and its $80 million of outstanding 7.625% First Mortgage Bonds due 2025.

On September 27, 2005, WPP Funding, LLC, an indirect subsidiary of West Penn issued $115.0 million of 4.46% Transition Bonds, Series 2005-A with an expected maturity of June 2010. These bonds securitize an intangible right to receive a revenue stream in the form of a transition charge from Pennsylvania rate payers. Interest on these bonds will accrue and be added to the principal amount of the bonds until the first scheduled interest payment date following final payment of the Transition Bonds, Series 1999-A issued by West Penn Funding LLC, which is expected to occur in June 2008. Thereafter, interest on these bonds will be paid quarterly.

On October 17, 2005, Monongahela issued $70.0 million of 5.375% First Mortgage Bonds due 2015. Monongahela utilized the proceeds and available cash to redeem $70.0 million of its 7 ⁵/8% First Mortgage Bonds due 2025 on November 16, 2005.

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

Allegheny made various other debt payments during 2005. See Note 4, “Capitalization” for additional information.

Issuances and repayments of indebtedness, by entity, during 2005 were as follows:

(In millions)	Issuances		Repayments
AE:
2005 AE Credit Facility	$	422.0	$	223.0
Prior Credit Facility		47.0		147.0
Convertible Preferred Securities		—		300.0
Medium-Term Notes		—		300.0
Total AE	$	469.0	$	970.0
Monongahela:
First Mortgage Bonds	$	70.0	$	70.0
AE Supply:
2005 AE Supply Term Loan	$	1,069.0	$	80.0
2004 AE Supply Loan		—		982.1
Medium-Term Notes		—		380.0
Total AE Supply	$	1,069.0	$	1,442.1
Potomac Edison:
First Mortgage Bonds	$	145.0	$	145.0
West Penn:
Transition Bonds (a)	$	116.3	$	73.0
Consolidated Total	$	1,869.3	$	2,700.1
Debt associated with assets held for sale:
Other Notes (b)	$	—	$	86.7

(a) The issuance amounts include $1.3 million of interest that was accrued and added to the principal amount of certain of the bonds.

(b) Represents debt related to Monongahela’s former natural gas operations in West Virginia. In connection with the sale of these operations on September 30, 2005, the purchaser assumed this debt.

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 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 will provide 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

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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.

During 2005, AE Supply and West Penn and its subsidiaries completed land sales for aggregate proceeds of $2.6 million.

See Note 8, “Asset Sales,” for information relating to asset sales.

Dividends

AE paid no dividends on its common stock in 2006 or 2005. Monongahela paid dividends on its common stock of $10.0 million during 2006 and paid no dividends on its common stock during 2005. Monongahela paid dividends on its preferred stock of $1.2 million and $5.0 million in 2006 and 2005, respectively. AGC paid aggregate dividends on its common stock to AE Supply and Monongahela of $31.0 million and $21.8 million during 2006 and 2005, respectively.

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.

Other Matters Concerning Liquidity and Capital Requirements

Allegheny estimates that its contributions to the pension plan during 2007 will approximate $50 million. Allegheny also currently anticipates that it will contribute $19 million to $23 million during 2007 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 expectations, if actuarial assumptions or asset valuation methods change or if there are changes to employee benefit and tax laws.

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.

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Allegheny

As described in the capital expenditures table included in Item 1, “Business,” Allegheny estimates that its capital expenditures will approximate $1,030 million in 2007 and $1,120 million in 2008, including amounts relating to significant multiple year environmental control and transmission expansion projects.

Allegheny plans to fund $450 million of construction costs through 2009 for the Fort Martin Scrubbers through securitization of an environmental control surcharge to be collected from the West Virginia customers of Monongahela and Potomac Edison. Allegheny plans to fund the remainder of its capital expenditures with cash on hand, cash from operations and, when necessary, external debt financings.

Allegheny has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel agreements and other contracts. The table below summarizes the payments due by period for these obligations and commitments, as of December 31, 2006. 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 “Allegheny Energy, Inc.-Discussion of Segment Results of Operations-AE’s Generation and Marketing Segment Results.”

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2007		Payments from January 1, 2008 to December 31, 2009		Payments from January 1, 2010 to December 31, 2011		Payments from January 1, 2012 and beyond		Total
Long-term debt (a)	$	201.2	$	150.8	$	1,272.0	$	1,969.8	$	3,593.8
Interest on long-term debt (b)		233.5		447.8		363.9		425.1		1,470.3
Interest rate swap obligations		6.1		12.3		7.2		—		25.6
Capital lease obligations		10.7		14.8		9.8		5.0		40.3
Operating lease obligations		4.6		6.9		6.7		16.1		34.3
PURPA purchased power		227.4		463.5		473.9		3,941.4		5,106.2
Fuel purchase and transportation commitments		750.1		1,217.0		965.8		2,865.2		5,798.1
Other purchase obligation (c)		27.1		52.6		48.0		22.4		150.1
Total	$	1,460.7	$	2,365.7	$	3,147.3	$	9,245.0	$	16,218.7

(a) Does not include unamortized debt expense, discounts, premiums, payments made and debt issued subsequent to December 31, 2006 and changes resulting from the January 1, 2007 Asset Swap, which is discussed at Note 26, “Subsequent Event—Asset Swap,” to the Consolidated Financial Statements.

(b) Amounts are based on interest rates as of December 31, 2006 and do not reflect any payments made or interest rate changes subsequent to December 31, 2006. Total interest on long-term debt includes $8.3 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 represent Allegheny’s expected cash payments for outsourcing of certain information technology functions and assistance with the installation of an enterprise resource planning system.

Monongahela

As described in the capital expenditures table within Item 1, “Business,” Monongahela estimates that its capital expenditures will approximate $260 million in 2007 and $355 million in 2008 including amounts relating to significant multiple year environmental control and transmission expansion projects.

Monongahela plans to fund $450 million of construction costs through 2009 for the Fort Martin scrubbers, through securitization of an environmental control surcharge to be collected from West Virginia customers. Monongahela plans to fund the remainder of its capital expenditures with cash on hand, cash from operations and, when necessary, external debt financings.

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Monongahela has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel agreements and other contracts. The table below summarizes the payments due by period for these obligations and commitments, as of December 31, 2006. The table below does not include expected pension and postretirement benefits other than pension contributions and contingent liabilities.

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2007		Payments from January 1, 2008 to December 31, 2009		Payments from January 1, 2010 to December 31, 2011		Payments from January 1, 2012 and beyond		Total
Long-term debt (a)	$	15.5	$	—	$	110.0	$	410.2	$	535.7
Interest on long-term debt (b)		32.6		64.2		48.3		105.6		250.7
Capital lease obligations		3.2		4.4		2.7		1.7		12.0
Operating lease obligations		0.4		0.2		—		—		0.6
PURPA purchased power		65.0		131.8		134.1		1,457.0		1,787.9
Fuel purchase and transportation commitments		232.0		240.3		162.7		618.6		1,253.6
Total	$	348.7	$	440.9	$	457.8	$	2,593.1	$	3,840.5

(a) Does not include unamortized debt expense, discounts, premiums and payments made subsequent to December 31, 2006 and changes resulting from the January 1, 2007 Asset Swap, which is discussed at Note 17, “Subsequent Event—Asset Swap,” to Monongahela’s Consolidated Financial Statements.

(b) Amounts are based on interest rates as of December 31, 2006 and do not reflect any payments made or interest rate changes subsequent to December 31, 2006 and any debt prepayments or interest rate changes.

AGC

As described in the capital expenditures table within Item 1, “Business,” AGC estimates that its capital expenditures will approximate $7 million in 2007 and $5 million in 2008.

AGC has various obligations and commitments to make future cash payments under debt instruments. The table below summarizes the payments due by period for these obligations and commitments as of December 31, 2006. The table below does not include expected pension contributions and contingent liabilities.

Contractual Obligations and Commitments (In millions)	Payments by December 31, 2007		Payments from January 1, 2008 to December 31, 2009		Payments from January 1, 2010 to December 31, 2011		Payments from January 1, 2012 and beyond		Total
Long-term debt (a)	$	—	$	—	$	—	$	100.0	$	100.0
Interest on long-term debt (b)		6.9		13.8		13.8		80.1		114.6
Total	$	6.9	$	13.8	$	13.8	$	180.1	$	214.6

(a) Does not include unamortized debt expense, discounts, premiums and payments made subsequent to December 31, 2006.

(b) Amounts are based on interest rates as of December 31, 2006 and do not reflect any payments made or interest rate changes subsequent to December 31, 2006 and any debt prepayments or interest rate changes.

Off-Balance Sheet Arrangements

None of the Registrants has any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on their financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

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Allegheny 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, 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 2006, 2005 and 2004 are summarized as follows:

(In millions)	2006			2005			2004
Net income (loss)	$	319.3		$	63.1		$	(310.6	)
Loss (income) from discontinued operations, net of tax		(0.6	)		6.1			440.3
Non-cash items included in earnings		468.9			430.1			418.5
Pension and other postretirement employee benefit contributions		(78.0	)		(89.1	)		(58.7	)
Changes in certain assets and liabilities		48.7			21.1			42.2
Net cash provided by (used in) operating activities of discontinued operations		4.8			54.8			(8.0	)
Net cash provided by operating activities	$	763.1		$	486.1		$	523.7

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 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.

Significant cash flows related to operating activities for the year ended December 31, 2005 included $89.1 million in payments to Allegheny’s pension and other postretirement benefit plans, primarily as a result of contributions made to satisfy the funding requirements of these benefit plans, $47.2 million in payments to the holders of 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.

Significant cash flows related to operating activities for the year ended December 31, 2004 included $88.6 million in net proceeds related to the 2004 sale of the OVEC tolling agreement, $70.8 million in proceeds related to the 2003 sale of the CDWR contract and related hedges to J. Aron & Company as a result of the exit from Western U.S. energy markets, $58.7 million in payments to Allegheny’s pension and other postretirement benefit plans, primarily as a result of contributions made to satisfy the funding requirements of these benefit plans, and $28.0 million in final scheduled payments in connection with the termination of a tolling agreement with Williams Energy and Marketing Company. Changes in certain assets and liabilities primarily consisted of a $70.1 million change in accrued taxes and a $22.6 million change in prepaid taxes, both primarily as a result of timing differences associated with the payment of certain tax obligations, a $20.3 million change in other current

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liabilities and a $13.0 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues. These amounts were partially offset by a $40.1 million increase in collateral deposits, primarily due to the requirements of various contracts, a $27.6 million decrease in accounts payable, primarily as a result of timing differences associated with the payment of certain obligations, a $13.3 million change in other liabilities and a $10.3 million increase in materials, supplies and fuel.

Investing Activities

Cash flows from investing activities for 2006, 2005 and 2004 are summarized as follows:

(In millions)	2006			2005			2004
Capital expenditures	$	(447.3	)	$	(306.5	)	$	(265.6	)
Proceeds from asset sales		2.6			66.5			24.0
Purchase of minority interest in Hunlock Creek Energy Ventures		(13.9	)		—			—
Decrease (increase) in restricted funds		8.7			207.3			(183.8	)
Other investments		(4.3	)		(2.6	)		2.1
Net cash provided by investing activities of discontinued operations		50.4			226.8			161.4
Net cash provided by (used in) investing activities	$	(403.8	)	$	191.5		$	(261.9	)

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

Significant cash flows provided by investing activities for the year ended December 31, 2005 included net cash provided by investing activities of discontinued operations, 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, 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, primarily as a result of the sale of Monongahela’s Ohio T&D assets. These items were partially offset by capital expenditures.

Significant cash flows used in investing activities for the year ended December 31, 2004 included capital expenditures and an increase in restricted funds, primarily due to the requirement that the proceeds received from the 2004 sales of a portion of AE’s equity interest in OVEC and AE Supply’s Lincoln generation facility be used to repay debt. These amounts were partially offset by net cash provided by investing activities of discontinued operations, primarily as a result of the sale of AE Supply’s Lincoln generation facility and proceeds from the sale of assets, primarily as a result of the sale of a portion of AE’s equity interest in OVEC and various parcels of land.

Financing Activities

Cash flows from financing activities for 2006, 2005 and 2004 are summarized as follows:

(In millions)	2006			2005			2004
Net repayment of short-term debt	$	—		$	—		$	(53.6	)
Issuance of long-term debt		1,571.3			1,849.1			2,811.5
Repayment of long-term debt		(2,102.9	)		(2,406.9	)		(3,506.0	)
Redemption of preferred stock of subsidiary		—			(50.0	)		—
Proceeds from the issuance of common stock		—			—			151.4
Proceeds from the exercise of employee stock options		24.7			2.9			0.2
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		(0.4	)		—			(1.1	)
Net cash used in financing activities of discontinued operations		—			—			(3.3	)
Net cash used in financing activities	$	(507.3	)	$	(604.9	)	$	(600.9	)

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Significant cash flows used in financing activities for the year ended December 31, 2006 included repayments of long-term debt, 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.

Significant cash flows used in financing activities for the year ended December 31, 2005 included repayments of long-term debt, 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.

Significant cash flows used in financing activities for the year ended December 31, 2004 included repayments of long-term debt, primarily related to the March 2004 refinancing of borrowing facilities, the June 2004 refinancing of outstanding First Mortgage Bonds, the October 2004 refinancing of an AE Supply term loan and the November 2004 refinancing of outstanding First Mortgage Bonds. Partially offsetting these amounts were $2,811.5 million (net of $30.5 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, primarily related to the previously mentioned refinancings and $151.4 million in proceeds from the October 2004 private placement of 10 million shares of AE common stock.

Monongahela Cash Flows

Operating Activities

Monongahela’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, future demand and market prices for power. Cash flows from operating activities for 2006, 2005 and 2004 are summarized as follows:

(In millions)	2006		2005			2004
Net income	$	69.1	$	10.2		$	2.5
Loss (income) from discontinued operations, net of tax		1.0		(1.0	)		13.9
Non-cash items included in earnings		60.1		83.7			64.2
Changes in certain assets and liabilities		11.0		51.2			18.4
Net cash provided by (used in) operating activities of discontinued operations		—		63.9			(49.4	)
Net cash provided by operating activities	$	141.2	$	208.0		$	49.6

Operating cash flows for the year ended December 31, 2006 included changes in certain assets and liabilities primarily consisting of a $16.6 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, a $14.0 million decrease in collateral deposits, primarily due to the requirements of various contracts and a $13.5 million change in prepaid taxes, primarily due to timing differences associated with the payment of certain tax obligations. These amounts were partially offset by cash flows used for operating activities primarily as a result of a $15.1 million decrease in accounts payable, due to the timing differences associated with the payment of certain obligations, and a $15.2 million change in accrued taxes, primarily as a result of timing differences associated with the payment of certain tax obligations.

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Operating cash flows for the year ended December 31, 2005 included changes in certain assets and liabilities primarily consisting of $60.3 million increase in accounts payable to affiliates, net, primarily as a result of timing differences associated with the payment of certain obligations, and a $15.0 million change in prepaid taxes primarily due to timing differences associated with the payment of certain tax obligations. These amounts were partially offset by cash flows used for operating activities primarily as a result of a $23.4 million increase in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, and a $12.7 million increase in collateral deposits, primarily due to the requirements of various contracts.

Operating cash flows for the year ended December 31, 2004 included changes in certain assets and liabilities consisting of a $17.2 million increase in accounts payable to affiliates, net and an $11.8 million change in prepaid taxes, each primarily as a result of timing differences associated with the payment of certain tax and other obligations. This amount was partially offset by a $6.2 million change in accrued taxes primarily as a result of timing differences associated with the payment of certain tax obligations.

Investing Activities

Cash flows from investing activities for 2006, 2005 and 2004 are summarized as follows:

(In millions)	2006			2005			2004
Capital expenditures	$	(90.6	)	$	(70.0	)	$	(54.2	)
Proceeds from asset sales		0.4			52.1			0.2
Notes receivable from affiliates		(1.9	)		(21.3	)		(4.2	)
Net cash provided by (used in) investing activities of discontinued operations		—			127.6			(13.0	)
Net cash provided by (used in) investing activities	$	(92.1	)	$	88.4		$	(71.2	)

Significant cash flows used in investing activities for the years ended December 31, 2006, 2005 and 2004 were for capital expenditures. The year ended December 31, 2005 amount also included net cash provided by investing activities of discontinued operations, primarily as a result of the sale of Monongahela’s West Virginia natural gas operations, proceeds from the sale of assets, primarily as a result of the sale of Monongahela’s Ohio T&D assets and an increase in a note receivable from affiliates.

Financing Activities

Cash flows from financing activities for 2006, 2005 and 2004 are summarized as follows:

(In millions)	2006			2005			2004
Net repayment of short-term debt	$	—		$	—		$	(53.6	)
Issuance of long-term debt		149.5			69.2			117.2
Repayment of long-term debt		(300.0	)		(72.1	)		(66.3	)
Deferred financing costs		(1.6	)		—			—
Redemption of preferred stock		—			(50.0	)		—
Return of capital to AE		—			(80.0	)		—
Cash dividends paid on preferred stock		(1.2	)		(5.0	)		(5.0	)
Cash dividends paid on common stock		(10.0	)		—			(33.3	)
Net cash provided by (used in) financing activities of discontinued operations		—			(67.1	)		63.7
Net cash provided by (used in) financing activities	$	(163.3	)	$	(205.0	)	$	22.7

Significant cash flows used in financing activities for the year ended December 31, 2006 related to the retirement of outstanding First Mortgage Bonds related to the September 2006 refinancing, and cash dividends paid on preferred and common stock. These amounts were partially offset by $149.5 million (net of $0.5 million

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related to an original issue discount and debt issuance costs) in proceeds from the September 2006 issuance of First Mortgage Bonds, which was used to help fund the repayment at maturity of the $300 million aggregate principal amount of 5.0% First Mortgage Bonds.

Significant cash flows used in financing activities for the year ended December 31, 2005 related to a return of capital to AE using a portion of the proceeds from the sale of the West Virginia natural gas operations, the retirement of outstanding First Mortgage Bonds related to the October 2005 refinancing, net cash used in financing activities of discontinued operations and the redemption of preferred stock. These amounts were partially offset by $69.2 million (net of $0.8 million related to an original issue discount and debt issuance costs) in proceeds from the issuance of First Mortgage Bonds related to the October 2005 refinancing.

Significant cash flows provided by financing activities for the year ended December 31, 2004 related to $117.2 million (net of $2.8 million related to an original issue discount and debt issuance costs) in proceeds from the issuance of First Mortgage Bonds related to the June 2004 refinancing and net cash provided by financing activities of discontinued operations. These amounts were partially offset by the retirement of outstanding First Mortgage Bonds and the repayment of short-term debt, each related to the June 2004 refinancing, and cash dividends paid on preferred and common stock.

AGC Cash Flows

Operating Activities

AGC’s cash flows from operating activities primarily result from the sale of electricity. Future cash flows will be affected by the economy, weather, future demand and market prices for power. Cash flows from operating activities for 2006, 2005 and 2004 are summarized as follows:

(In millions)	2006		2005		2004
Net income	$	24.8	$	31.1	$	27.4
Non-cash items included in earnings		10.7		12.5		12.3
Changes in certain assets and liabilities		0.8		0.6		2.1
Net cash provided by operating activities	$	36.3	$	44.2	$	41.8

Operating cash flows for the year ended December 31, 2006 included changes in certain assets and liabilities primarily consisting of a $2.2 million change in taxes receivable/accrued, net and a $0.9 million change in accounts receivable due from/payable to affiliates, net, each primarily as a result of timing differences associated with the payment of certain tax and other obligations. These amounts were partially offset by a $2.1 million change in accounts payable, primarily as a result of timing differences associated with the payment of certain obligations.

Operating cash flows for the year ended December 31, 2005 included changes in certain assets and liabilities primarily consisting of a $4.2 million change in accounts receivable due from/payable to affiliates, net and a $2.7 million increase in accounts payable, each primarily as a result of timing differences associated with the payment of certain obligations. These amounts were partially offset by a $6.1 million change in taxes receivable/accrued, net, primarily as a result of timing differences associated with the payment of certain tax obligations.

Operating cash flows for the year ended December 31, 2004 included changes in certain assets and liabilities primarily consisting of a $1.5 million change in accounts receivable due from/payable to affiliates, net and a $0.7 million change in taxes receivable/accrued, net, each primarily as a result of timing differences associated with the payment of certain obligations.

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Investing Activities

Cash flows used in investing activities for the years ended December 31, 2006, 2005 and 2004 were $4.3 million, $13.0 million and $9.1 million, respectively, consisting of capital expenditures.

Financing Activities

Cash flows used in financing activities for the year ended December 31, 2006 were $31.0 million consisting of cash dividends paid on common stock. Cash flows used in financing activities for the year ended December 31, 2005 were $36.8 million consisting of a $15.0 million payment on a note payable to parent and $21.8 million of cash dividends paid on common stock. Cash flows used in financing activities for the year ended December 31, 2004 were $27.5 million consisting of a $15.0 million payment on a note payable to parent and $12.5 million of cash dividends paid on common stock.

Financing

AE Common Stock

During 2006, AE issued 2.4 million shares of common stock, primarily in connection with stock option exercises and the settlement of stock units. During 2005, AE issued 0.6 million shares of common stock, primarily in connection with matching contributions to its Employee Stock Ownership and Savings Plan (“ESOSP”), stock option exercises and the settlement of stock units.

During 2005, AE issued an aggregate of 25.0 million shares of its common stock in connection with the tender offer for Capital Trust’s Outstanding Trust Preferred Securities.

There were no shares of common stock repurchased in 2006 and 2005.

Preferred Stock

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

Debt

See “Liquidity and capital requirements,” above, and Note 4, “Capitalization,” for information regarding debt.

Lease Transactions

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

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Credit Ratings

The following table lists Allegheny’s credit ratings, as of February 27, 2007:

	Moody’s	S & P	Fitch
Outlook	Stable (1)	Positive	Stable (2)
AE:
Corporate Credit Rating	Ba2(3)	BB+	NR
Senior Unsecured Debt	Ba2	BB-	BB+
Short-term Rating	SGL-2(4)	B2	NR
AE Supply:
Senior Secured Debt	Baa3	BBB-	BBB-
Senior Unsecured Debt	Ba3	BB-	BB+
Pollution Control Bonds	NR	NR	AAA
Monongahela:
First Mortgage Bonds	Baa2	BBB-	BBB+
Senior Unsecured Debt	Baa3	BB-	BBB-
Preferred Stock	Ba3	B+	BB+
Potomac Edison:
First Mortgage Bonds	Baa2	BBB-	BBB+
Senior Unsecured Debt	Baa3	BB-	BBB-
West Penn:
Transition Bonds	Aaa	AAA	AAA
First Mortgage Bonds	Baa2	BBB	BBB+
Senior Unsecured Debt	Baa3	BB+	BBB-
AGC:
Senior Unsecured Debt	Ba3	BB-	BB+

(1) Moody’s outlook for Potomac Edison is negative

(2) Fitch’s outlook for Monongahela is negative

(3) Corporate family rating for AE only, which excludes all of its subsidiaries

(4) Liquidity rating

RECENT ACCOUNTING PRONOUNCEMENTS

The following recent accounting pronouncements were issued, but have not yet been adopted by Allegheny as of December 31, 2006:

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value and establishes a framework for measuring fair value when fair value is required for recognition or disclosure purposes under GAAP. The standard also expands disclosure about fair value measurement but does not require any new fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Management has not completed the process of determining the effect of SFAS No. 157 on Allegheny’s financial statements, however, at this time the adoption of SFAS No. 157 is not expected to have a material impact on Allegheny’s, Monongahela’s or AGC’s consolidated results of operations or financial position.

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. The guidance in the FSP is to be applied to the first fiscal year beginning

120

after December 15, 2006. It is Allegheny’s policy to account for planned major maintenance activities using the direct expense method. Therefore, the adoption of the FSP is not expected to have a material impact on Allegheny’s, Monongahela’s or AGC’s consolidated results of operations, financial position or cash flows.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109 (“FIN 48”). The provisions of FIN 48 are effective beginning January 1, 2007. See Notes to Financial Statements for Allegheny, Monongahela and AGC for additional information related to FIN 48 and its estimated impact on the Companies’ financial results.

In June 2006, the EITF reached a consensus on 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) basis. In addition, EITF 06-3 requires disclosure of any such taxes that are reported on a gross basis as well as the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented.

EITF 06-3 is effective for financial statements issued for fiscal years beginning after December 15, 2006. As disclosed in Note 1, “Basis of Presentation,” it is Allegheny’s policy to record 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, which 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, implementation of EITF 06-3 will not have a material impact on Allegheny’s, Monongahela’s or AGC’s financial statements.

121

I TEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

AE

During 2006, Allegheny continued its focus on reducing risk, optimizing the value of its generation facilities, reducing the volatility of mark-to-market earnings and prudently managing and protecting the value associated with the existing positions in its wholesale energy markets transactions portfolio.

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

Allegheny’s Corporate 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 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, fuel procurement, power marketing and the purchase and sale of electricity. Allegheny’s wholesale activities principally consist of bilateral forward contracts for the purchase and sale of electricity and natural gas. The majority of these contracts represent commitments to purchase or sell electricity at fixed prices in the future. These forward contracts generally require physical delivery of electricity.

At December 31, 2006, AE’s outstanding debt subject to variable interest rates was $747 million, compared to $1.19 billion of outstanding debt subject to variable interest rates at December 31, 2005. 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 2007 by approximately $7.5 million for outstanding debt, on an annual basis, based on the amount of outstanding debt as of December 31, 2006. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Requirements” below and Note 4, “Capitalization,” 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.

122

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

Allegheny has a concentration of counterparties in the electric, coal and natural gas utility industries, most of whom are viewed as above investment grade credit quality. 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, 2006, the fair value of Allegheny’s trading portfolio is comprised primarily of interest rate swap agreements with a single counterparty and commodity cash flow hedges.

Additionally, AE Supply is a counterparty to certain long-term agreements for the transportation of natural gas. See “Business—Fuel, Power and Resource Supply” above.

Allegheny currently is involved in a number of capital intensive projects, including the TrAIL 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 accomplish the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities and may in the future enter into additional such contracts with respect to these and other capital projects, including the TrAIL 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. Furthermore, Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all.

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, 2006 and 2005, this calculation yielded a VaR of $8,000 and $382,000, respectively.

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MONONGAHELA

Monongahela is exposed to market risks associated with commodity prices that result from market fluctuations in the price and transportation costs of electricity.

Monongahela is subject to capped rates in West Virginia. Monongahela agreed to terminate its fuel clause in West Virginia effective July 1, 2000. The purpose of the fuel clause, which allowed Monongahela to recoup certain fuel costs through customer rates, had been to offset fluctuations in the market price of fuel. In order to manage its financial exposure to these price fluctuations in the absence of a fuel clause, Monongahela enters into contracts, such as fuel purchase commitments. To the extent that Monongahela purchases fuel at significantly higher prices, Monongahela’s results of operations and cash flows could be adversely affected. In July 2006, Monongahela and Potomac Edison filed a request with the West Virginia PSC to increase their West Virginia retail rates. The request includes an increase in rates related to fuel and purchased power costs, including the reinstatement of Monongahela’s fuel cost recovery clause. See “Business—Regulatory Framework Affecting Allegheny” above.

AGC

Not Applicable.

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I TEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements

	Page No.
Allegheny Energy, Inc. and Subsidiaries	126
Report of Independent Registered Public Accounting Firm	188
Monongahela Power Company and Subsidiaries	190
Report of Independent Registered Public Accounting Firm	222
Allegheny Generating Company	223
Report of Independent Registered Public Accounting Firm	238
Schedule I AE (Parent Company) Condensed Financial Statements	239
Schedule II Valuation and Qualifying Accounts	241

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A LLEGHENY ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

	Year ended December 31,
(In thousands, except per share data)	2006			2005			2004
Operating revenues	$	3,121,489		$	3,037,887		$	2,756,121
Operating expenses:
Fuel		842,661			759,057			634,046
Purchased power and transmission		382,990			458,306			328,421
Loss on sale of Ohio T&D assets		—			29,256			—
Gain on sale of OVEC power agreement and shares		(6,124	)		—			(94,826	)
Deferred energy costs, net		7,584			(1,528	)		204
Operations and maintenance		685,650			735,330			798,810
Depreciation and amortization		273,134			308,141			299,425
Taxes other than income taxes		203,274			212,534			200,811
Total operating expenses		2,389,169			2,501,096			2,166,891
Operating income		732,320			536,791			589,230
Other income and expenses, net		33,956			44,230			24,522
Interest expense and preferred dividends:
Interest expense		270,264			436,447			400,196
Preferred dividends of subsidiary		1,172			4,071			5,037
Total interest expense and preferred dividends		271,436			440,518			405,233
Income from continuing operations before income taxes and minority interest		494,840			140,503			208,519
Income tax expense		173,543			64,771			79,669
Minority interest in net income (loss) of subsidiaries		2,562			587			(882	)
Income from continuing operations		318,735			75,145			129,732
Income (loss) from discontinued operations, net of tax (Note 7)		586			(6,152	)		(440,330	)
Income (loss) before cumulative effect of accounting changes		319,321			68,993			(310,598	)
Cumulative effect of accounting changes, net of tax of $3,367		—			(5,928	)		—
Net income (loss)	$	319,321		$	63,065		$	(310,598	)
Common Share Data:
Weighted average common shares outstanding
Basic		164,184			155,016			129,486
Diluted		168,676			158,634			156,492
Basic income (loss) per common share:
Income from continuing operations	$	1.94		$	0.48		$	1.00
Loss from discontinued operations, net of tax		—			(0.04	)		(3.40	)
Cumulative effect of accounting changes, net of tax		—			(0.04	)		—
Net income (loss) per common share	$	1.94		$	0.40		$	(2.40	)
Diluted income (loss) per common share:
Income from continuing operations	$	1.89		$	0.47		$	0.99
Loss from discontinued operations, net of tax		—			(0.04	)		(2.82	)
Cumulative effect of accounting changes, net of tax		—			(0.03	)		—
Net income (loss) per common share	$	1.89		$	0.40		$	(1.83	)

See accompanying Notes to Consolidated Financial Statements.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

	Year ended December 31,
(In thousands)	2006			2005			2004
Cash Flows From Operating Activities:
Net income (loss)	$	319,321		$	63,065		$	(310,598	)
Loss (income) from discontinued operations, net of tax		(586	)		6,152			440,330
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Cumulative effect of accounting changes, net		—			5,928			—
Depreciation and amortization		273,134			308,141			299,425
Amortization of debt issuance costs		23,086			24,861			44,401
Amortization of power sale liability related to Ohio sale		(25,900	)		—			—
Amortization of liability for adverse power purchase commitment		(17,154	)		(16,727	)		(18,042	)
Amortization of Pennsylvania stranded cost recovery asset		15,213			16,049			15,752
Loss (gain) on asset sales and disposals		(1,444	)		26,520			(20,937	)
Minority interest in net income (loss) of subsidiaries		2,562			587			(882	)
Deferred income taxes and investment tax credit, net		163,834			16,064			(18,907	)
Stock-based compensation expense		13,875			10,632			21,884
Unrealized losses (gains) on commodity contracts, net		(32,397	)		(20,639	)		5,720
Pension and other postretirement employee benefit plan expense		41,468			46,224			45,404
Pension and other postretirement employee benefit plan contributions		(77,966	)		(89,079	)		(58,688	)
Other, net		12,544			12,487			44,691
Changes in certain assets and liabilities:
Accounts receivable, net		24,817			(63,204	)		13,046
Materials, supplies and fuel		(8,087	)		(3,744	)		(10,271	)
Collateral deposits		132,727			(65,863	)		(40,145	)
Prepaid taxes		28,291			28,622			22,601
Prepayments		139			4,315			7,573
Other current assets		(10,046	)		1,233			1,527
Accounts payable		(109,931	)		75,128			(27,617	)
Accrued taxes		(21,021	)		21,955			70,064
Accrued interest		8,421			34,536			2,380
Other current liabilities		1,032			(11,161	)		20,252
Other assets		2,097			4,135			(3,725	)
Commodity contract termination costs liability		—			—			(259	)
Other liabilities		271			(4,847	)		(13,303	)
Net cash provided by (used in) operating activities of discontinued operations		4,804			54,750			(7,981	)
Net cash provided by operating activities		763,104			486,120			523,695
Cash Flows From Investing Activities:
Capital expenditures		(447,325	)		(306,461	)		(265,618	)
Proceeds from asset sales		2,591			66,497			24,039
Purchase of minority interest in Hunlock Creek Energy Ventures		(13,900	)		—			—
Decrease (increase) in restricted funds		8,666			207,268			(183,830	)
Other investments		(4,278	)		(2,644	)		2,130
Net cash provided by investing activities of discontinued operations		50,402			226,829			161,378
Net cash provided by (used in) investing activities		(403,844	)		191,489			(261,901	)
Cash Flows From Financing Activities:
Net repayments of short-term debt		—			—			(53,610	)
Issuance of long-term debt		1,571,289			1,849,061			2,811,547
Repayment of long-term debt		(2,102,854	)		(2,406,870	)		(3,506,000	)
Payments on capital lease obligations		(60	)		—			—
Redemption of preferred stock of subsidiary		—			(50,000	)		—
Proceeds from issuance of common stock		—			—			151,360
Proceeds from exercise of employee stock options		24,691			2,941			227
Cash dividends paid to minority shareholder in Hunlock Creek Energy Ventures		(400	)		—			(1,100	)
Net cash used in financing activities of discontinued operations		—			(11	)		(3,348	)
Net cash used in financing activities		(507,334	)		(604,879	)		(600,924	)
Net increase (decrease) in cash and cash equivalents		(148,074	)		72,730			(339,130	)
Cash and cash equivalents at beginning of period		262,212			189,482			528,612
Cash and cash equivalents at end of period	$	114,138		$	262,212		$	189,482
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest (net of amount capitalized)	$	241,300		$	399,797		$	392,526
Income taxes, net	$	3,204		$	3,215		$	(2,748	)

See accompanying Notes to Consolidated Financial Statements

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

	As of December 31,
(In thousands)	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	114,138		$	262,212
Accounts receivable:
Customer		167,792			179,634
Unbilled utility revenue		117,977			129,111
Wholesale and other		63,894			82,261
Allowance for uncollectible accounts		(14,591	)		(16,778	)
Materials and supplies		96,117			98,069
Fuel		74,951			67,273
Deferred income taxes		127,531			93,404
Prepaid taxes		44,603			45,758
Assets held for sale (Note 8)		—			1,521
Collateral deposits		39,399			147,775
Commodity contracts		1,430			9,325
Restricted funds		12,923			21,589
Regulatory assets		39,128			38,418
Other		24,130			14,246
Total current assets		909,422			1,173,818
Property, Plant and Equipment, Net:
Generation		5,820,278			5,751,077
Transmission		1,056,759			1,028,323
Distribution		3,597,405			3,448,350
Other		412,894			429,108
Accumulated depreciation		(4,636,972	)		(4,508,707	)
Subtotal		6,250,364			6,148,151
Construction work in progress		262,529			129,277
Total property, plant and equipment, net		6,512,893			6,277,428
Investments and Other Assets:
Non-current assets held for sale (Note 8)		—			48,559
Goodwill		367,287			367,287
Investments in unconsolidated affiliates		28,259			28,555
Intangible assets		—			27,396
Other		27,932			49,413
Total investments and other assets		423,478			521,210
Deferred Charges:
Regulatory assets		674,095			544,810
Other		32,558			41,546
Total deferred charges		706,653			586,356
Total Assets	$	8,552,446		$	8,558,812

See accompanying Notes to Consolidated Financial Statements.

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ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (continued)

	As of December 31,
(In thousands, except share data)	2006			2005
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Long-term debt due within one year (Note 4)	$	201,189		$	477,217
Accounts payable		236,706			316,713
Accrued taxes		136,216			154,587
Commodity contracts		5,984			92,934
Accrued interest		99,854			91,433
Other		140,830			153,570
Total current liabilities		820,779			1,286,454
Long-term Debt (Note 4)		3,383,986			3,624,483
Deferred Credits and Other Liabilities:
Commodity contracts		17,982			22,994
Investment tax credit		72,938			76,965
Deferred income taxes		936,911			706,092
Obligations under capital leases		26,007			16,427
Regulatory liabilities		464,092			454,275
Adverse power purchase commitment		166,937			184,224
Other		547,706			445,614
Total deferred credits and other liabilities		2,232,573			1,906,591
Commitments and Contingencies (Note 25)
Minority Interest		10,713			21,989
Preferred Stock of Subsidiary		24,000			24,000
Common Stockholders’ Equity:
Common stock, $1.25 par value, 260 million shares authorized and 165,409,908 and 163,002,295 shares issued at December 31, 2006 and 2005, respectively		206,762			203,753
Other paid-in capital		1,907,879			1,880,644
Retained earnings (accumulated deficit)		74,698			(244,625	)
Treasury stock at cost; 49,493 shares		(1,756	)		(1,756	)
Accumulated other comprehensive loss		(107,188	)		(142,721	)
Total common stockholders’ equity		2,080,395			1,695,295
Total Liabilities and Stockholders’ Equity	$	8,552,446		$	8,558,812

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Capitalization

				As of December 31,
(Dollar amounts in thousands)				2006			2005
Common Stockholders’ Equity				$	2,080,395		$	1,695,295
Preferred Stock of Subsidiary, $100 par value:
	As of December 31, 2006
Series	Regular Call Price Per Share		Interest Rate %
240,000 shares outstanding at December 31, 2006 and 2005	$	102.86 to $106.50	4.40 – 6.28	$	24,000		$	24,000
Long-term Debt:
	As of December 31, 2006
	Maturities		Interest Rate %
Medium-term notes		2010-2012	6.625 – 8.250	$	1,240,000		$	1,340,000
First mortgage bonds		2014-2017	5.125 – 6.700		905,000			810,000
AE Supply Credit Facility		2011	6.097 – 6.116		747,000			988,979
2005 AE Credit Facility		—	—		—			199,000
Pollution control bonds		2007-2029	4.700 – 6.875		356,065			356,065
Transition bonds		2008-2010	4.460 – 6.980		245,757			316,284
Debentures		2023	6.875		100,000			100,000
Unamortized debt discounts		—	—		(8,647	)		(8,628	)
Total long-term debt (including current portion of $201,189 and $477,217 at December 31, 2006 and 2005, respectively)				$	3,585,175		$	4,101,700
Total Capitalization				$	5,689,570		$	5,820,995

See accompanying Notes to Consolidated Financial Statements.

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

(In thousands, except shares)	Shares outstanding		Common stock			Other paid-in capital			Retained earnings (deficit)			Treasury stock			Accumulated other comprehensive income (loss)			Total stockholders’ equity			Comprehensive income (loss)
Balance at December 31, 2003	126,968,238		$	158,761		$	1,447,830		$	2,910		$	(1,438	)	$	(92,204	)	$	1,515,859
Net loss	—			—			—			(310,598	)		—			—			(310,598	)	$	(310,598	)
Minimum pension liability adjustment, net of tax of $10,477	—			—			—			—			—			(14,677	)		(14,677	)		(14,677	)
Unrealized gain on available-for-sale securities, net of tax of $167	—			—			—			—			—			87			87			87
Unrealized losses on cash flow hedges for the period, net of tax of $1,210	—			—			—			—			—			(1,947	)		(1,947	)		(1,947	)
Comprehensive loss																					$	(327,135	)
Issuance of common stock for Employee Stock Ownership and Savings Plan	363,361			454			5,591			—			—			—			6,045
Issuance of common stock, net	10,000,000			12,500			138,860			—			—			—			151,360
Stock-based compensation expense:
Stock units	—			—			6,729			—			—			—			6,729
Non employee stock awards	16,000			20			484			—			—			—			504
Exercise of stock options	17,000			21			206			—			—			—			227
Settlement of stock units	30,000			38			422			—			—			—			460
Other	(13,955	)		(6	)		93			(2	)		(318	)		—			(233	)
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	)
Unrealized losses on cash flow hedges for the period, 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

See accompanying Notes to Consolidated Financial Statements.

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

(In thousands, except shares)	Shares outstanding	Common stock		Other paid-in capital			Retained earnings (deficit)			Treasury stock			Accumulated other comprehensive income (loss)			Total stockholders’ equity			Comprehensive income
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 No. 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
Decreased unrealized losses on cash flow hedges for the period, 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note No.		Page No.
1	Basis of Presentation	134
2	Stock-Based Compensation	143
3	Review of Estimated Remaining Service Lives and Depreciation Practices	148
4	Capitalization	148
5	Derivative Instruments and Hedging Activities	154
6	Jointly Owned Electric Utility Plants	154
7	Discontinued Operations	155
8	Asset Sales	156
9	Business Segments	157
10	Pension Benefits and Postretirement Benefits Other Than Pensions	158
11	Income Taxes	165
12	Goodwill and Intangible Assets	167
13	Income (Loss) per Share	169
14	Rates and Regulation	170
15	Regulatory Assets and Liabilities	171
16	Adverse Power Purchase Commitment Liability	172
17	Asset Retirement Obligations (“ARO”)	172
18	Dividend Restriction	173
19	Fair Value of Financial Instruments	173
20	Other Income and Expenses, Net	174
21	Quarterly Financial Information (Unaudited)	175
22	Guarantees and Letters of Credit	176
23	Variable Interest Entities	177
24	HCEV Partnership Interest	177
25	Commitments and Contingencies	178
26	Subsequent Event—Asset Swap	187

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1:  BASIS OF PRESENTATION

Allegheny Energy, Inc. (“AE”) operates primarily through directly and indirectly owned subsidiaries (together with AE, “Allegheny”). Allegheny’s two business segments are the Delivery and Services segment and the Generation and Marketing segment.

The Delivery and Services segment primarily consists of Allegheny’s regulated utility subsidiaries. These subsidiaries include Monongahela Power Company (“Monongahela”), excluding its generation operations, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”) (collectively, the “Distribution Companies”). The Distribution Companies 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. The Delivery and Services segment also includes Allegheny Ventures, Inc. (“Allegheny Ventures”) and Trans-Allegheny Interstate Line Company (“TrAIL Company”). TrAIL Company was formed in 2006 in connection with the management and financing of transmission expansion projects, including Allegheny’s 210-mile 500 KV transmission line.

The Generation and Marketing segment primarily consists of Allegheny’s electric generation subsidiaries. These subsidiaries include Allegheny Energy Supply Company, LLC (“AE Supply”) and Allegheny Generating Company (“AGC”). The Generation and Marketing segment also includes 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 at December 31, 2006 owned approximately 77% and 23% of AGC, respectively. As discussed in Note 26, “Subsequent Event—Asset Swap,” effective January 1, 2007, AE Supply’s and Monongahela’s ownership interests in AGC are approximately 59% and 41%, respectively, as a result of a transfer of assets between AE Supply and Monongahela that realigned generation ownership and contractual arrangements within the Allegheny Energy system (the “Asset Swap”). The Generation and Marketing segment is subject to federal regulation but is not subject to state regulation of rates, except that Monongahela’s generation is subject to state regulation of its rates in West Virginia.

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny. As of December 31, 2006, AESC employed approximately 4,362 employees, of which approximately 1,250 are subject to collective bargaining arrangements.

During the fourth quarter of 2006, Allegheny changed its classification of fuel handling and residual disposal costs within its Consolidated Statements of Operations from “Operations and maintenance” expenses to “Fuel” expenses, to improve comparability with other energy and utility companies and facilitate a better understanding of operating costs. Accordingly, Allegheny reclassified such costs previously reported in the amounts of $18.3 million, $22.4 million and $19.6 million for the nine months ended September 30, 2006 and the years ended December 31, 2005 and 2004, respectively, to conform to the financial statement presentation for the current period. Fuel handling and residual disposal costs for the full year 2006 were $24.7 million.

In addition, certain other amounts in previously issued financial statements have been reclassified to conform to the current presentation.

During 2005, Allegheny recorded a $5.9 million cumulative effect of accounting change related to its adoption of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“Conditional AROs”) (“FIN 47”). For additional information, see Note 17, “Asset Retirement Obligations (“ARO”).”

Significant accounting policies of Allegheny are summarized below.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires Allegheny to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure during the reporting period. On a continuous basis, Allegheny evaluates its estimates, including those related to the calculation of the fair value of commodity contracts and derivative instruments, unbilled revenues, goodwill, provisions for depreciation and amortization, regulatory assets and liabilities, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Allegheny develops its estimates based on GAAP, historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Consolidation

The Consolidated Financial Statements include the accounts of AE and its wholly owned and controlled subsidiaries. All significant intercompany balances and transactions have been eliminated. The Consolidated Financial Statements have been prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of 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”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs, 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 No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation 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 15, “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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

PJM Interconnection, LLC (“PJM”) is a regional transmission organization. To facilitate the economic dispatch of Allegheny’s generation, most of the power that Allegheny generates is sold into the PJM market, and most of the power needed to meet the needs of customers of the Distribution Companies is purchased from the PJM market. The majority of PJM purchases and sales are reported on a net basis in “Operating revenues.”

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

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

Allegheny has netting agreements with various counterparties, which provide the right to set off amounts due from or to the counterparty. In cases in which these netting agreements are in place, Allegheny records the fair value of commodity contract assets and liabilities and accounts receivable and accounts payable with counterparties on a net basis. Cash flows associated with derivative contracts are recorded in cash flows from operating activities.

See Note 5, “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 cycle 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Deferred Energy Costs, Net

Historically, the difference between the costs of fuel, purchased energy and certain other costs billed to regulated electric utility customers has been deferred until it is either recovered from or credited to customers under state fuel and energy cost-recovery procedures. With the exception of the two power purchase agreement under the Public Utility Regulatory Policies Act of 1978 (“PURPA”) that remain subject to a deferred energy cost mechanism described below, fuel and purchased energy costs for the regulated electric utilities have been expensed as incurred, because the applicable state regulatory bodies eliminated their deferred energy cost mechanisms. However, Monongahela and Potomac Edison have filed a request with the West Virginia Public Service Commission (the “West Virginia PSC”) to reinstate deferred fuel accounting. The outcome of this request is pending.

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

To satisfy certain of its obligations under PURPA, Allegheny, through 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 on Potomac Edison’s Consolidated Balance Sheets as deferred energy costs, pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge. Because the AES Warrior Run Surcharge represents a dollar-for-dollar recovery of net contract costs, AES Warrior Run Surcharge revenues or revenues from sales of AES Warrior Run output do not impact Potomac Edison’s net income.

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 provides for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia PSC authorized Monongahela and Potomac Edison 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 will be tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge.

Debt Issuance Costs

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

Intercompany Transactions

Common Services.    Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for Allegheny. Each entity is responsible for its proportionate share of the cost of services provided by AESC.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

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’s federal funds effective interest rate, or the Federal Reserve’s previous day’s 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 and Monongahela supply electricity to the Distribution Companies in accordance with agreements approved by FERC to meet the majority of the Distribution Companies’ retail provider-of-last-resort (“PLR”) obligations. AE Supply also records ancillary service revenue from the Distribution Companies in accordance with these agreements.

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

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

Long-Lived Assets

Allegheny’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows. There were no impairment charges recorded during 2006. See Note 7, “Discontinued Operations,” for information related to asset impairment charges recorded during 2005 and 2004.

Property, Plant and Equipment

Regulated property, plant and equipment is stated 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, postretirement benefits, taxes and other benefits related to employees engaged in construction. Upon retirement, the costs of depreciable property, plus cost of removal less salvage, are charged to accumulated depreciation with no gain or loss recorded.

Unregulated property, plant and equipment is stated 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, postretirement benefits, taxes and other benefits related to employees engaged in construction. Upon retirement, the costs of depreciable property, less salvage, are charged to accumulated depreciation with no gain or loss recorded.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Consolidated Balance Sheets include the amounts listed below for generation assets not subject to SFAS No. 71 as of December 31, 2006 and 2005:

(In millions)	December 31, 2006			December 31, 2005
Property, plant and equipment	$	4,338.7		$	4,160.4
Amounts under construction included above	$	136.6		$	62.7
Accumulated depreciation	$	(2,054.6	)	$	(1,992.4	)

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

AFUDC, reflected as “Other income and expense, net” and a reduction of interest expense that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is recognized by Allegheny’s utility subsidiaries as a cost of utility property, plant and equipment when the property is not afforded rate base treatment. Rates used by the regulated subsidiaries for computing AFUDC in 2006, 2005 and 2004 averaged 6.42%, 6.79% and 7.27%, respectively. Allegheny recorded AFUDC of $4.9 million, $2.7 million and $1.9 million in 2006, 2005 and 2004, respectively.

For non-utility construction, Allegheny capitalizes interest costs associated with construction. The average interest capitalization rates for 2006, 2005 and 2004 were 7.01%, 7.12% and 7.33%, respectively. Allegheny capitalized $6.9 million, $3.1 million and $3.4 million of interest during 2006, 2005 and 2004, 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 2.5% of average depreciable property in 2006 and 2.8% of average depreciable property in 2005 and 2004. Estimated service lives for generation, T&D and other property at December 31, 2006 are as follows:

	Years
Generation property:
Steam scrubbers and equipment	20-65
Steam generator units	40-80
Internal combustion units	40-43
Hydroelectric dams and facilities	50-152
Transmission and distribution property:
Electric equipment	10-65
Easements	75-100
Other property:
Office buildings and improvements	35-60
General office/other equipment	12-25
Vehicles and transportation	7-25
Computers, software and information systems	5-20

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The Delivery and Service segment’s depreciation expense was $123.0 million, $124.6 million and $120.1 million in 2006, 2005 and 2004, respectively. The Generation and Marketing segment’s depreciation expense was $120.3 million, $152.0 million and $148.0 million in 2006, 2005 and 2004, respectively.

With the assistance of an independent third party, 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. See Note 3, “Review of Estimated Remaining Service Lives and Depreciation Practices,” for additional information.

Maintenance expenses reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily relating to plant outages and storm damage and the replacement of minor items of property. Maintenance costs are expensed as incurred.

Goodwill and Intangible Assets

Allegheny records the acquisition cost in excess of fair value of tangible and intangible assets acquired, less liabilities assumed, as goodwill. Allegheny tests goodwill and intangible assets with indefinite lives for impairment at least annually. Other intangible assets with finite lives are amortized over their useful lives and tested for impairment when events or circumstances warrant.

See Note 12, “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 Operations.

Cash Equivalents

For purposes of the Consolidated Statements of Cash Flows and Consolidated Balance Sheets, temporary cash investments, generally in the form of commercial paper, certificates of deposit, repurchase agreements and money market funds, are considered to be the equivalent of cash.

Restricted Funds

Allegheny had restricted funds at December 31, 2006 and 2005 of $12.9 million and $21.6 million, respectively, which were primarily comprised of $12.9 million and $16.8 million, respectively, of Intangible Transition Charges collected from West Penn customers related to Pennsylvania transition costs.

Collateral Deposits

Allegheny had collateral deposits at December 31, 2006 and 2005 of $39.4 million and $147.8 million, respectively. These deposits are posted as security with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. These amounts are included in “Current assets” on the Consolidated Balance Sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Allegheny also has funds on deposit with a third party that were posted as collateral for the issuance of surety bonds. These amounts were $15.3 million and $41.3 million at December 31, 2006 and 2005, respectively, and are included in the caption “Other” within “Investments and other assets” on the Consolidated Balance Sheets.

Inventory

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

Income Taxes

The Company 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. Net deferred tax assets are recorded when it is more likely than not that such tax benefits will be realized.

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 11, “Income Taxes,” for additional information.

Taxes Collected from Customers and Remitted to Governmental Authorities

Allegheny records taxes collected from customers, which 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 which 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 has noncontributory, defined benefit pension plans 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.

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, are based upon an age and years-of-service vesting schedule, other plan provisions and 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. Allegheny does not provide subsidized medical coverage in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006.

See Note 10, “Pension Benefits and Postretirement Benefits Other Than Pensions” for additional information.

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Stock-Based Compensation

Allegheny maintains certain stock-based compensation arrangements. These arrangements include Allegheny’s Long-Term Incentive Plan (“LTIP”), under which stock option awards, restricted share awards and performance awards may be granted, and Allegheny’s Stock Unit Plan (the “Stock Unit Plan”), under which stock units can be granted to Allegheny’s key employees.

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,” which is defined below. 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 2, “Stock-Based Compensation” for additional information.

Other Comprehensive Income (Loss)

Other comprehensive income (loss) consists of unrealized gains and losses, net of income taxes, from the temporary change in the fair value of available-for-sale securities, cash flow hedges and changes in the funded status of Allegheny’s pension plans.

Accumulated other comprehensive income (loss) included in the shareholders’ equity section of the Consolidated Balance Sheets at December 31, 2006 consisted of $(107.4) million relating to pension and other postretirement employee benefits and $0.2 million relating to cash flow hedges. Amounts at December 31, 2005 consisted of $(111.2) million relating to pension liabilities and $(31.5) million relating to cash flow hedges.

Recent Accounting Pronouncements

The following accounting pronouncements were adopted by Allegheny during 2006:

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 is effective for Allegheny for its December 31, 2006 annual financial statements and its adoption did not impact Allegheny’s financial statements.

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 10, “Pension Benefits and Postretirement Benefits Other than Pensions,” for additional information.

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 2, “Stock-Based Compensation,” for additional information.

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NOTE 2:  STOCK-BASED COMPENSATION

In December 2004, the FASB issued SFAS No. 123R. This statement requires that all share-based payments to employees, including grants of employee stock options, be measured at fair value on the date of grant and recognized as expense over the requisite service period.

Allegheny adopted SFAS No. 123R effective January 1, 2006 using the modified prospective transition method. Under this transition method, the fair value accounting and recognition provisions of SFAS No. 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 No. 123 pro-forma disclosures, net of estimated forfeitures. Prior to the adoption of SFAS No. 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 2006, 2005 and 2004:

(In millions)	2006		2005		2004
Stock options	$	7.9	$	—	$	—
Stock units		4.7		9.9		18.7
Other		1.3		0.7		0.4
Stock-based compensation expense included in operations and maintenance expense		13.9		10.6		19.1
Income tax benefit		5.6		4.3		7.8
Total stock-based compensation expense, net of tax	$	8.3	$	6.3	$	11.3

No stock-based compensation cost was capitalized in 2006, 2005, or 2004.

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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 and 2004 would have been reduced to the pro forma amounts shown below if compensation expense had been determined using the fair value provisions of SFAS No. 123R:

	Year Ended December 31,
(In millions, except per share data)	2005		2004
Consolidated net income (loss), as reported	$	63.1	$	(310.6	)
Add:
Stock-based employee compensation expense included in consolidated net income (loss), net of related tax effects		6.3		11.3
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		11.3		16.1
Consolidated net income (loss), pro forma	$	58.1	$	(315.4	)
Basic income (loss) per share:
As reported	$	0.40	$	(2.40	)
Pro-forma	$	0.37	$	(2.44	)
Diluted income (loss) per share:
As reported	$	0.40	$	(1.83	)
Pro-forma	$	0.36	$	(1.86	)

Stock Options

Allegheny’s 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 of Directors (the “Board”) or the independent directors of the Board. The exercise price per share for each award is equal to or greater than the fair market value of a share of AE’s common stock on the grant date. Stock options vest in annual tranches on a pro-rata basis over the vesting period, which is typically two to five years, and become fully vested and exercisable upon a change in control. Stock options typically expire after 10 years. 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 or disability, in which case, exercisable options will expire three years after the date of termination. 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. For stock options granted in 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 expected term of the 2006 stock option grants was calculated in accordance with Staff Accounting Bulletin No. 107 using the “simplified” method. The risk-free interest rate was

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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 following weighted-average assumptions were used to estimate the fair value of options granted during 2006, 2005 and 2004:

	2006			2005			2004
Annual risk-free interest rate		4.64	%		4.19	%		3.50	%
Expected term of the option (in years)		6.23			6.50			6.00
Expected annual dividend yield		—			—			—
Expected stock price volatility		28.9	%		35.0	%		52.4	%
Grant date fair value per stock option	$	14.36		$	9.40		$	7.18

Stock option activity for the past three years was as follows:

	Stock Options		Weighted Average Price
Outstanding at December 31, 2003	1,505,101		$	35.022
Granted	5,789,421		$	13.482
Exercised	(17,000	)	$	13.350
Forfeited/Expired	(1,117,748	)	$	24.980
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

The grant-date fair value of stock options granted during 2006 was $3.0 million. The total intrinsic value of stock options exercised during 2006 was $24.0 million. Cash received by Allegheny from option exercises totaled $24.7 million in 2006. Allegheny issued new shares to satisfy these stock option exercises. There was no cash tax benefit realized from tax deductions on stock options exercised during 2006 because of existing tax net operating loss carryforwards.

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The following table summarizes information about stock options outstanding and stock options exercisable at December 31, 2006:

	Options Outstanding							Options Exercisable
		Weighted-Average
Range of Exercise Prices	Outstanding as of December 31, 2006	Remaining Contractual Term (in Years)	Exercise Price		Aggregate Intrinsic Value (in millions)			Exercisable as of December 31, 2006	Weighted Average Exercise Price		Aggregate Intrinsic Value (in millions)
$10.00 - $14.99	3,902,721	7.1	$	13.45	$	126.7		1,977,885	$	13.42	$	64.3
$15.00 - $19.99	147,600	8.1	$	19.00		4.0		29,733	$	19.26		0.8
$20.00 - $24.99	65,000	7.5	$	20.90		1.6		29,000	$	20.76		0.7
$25.00 - $29.99	75,000	8.9	$	28.49		1.3		15,000	$	28.49		0.3
$30.00 - $34.99	138,000	3.1	$	31.92		1.9		138,000	$	31.92		1.9
$35.00 - $39.99	122,600	8.5	$	36.97		1.1		20,800	$	39.25		0.1
$40.00 - $44.99	204,417	4.8	$	42.36		0.7		173,417	$	42.28		0.6
$45.00 - $49.99	15,000	4.2	$	46.26		(a	)	15,000	$	46.26		(a	)
Total	4,670,338	7.0	$	16.50	$	137.3		2,398,835	$	17.25	$	68.7

(a) The aggregate intrinsic value of these stock options is zero, because the exercise prices of these stock options exceeded the market price of Allegheny’s stock at December 31, 2006.

As of December 31, 2006, there was approximately $16.8 million of total unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over a weighted-average period of approximately 2 years.

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 and exercisable 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 2006.

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Stock unit activity for the last three years was as follows:

	Number of Stock Units		Weighted-Average Grant Date Fair Value		Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2003	—		$	—	$	—
Granted	3,464,048		$	15.29
Units converted into 30,000 common shares	(30,000	)	$	15.30
Forfeited	(389,888	)	$	15.30
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

The total intrinsic value of stock units converted to shares of AE common stock during 2006 was $70.6 million. AE issued new shares in connection with these 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, 2006, there was $3.0 million of total unrecognized compensation cost related to non-vested outstanding stock units, which is expected to be recognized over a weighted-average period of approximately six months.

Under the Non-Employee Director Stock Plan, each non-employee member of the Board receives, 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. AE’s Board set the 2006, 2005 and 2004 quarterly compensation of each non-employee director at 1,000 shares, 800 shares and 800 shares, respectively, of AE’s common stock. The amount of expense relating to this plan for 2006, 2005 and 2004 was $1.3 million, $0.7 million and $0.4 million, respectively, representing the market price on the date of grant.

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Non-employee director stock plan activity for the last three years was as follows:

	Number of Shares
Shares earned but not issued at December 31, 2003	5,293
Granted	25,600
Issued	(16,000	)
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

NOTE 3:  REVIEW OF ESTIMATED REMAINING SERVICE LIVES AND DEPRECIATION PRACTICES

With the assistance of an independent third party, 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 4:  CAPITALIZATION

Allegheny’s consolidated capital structure, including short-term debt and debt associated with assets held for sale and excluding minority interest, as of December 31, 2006 and 2005, was as follows:

	2006			2005
(In millions, except percent)	Amount		%	Amount		%
Debt	$	3,585.2	63.0	$	4,101.7	70.5
Common equity		2,080.4	36.6		1,695.3	29.1
Preferred stock of subsidiary		24.0	0.4		24.0	0.4
Total	$	5,689.6	100.0	$	5,821.0	100.0

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Common Stock

During 2006, AE issued 2.4 million shares of common stock, primarily in connection with stock option exercises and the settlement of stock units. During 2005, AE issued 0.6 million shares of common stock, primarily in connection with matching contributions to its ESOSP, stock option exercises and the settlement of stock units.

During 2005, AE issued 25.0 million shares of its common stock in connection with a tender offer for $300.0 million in Trust Preferred Securities issued by Allegheny Capital Trust I (“Capital Trust”). See “2005 Debt Activity,” below.

Preferred Stock of Subsidiary

Each share of Monongahela’s preferred stock is entitled, upon voluntary liquidation, to its then current call price and, on involuntary liquidation, to $100 per share.

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

Return of Capital

During October 2005, AE received 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.

Long-Term Debt

At December 31, 2006, contractual maturities of long-term debt are as follows. The table below excludes debt changes due to the January 1, 2007 Asset Swap, which are discussed at Note 26, “Subsequent Event—Asset Swap.”

(In millions)	2007		2008		2009		2010		2011		Thereafter		Total
AE Supply:
Medium-Term Notes	$	—	$	—	$	—	$	—	$	400.0	$	650.0	$	1,050.0
AE Supply Credit Facility		—		—		—		—		747.0		—		747.0
Pollution Control Bonds		91.7		—		—		—		—		191.4		283.1
Debentures-AGC		—		—		—		—		—		100.0		100.0
Total AE Supply	$	91.7	$	—	$	—	$	—	$	1,147.0	$	941.4	$	2,180.1
Monongahela:
First Mortgage Bonds	$	—	$	—	$	—	$	—	$	—	$	340.0	$	340.0
Medium-Term Notes		—		—		—		110.0		—		—		110.0
Pollution Control Bonds		15.5		—		—		—		—		70.2		85.7
Total Monongahela	$	15.5	$	—	$	—	$	110.0	$	—	$	410.2	$	535.7
Potomac Edison:
First Mortgage Bonds	$	—	$	—	$	—	$	—	$	—	$	420.0	$	420.0
Total Potomac Edison	$	—	$	—	$	—	$	—	$	—	$	420.0	$	420.0

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(In millions)	2007			2008			2009			2010			2011			Thereafter			Total
West Penn:
Transition Bonds	$	79.9		$	76.2		$	74.7		$	15.0		$	—		$	—		$	245.8
First Mortgage Bonds		—			—			—			—			—			145.0			145.0
Medium-Term Notes		—			—			—			—			—			80.0			80.0
Total West Penn	$	79.9		$	76.2		$	74.7		$	15.0		$	—		$	225.0		$	470.8
AGC:
Debentures	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0
Total AGC	$	—		$	—		$	—		$	—		$	—		$	100.0		$	100.0
Unamortized debt discounts and premiums		(1.4	)		(1.4	)		(1.4	)		(1.3	)		(1.0	)		(2.1	)		(8.6	)
Eliminations (a)		(2.3	)		—			—			—			—			(110.5	)		(112.8	)
Total consolidated debt	$	183.4		$	74.8		$	73.3		$	123.7		$	1,146.0		$	1,984.0		$	3,585.2

(a) Represents the elimination of AGC’s $100 million 6 7/8% Debentures due 2023, which are also included above under AE Supply, and $12.8 million in the aggregate of Pollution Control Bonds, for which Monongahela and AE Supply were co-obligors. As a result of the Asset Swap, effective January 1, 2007, certain pollution control bond obligations have changed. See Note 6, “Jointly Owned Electric Utility Plants” and Note 26, “Subsequent Event—Asset Swap,” for additional information.

Certain of Allegheny’s properties are subject to liens of various relative priorities securing debt.

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”). The AE Supply Credit Facility matures in 2011 and has a current interest rate equal to the London Interbank Offered Rate (“LIBOR”) plus 0.75%, with decreases in the rate possible if AE Supply’s credit ratings improve from current levels. Proceeds from the AE Supply Credit Facility were used to refinance $967 million outstanding under the 2005 AE Supply’s 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 and has an initial interest rate equal to LIBOR plus 1%, with decreases in the rate possible if AE’s credit ratings improve from current levels. 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, which 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.

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In September 2006, Monongahela issued $150 million aggregate principal amount of 5.70% First Mortgage Bonds, which 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.

In October 2006, Potomac Edison issued $100 million aggregate principal amount of 5.80% First Mortgage Bonds, which 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.

See Note 26, “Subsequent Event—Asset Swap,” for debt changes resulting from the January 1, 2007 Asset Swap.

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
Total AE	$	219.1	$	418.1
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
Total AE Supply	$	967.0	$	1,209.0
Potomac Edison:
First Mortgage Bonds	$	100.0	$	—
Medium-Term Notes		—		100.0
Total Potomac Edison	$	100.0	$	100.0
West Penn:
First Mortgage Bonds	$	145.0	$	—
Transition Bonds (a)		5.2		75.8
Total West Penn	$	150.2	$	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.

2005 Debt Activity

In April 2005, the holders of $295.0 million of the outstanding $300.0 million in Trust Preferred Securities issued by Capital Trust accepted AE and Capital Trust’s tender offer and consent solicitation. Under the terms of the offer, for each $1,000 in liquidation amount of Trust Preferred Securities tendered, a holder received 83.33

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

shares of AE common stock and $160 in cash. On April 22, 2005, AE issued an aggregate of 24.6 million shares of its common stock and $47.2 million in cash to the holders of the tendered Trust Preferred Securities. The $47.2 million cash payment was expensed during the second quarter of 2005. In addition, AE received the required consents from holders of the Trust Preferred Securities for amendments to the indenture governing AE’s 11 ⁷/8% Notes due 2008. The holder of the remaining $5.0 million in liquidation amount of Trust Preferred Securities converted its Trust Preferred Securities into 416,650 shares of AE common stock on May 3, 2005.

On June 16, 2005, AE and AE Supply (together, the “Borrowers”) entered into a $700 million credit facility (the “2005 AE Credit Facility”) comprised of a $400 million senior unsecured revolving credit facility (the “2005 Revolving Facility”) and a $300 million senior unsecured term loan (the “2005 Term Facility”). On August 1, 2005, AE used the proceeds of the 2005 Term Facility to refinance the aggregate principal outstanding amount under AE’s 7.75% Notes due August 1, 2005.

Loans under the 2005 AE Credit Facility bore interest, depending on the type of loan requested by the Borrowers, at a rate equal to either (i) the higher of the rate announced publicly by Citibank in New York, from time to time, as Citibank’s base rate or 0.50% above the Federal Funds Rate (as defined in the Credit Agreement) (the “Base Rate”), plus the applicable margin, which was between 1.50% and 0.50% for Base Rate loans, or (ii) the Eurodollar Rate (as defined in the Credit Agreement), plus the applicable margin, which was between 2.50% and 1.50% for Eurodollar Rate-based loans. The applicable margin for LIBOR borrowings was 2.00% at December 31, 2005. On January 18, 2006, the margin for LIBOR borrowings was reduced to 1.50% as a result of increased Standard & Poor’s (“S&P”) credit ratings on certain of AE’s debt. With respect to each letter of credit, the relevant Borrower was required to pay to the Administrative Agent a letter of credit fee equal to the applicable margin, which ranged from 2.50% to 1.50%, times the daily maximum amount available to be drawn under such letter of credit. In each case of a Base Rate loan, Eurodollar Rate loan or letter of credit, the applicable margin varied depending upon S&P and Moody’s Investors Service, Inc.’s (“Moody’s”) ratings of certain of AE’s public debt. The Borrowers’ ability to request and maintain Eurodollar Rate loans was subject to certain limitations. The 2005 AE Credit Facility was refinanced during 2006, as discussed above under the heading “2006 Debt Activity.”

On July 21, 2005, AE Supply and certain of its subsidiaries entered into a secured term loan facility (the “2005 AE Supply Term Loan”) of $1.07 billion. The 2005 AE Supply Term Loan had an initial interest rate equal to LIBOR plus 1.75%. On January 18, 2006, the margin for LIBOR borrowings was reduced to 1.50% as a result of increased S&P credit ratings on certain of AE Supply’s debt. Proceeds from the 2005 AE Supply Term Loan were used, in part, to refinance approximately $738 million outstanding under a 2004 AE Supply loan. Proceeds from the 2005 AE Supply Term Loan were also used on August 22, 2005 to redeem AE Supply’s 10.25% Senior Notes due 2007, which had a principal amount outstanding of approximately $331 million. Also on August 22, 2005, AE Supply used cash on hand to redeem its 13.0% Senior Notes due 2007, which had a principal amount outstanding of approximately $35 million. AE Supply expensed premiums and costs associated with the redemption of its 10.25% Senior Notes and 13.0% Senior Notes in the amount of $32.6 million during the three months ended September 30, 2005. The 2005 AE Supply Term Loan was refinanced during 2006, as discussed above under the heading “2006 Debt Activity.”

On August 15, 2005, Potomac Edison issued $145 million of 5.125% First Mortgage Bonds due 2015. Approximately $143 million of the proceeds, together with available cash, was used to redeem Potomac Edison’s $65 million of outstanding 7.75% First Mortgage Bonds due 2025 and its $80 million of outstanding 7.625% First Mortgage Bonds due 2025.

On September 27, 2005, WPP Funding, LLC, an indirect subsidiary of West Penn, issued $115.0 million of 4.46% Transition Bonds, Series 2005-A with an expected maturity of June 2010. These bonds securitize an

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intangible right to receive a revenue stream in the form of a transition charge from Pennsylvania rate payers. Interest on these bonds will accrue and be added to the principal amount of the bonds until the first scheduled interest payment date following final payment of the Transition Bonds, Series 1999-A issued by West Penn Funding LLC, which is expected to occur in June 2008. Thereafter, interest on these bonds will be paid quarterly.

On October 17, 2005, Monongahela issued $70.0 million of 5.375% First Mortgage Bonds due 2015. Monongahela utilized the proceeds and available cash to redeem $70.0 million of its 7 ⁵/8% First Mortgage Bonds due 2025 on November 16, 2005.

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

Allegheny made various other debt payments during 2005.

Issuances and repayments of indebtedness, by entity, during 2005 were as follows:

(In millions)	Issuances		Repayments
AE:
2005 AE Credit Facility	$	422.0	$	223.0
Prior Credit Facility		47.0		147.0
Convertible Preferred Securities		—		300.0
Medium-Term Notes		—		300.0
Total AE	$	469.0	$	970.0
Monongahela:
First Mortgage Bonds	$	70.0	$	70.0
AE Supply:
2005 AE Supply Term Loan	$	1,069.0	$	80.0
2004 AE Supply Loan		—		982.1
Medium-Term Notes		—		380.0
Total AE Supply	$	1,069.0	$	1,442.1
Potomac Edison:
First Mortgage Bonds	$	145.0	$	145.0
West Penn:
Transition Bonds (a)	$	116.3	$	73.0
Consolidated Total	$	1,869.3	$	2,700.1
Debt associated with assets held for sale:
Other Notes (b)	$	—	$	86.7

(a) The issuance amounts include $1.3 million of interest that was accrued and added to the principal amount of certain of the bonds.

(b) Represents debt related to Monongahela’s natural gas operations in West Virginia. In connection with the sale of these operations on September 30, 2005, the purchaser assumed this debt.

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NOTE 5:  DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

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

AE Supply has designated certain contracts as cash flow hedges of forecasted sales of electricity. Changes in the fair value of these contracts upon such designation and thereafter are reflected in “Accumulated other comprehensive income” until the hedged item is realized. These contracts expire at various dates through September 2007. The pre-tax accumulated other comprehensive income (loss) for the contracts was $1.3 million at December 31, 2006 and $(50.4) million at December 31, 2005. The decrease in accumulated other comprehensive income related to cash flow hedges is a result of the change in the fair value of these contracts due to contract settlements and changes in market prices. The accumulated other comprehensive loss balance is expected to be completely reclassified as a reduction to earnings over the next twelve months. The ineffective portion of the cash flow hedges of $1.3 million and $(1.1) million is reflected in earnings for the years ended December 31, 2006 and 2005 respectively.

Derivative contracts that are not designated as cash flow hedges or normal purchase and normal sale contracts are accounted for on a mark-to-market basis with changes in fair value reflected in earnings. The recorded net fair value of mark-to-market and cash flow hedge derivative commodity contracts was a net liability of $22.5 million and $106.6 million at December 31, 2006 and 2005, respectively. Operating revenues included net unrealized gains (losses) related to trading activities of $32.4, $20.6 and $(5.7) million and net realized gains (losses) related to cash flow hedges and trading activities of $(27.2), $(24.9) and $59.9 million for the years ended December 31, 2006, 2005 and 2004, respectively.

NOTE 6:  JOINTLY OWNED ELECTRIC UTILITY PLANTS

AGC jointly owns the Bath County generation facility with a non-affiliated third party. For reporting purposes, AGC is consolidated with AE Supply. Monongahela accounts for AGC under the equity method of accounting. AGC’s investment and accumulated depreciation in the Bath County generation facility, at December 31 were as follows:

(Dollars in millions)	2006			2005
Utility plant investment	$	835.6		$	839.0
Accumulated depreciation	$	318.1		$	316.3
Ownership %		40	%		40	%

See Note 24, “HCEV Partnership Interest,” for additional information regarding jointly owned plants.

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NOTE 7:  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 have been classified as discontinued operations in the accompanying Consolidated Statements of Operations, and, through the dates on which these sales concluded, their assets and liabilities have been classified as held for sale in the Consolidated Balance Sheets. See Note 8, “Asset Sales” for additional information.

The components of income (loss) from discontinued operations are as follows:

(In millions)	2006			2005			2004
AE Supply:
Operating revenues	$	—		$	0.4		$	29.3
Operating expenses		7.3			7.2			(28.1	)
Interest expense		(2.5	)		(10.2	)		(27.3	)
Income (loss) before income taxes		4.8			(2.6	)		(26.1	)
Income tax benefit (expense)		(1.8	)		2.6			2.5
Gain from disposal of discontinued operations, net of tax		—			—			1.1
Impairment charge, net of tax		(1.4	)		(7.2	)		(403.9	)
Income (loss) from discontinued operations, net of tax	$	1.6		$	(7.2	)	$	(426.4	)
Monongahela:
Operating revenues	$	—		$	218.1		$	306.4
Operating expenses		(1.7	)		(201.6	)		(285.2	)
Other income		—			1.0			0.2
Interest expense		—			(6.1	)		(8.3	)
Income (loss) before income taxes		(1.7	)		11.4			13.1
Income tax benefit (expense)		0.7			(3.4	)		(5.3	)
Impairment charge, net of tax		—			(7.0	)		(21.7	)
Income (loss) from discontinued operations, net of tax	$	(1.0	)	$	1.0		$	(13.9	)
Consolidated:
Operating revenues	$	—		$	218.5		$	335.7
Operating expenses		5.6			(194.3	)		(313.3	)
Other income		—			1.0			0.2
Interest expense		(2.5	)		(16.3	)		(35.6	)
Income (loss) before income taxes		3.1			8.9			(13.0	)
Income tax benefit (expense)		(1.1	)		(0.8	)		(2.8	)
Gain from disposal of discontinued operations, net of tax		—			—			1.1
Impairment charge, net of tax		(1.4	)		(14.2	)		(425.6	)
Income (loss) from discontinued operations, net of tax	$	0.6		$	(6.1	)	$	(440.3	)

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NOTE 8:  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 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 will provide 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.

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.

Assets held for sale at December 31, 2005, all of which relate to AE Supply, were as follows:

(In millions)	December 31, 2005
Assets:
Current assets	$	1.5
Property, plant and equipment		23.1
Deposit		25.5
Total assets	$	50.1

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NOTE 9:  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 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.

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
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 and amortization		151.3			121.8			—		—			273.1
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			4,077.6			754.8		(549.9	)		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 and amortization		153.6			154.6			—		—			308.2
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			4,079.8			591.1		(334.3	)		8,558.8
2004
External operating revenues	$	2,709.2		$	46.9		$	—	$	—		$	2,756.1
Internal operating revenues		54.9			1,491.8			—		(1,546.7	)		—
Total operating revenues		2,764.1			1,538.7			—		(1,546.7	)		2,756.1
Depreciation and amortization		148.8			150.6			—		—			299.4
Operating income		303.3			285.9			—		—			589.2
Interest expense		125.9			274.5			—		(0.2	)		400.2
Income tax expense (benefit) from continuing operations		79.9			(0.2	)		—		—			79.7
Income from continuing operations		117.3			12.5			—		(0.1	)		129.7
Loss from discontinued operations, net of tax		(14.0	)		(426.4	)		—		0.1			(440.3	)
Net income (loss)		103.3			(413.9	)		—		—			(310.6	)
Capital expenditures		160.5			107.0			—		—			267.5

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NOTE 10:  PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains a Supplemental Executive Retirement Plan (“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 plans, are based upon an age and years-of-service vesting schedule, other plan provisions and 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 No. 158. Allegheny adopted the recognition and disclosure provisions of SFAS No. 158 as of December 31, 2006. SFAS No. 158 requires the Company 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 accumulated other comprehensive income, net of tax. In accordance with SFAS No. 158, at December 31, 2006, Allegheny also derecognized the Additional Minimum Pension Liability (“AML”) and related intangible assets previously recognized under SFAS No. 87, “Employers’ Accounting for Pensions.”

During 2006, Allegheny determined that a portion of the pensions and postretirement benefits other than pensions’ obligations are probable for future recovery under the regulatory ratemaking process in certain of the Company’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 No. 158, with the offsetting credit to other comprehensive income, net of tax. In addition, upon adoption of SFAS No. 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 No. 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 No. 158, in connection with SFAS No. 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 No. 71 Adjustments			Sub-totals			SFAS No. 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 No. 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. The Company is required under SFAS No. 158 to change to a December 31 measurement date by year end 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)	2006			2005			2004			2006			2005			2004
Components of net periodic cost:
Service cost	$	21.7		$	23.6		$	23.5		$	5.1		$	4.0		$	4.3
Interest cost		61.4			63.4			62.7			16.9			16.8			15.3
Expected return on plan assets		(69.6	)		(69.2	)		(68.7	)		(7.0	)		(6.2	)		(6.1	)
Amortization of unrecognized transition obligation		0.5			0.5			0.5			5.7			5.9			5.9
Amortization of prior service cost		3.5			3.6			4.1			—			—			0.2
Recognized actuarial loss		12.4			9.2			5.8			3.8			2.1			0.1
Subtotal		29.9			31.1			27.9			24.5			22.6			19.7
Curtailments, settlements and special termination benefits		—			1.3			6.0			—			3.4			3.4
Net periodic cost	$	29.9		$	32.4		$	33.9		$	24.5		$	26.0		$	23.1
Allocation of net periodic cost:
Monongahela	$	7.7		$	10.0		$	11.6		$	6.8		$	9.0		$	9.3
AE Supply		9.0			9.0			10.7			5.6			5.2			4.5
West Penn		7.4			7.4			6.3			6.7			6.5			4.9
Potomac Edison		5.4			5.5			4.7			5.3			5.0			4.2
AE		0.4			0.5			0.6			0.1			0.3			0.2
Net periodic cost	$	29.9		$	32.4		$	33.9		$	24.5		$	26.0		$	23.1
Portion of net periodic cost above included in discontinued operations	$	—		$	1.7		$	4.4		$	—		$	2.6		$	4.6

For the years ended December 31, 2006, 2005 and 2004, Allegheny allocated $13.0 million, $12.2 million and $11.6 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 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. The net periodic cost for 2004 includes $2.7 million of curtailment charges for pension and $3.4 million of curtailment charges for postretirement benefits other than pensions related to the sale of Monongahela’s West Virginia natural gas operations. See Note 7, “Discontinued Operations,” for additional information.

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The amounts in accumulated other comprehensive loss 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	$	10.6	$	2.4
Prior service cost		3.2		—
Transition obligation		0.5		5.7
Total to be recognized in net periodic cost	$	14.3	$	8.1

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)	2006			2005			2006			2005
Change in benefit obligation:
Benefit obligations at beginning of year	$	1,129.9		$	1,108.8		$	311.3		$	296.1
Service cost		21.7			23.6			5.2			4.0
Interest cost		61.4			63.4			16.8			16.8
Plan participants’ contributions		—			—			3.0			2.1
Curtailments gain		—			(6.2	)		—			—
Settlements gain		—			(2.3	)		—			—
Actuarial (gain)/loss		(31.1	)		8.8			(17.0	)		18.6
Benefits paid		(70.8	)		(66.2	)		(26.0	)		(26.3	)
Benefit obligation at end of year		1,111.1			1,129.9			293.3			311.3
Change in plan assets:
Fair value of plan assets at beginning of year		839.5			765.4			81.5			73.4
Actual return on plan assets		62.9			79.6			7.7			4.0
PBGC premium refund		0.9			—			—			—
Plan participants’ contributions		—			—			3.0			2.1
Employer contribution		65.3			63.0			6.9			15.3
Settlements		—			(2.3	)		—			—
Benefits paid		(70.8	)		(66.2	)		(15.4	)		(13.3	)
Fair value of plan assets at end of year		897.8			839.5			83.7			81.5
Funded status prior to fourth quarter contribution		(213.3	)		(290.4	)		(209.6	)		(229.8	)
Employer contribution in the fourth quarter		0.1			0.1			2.3			8.7
Funded status at December 31		(213.2	)		(290.3	)		(207.3	)		(221.1	)
Unrecognized transition obligation		—			3.2			—			39.8
Unrecognized net actuarial loss		—			276.2			—			83.3
Unrecognized prior service cost due to plan amendments		—			25.0			—			—
Net amounts recognized at December 31	$	(213.2	)	$	14.1		$	(207.3	)	$	(98.0	)

The SERP is a non-qualified pension plan, and Allegheny is therefore not obligated to fund the SERP obligation. The SERP obligation, which is included as a component of the pension benefit obligation, shown in the table above, was $5.9 million and $5.3 million at December 31, 2006 and 2005, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Amounts recognized in the Consolidated Balance Sheets at December 31 were as follows:

	Pension Benefits						Postretirement Benefits Other Than Pensions
(In millions)	2006			2005			2006			2005
Noncurrent assets	$	—		$	27.4		$	—		$	—
Current liabilities		—			—			—			—
Noncurrent liabilities		(213.2	)		(200.2	)		(207.3	)		(98.0	)
Accumulated other comprehensive loss, pre-tax		—			186.9			—			—
Net amounts recognized at December 31	$	(213.2	)	$	14.1		$	(207.3	)	$	(98.0	)

Amounts recognized in “Accumulated other comprehensive loss,” pre-tax, at December 31 were as follows:

	Pension Benefits				Postretirement Benefits Other Than Pensions
(In millions)	2006			2005	2006			2005
Net transition obligation	$	2.8		—	$	34.1		—
Net prior service cost		21.5		—		—		—
Net actuarial loss		238.4		—		62.0		—
Accumulated other comprehensive loss, pre-tax		262.7		—		96.1		—
Regulatory asset		(102.1	)	—		(76.1	)	—
Accumulated other comprehensive loss, pre-tax, recognized at December 31	$	160.6		—	$	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 No. 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 $102.1 million for pension and $76.1 million for postretirement benefits other than pensions.

The accumulated benefit obligation for all defined benefit pension plans was $1,023.3 million and $1,039.9 million at December 31, 2006 and 2005, respectively. The portion of the total accumulated benefit obligation related to the SERP was $4.8 million and $4.8 million at December 31, 2006 and 2005, respectively.

Information for pension plans with a projected benefit obligation and an accumulated benefit obligation in excess of plan assets is as follows:

	Pension Benefits
(In millions)	2006		2005
Projected benefit obligation	$	1,111.1	$	1,129.9
Accumulated benefit obligation	$	1,023.3	$	1,039.9
Fair value of plan assets	$	897.8	$	839.5

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The assumptions used to determine net periodic benefit costs for the years ended December 31, 2006, 2005 and 2004 are shown in the table below.

	Pension Benefits						Postretirement Benefits Other Than Pensions
	2006		2005		2004		2006		2005		2004
Discount rate	5.60	%	5.90	%	6.00	%	5.60	%	5.90	%	6.00	%
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	3.25	%	3.25	%	3.75	%	3.25	%	3.25	%	3.75	%

(a) Excluding administrative expenses.

The assumptions used to determine benefit obligations at December 31, 2006 and 2005 are shown in the table below:

	Pension Benefits				Postretirement Benefits Other Than Pensions
	2006		2005		2006		2005
Discount rate	6.00	%	5.60	%	6.00	%	5.60	%
Rate of compensation increase	3.60	%(a)	3.25	%	3.60	%(a)	3.25	%

(a) Weighted-average rate for age graded scale.

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

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs in 2007 is 8.25%, which is net of administrative expenses.

Assumed health care cost trend rates at December 31 are as follows:

	2006	2005
Health care cost trend rate assumed for next year	9.0%	9.5%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0%	5.0%
Year that the rate reaches the ultimate trend rate	2015	2015

For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.0% beginning with 2007 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 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	$	0.7	$	(0.6	)
Effect on postretirement benefit obligation	$	5.3	$	(4.8	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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, in 2006, Allegheny is receiving the federal subsidy offered under the Medicare Act. Allegheny expects to receive subsidies of approximately $1.5 million to $1.9 million annually during the period from 2007 through 2011. Allegheny received a total subsidy of $1.4 million for 2006.

Plan Assets

Allegheny’s pension plan asset allocations as of the measurement dates of September 30, 2006 and 2005, by asset category are as follows:

	Plan Assets at September 30,
	2006		2005
Asset Category:
Fixed income securities	49	%	51	%
Equity securities	50	%	49	%
Other	1	%	—	%
Total	100	%	100	%

Allegheny’s postretirement benefits other than pension asset allocations as of the measurement dates of September 30, 2006 and 2005, by asset category are as follows:

	Plan Assets at September 30,
	2006		2005
Asset Category:
Fixed income securities	40	%	40	%
Equity securities	59	%	56	%
Cash	1	%	4	%
Total	100	%	100	%

As of September 30, 2006, 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% Other. The category “Other” represents investments in 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, 2006, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 2007 will approximate $50 million. Allegheny also currently anticipates that it will contribute $19 million to $23 million during 2007 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 expectations, 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 benefit payments, which reflect expected future service, as appropriate, are estimated to be paid, and the following federal subsidy payments are expected to be received, by Allegheny as follows:

	Pension Benefits		Postretirement Benefits Other Than Pensions
(In millions)			Benefit Payments		Expected Federal Subsidy
2007	$	65.8	$	22.7	$	1.5
2008	$	66.2	$	22.8	$	1.6
2009	$	66.5	$	23.0	$	1.8
2010	$	67.3	$	23.1	$	1.9
2011	$	68.3	$	23.2	$	1.5
2012 – 2016	$	369.0	$	116.2	$	—

401(k) Savings Plan

The ESOSP was established as a non-contributory stock ownership plan for all eligible employees, effective January 1, 1976, and was amended in 1984 to include a savings program. All of Allegheny’s employees, subject to meeting eligibility requirements, may elect to participate in the ESOSP. Under the ESOSP, each eligible employee can elect to have from 2% to 15% of his or her compensation contributed to the ESOSP on a pre-tax basis and an additional 1% to 6% on a post-tax basis. Participants direct the investment of contributions to specified mutual funds or AE common stock. Allegheny matches 50% of the first 6% of pre-tax compensation deferred into the ESOSP by an employee.

In 2006, AE made ESOSP matching contributions in cash in the amount of $7.5 million. In 2005 and 2004, AE made matching contributions in the form of AE common stock. In 2005, the matching contributions consisted of 294,904 newly issued shares with a market value of $7.8 million. In 2004, the matching contributions consisted of 363,361 newly issued shares and 129,308 shares purchased in the open market with a combined market value of $7.7 million. The fair value of these contributions was expensed, less amounts capitalized in “Construction work in progress.” The capitalized portions of these costs were $1.9 million, $1.9 million and $1.7 million in 2006, 2005 and 2004, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 11:  INCOME TAXES

Details of federal and state income tax expense from continuing operations are as follows:

(In millions)	2006			2005			2004
Income tax expense (benefit)—current:
Federal	$	26.1		$	55.2		$	88.7
State		(16.5	)		(6.5	)		10.0
Total		9.6			48.7			98.7
Income tax expense (benefit)-deferred, net		167.9			22.4			(12.5	)
Amortization of deferred investment tax credit		(4.0	)		(6.3	)		(6.5	)
Total income tax expense from continuing operations	$	173.5		$	64.8		$	79.7

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

On July 2, 2006, the Pennsylvania State budget for fiscal year 2006-2007 was enacted. The budget included a provision that raises 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 remains unchanged at 20 years. Allegheny recorded a benefit during the third quarter of 2006 in the amount of $16.7 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. In the fourth quarter of 2006, an additional $1.5 million for the state income tax effect, net of applicable federal income tax, was recorded.

During the fourth quarter of 2006, Allegheny recorded a charge of $6.6 million, which was the effect of settling prior year audit issues.

During the second quarter of 2005, Allegheny determined that it had not claimed certain income tax deductions in its 2003 income tax returns relating to commodity trading contracts. Allegheny filed a claim for these additional deductions, which increased Allegheny’s recorded tax net operating loss carryforwards in the amount of approximately $210 million and decreased other recorded deferred tax assets in a similar amount, except for certain state income tax effects. Allegheny recorded a charge of $3.8 million during the second quarter of 2005 to write-off state deferred tax assets that will not be realized due to state limitations on the use of net operating loss carryforwards resulting from the filing of this claim. The effect of this adjustment was not material to Allegheny’s results of operations for the year ended December 31, 2005.

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 the second quarter of 2005. The franchise tax has been replaced by a gross receipts tax that will be phased-in over a five year period beginning July 1, 2005.

Allegheny also recorded a $6.9 million charge during the fourth quarter of 2005 to decrease recorded deferred tax assets on deferred compensation due to changes in the timing of payments permitted under the American Jobs Creation Act of 2004.

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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.

Total income tax expense from continuing operations differs from the amount produced by applying the federal statutory income tax rate of 35% to income from continuing operations before income taxes and minority interest, due to the following reconciling items:

	2006					2005					2004
(In millions, except percent)	Amount			%		Amount			%		Amount			%
Income from continuing operations before income taxes and minority interest	$	494.8				$	140.5				$	208.5
Preferred dividend of subsidiary		1.2					4.1					5.0
Subtotal		496.0					144.6					213.5
Income tax expense calculated using the federal statutory rate of 35%		173.6		35.0			50.6		35.0			74.7		35.0
Increases (reductions) resulting from:
Tax deductions for which deferred tax was not provided:
Depreciation		6.9		1.4			7.5		5.2			0.5		0.2
Plant removal costs		(2.0	)	(0.4	)		(1.9	)	(1.3	)		(2.2	)	(1.0	)
State income tax, net of federal income tax benefit		14.9		3.0			7.2		5.0			7.6		3.5
Amortization of deferred investment tax credit		(4.0	)	(0.8	)		(6.3	)	(4.3	)		(6.5	)	(3.0	)
Reduction in tax benefits for deferred compensation		—		—			6.0		4.1			—		—
Effect of Pennsylvania legislation		(18.2	)	(3.7	)		—		—			—		—
Effect of prior year audit issues		6.6		1.3			—		—			—		—
Other, net		(4.3	)	(0.8	)		1.7		1.1			5.6		2.6
Total income tax expense	$	173.5		35.0		$	64.8		44.8		$	79.7		37.3

The income tax benefit for loss from discontinued operations differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount as set forth below:

(In millions)	2006		2005			2004
Income (loss) from discontinued operations, before income taxes	$	3.7	$	(12.1	)	$	(702.6	)
Income tax benefit calculated using the federal statutory rate of 35%	$	1.3	$	4.2		$	245.9
Increased for state income tax benefit, net of federal income tax expense (Primarily due to the impairment of the tax benefit on the sale of an asset)		1.8		1.7			16.4
Total income tax benefit	$	3.1	$	5.9		$	262.3

The income tax benefit for the cumulative effect of accounting changes differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount, as set forth below:

(In millions)	2005
Cumulative effect of accounting changes, before income taxes	$	(9.3	)
Income tax benefit calculated using the federal statutory rate of 35%	$	3.3
Increased for state income tax benefit, net of federal income tax expense		0.1
Total income tax benefit	$	3.4

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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)	2006			2005
Deferred income tax assets:
Recovery of transition costs	$	19.8		$	11.1
Unamortized investment tax credit		35.6			45.1
Postretirement benefits		100.6			111.1
Tax effect of net operating loss carryforwards		554.2			488.2
Fair value of commodity contracts		9.1			41.7
Valuation allowance on state net operating loss		(21.2	)		(9.4	)
Other		73.0			66.1
Total deferred income tax assets		771.1			753.9
Deferred income tax liabilities:
Plant asset basis differences, net		1,506.0			1,289.5
Other		74.5			77.1
Total deferred income tax liabilities		1,580.5			1,366.6
Total net deferred income tax liability		809.4			612.7
Deferred income taxes included in current assets		127.5			93.4
Total long-term net deferred income tax liability	$	936.9		$	706.1

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 FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109 (“FIN 48”), which is effective for fiscal periods beginning after December 15, 2006. FIN 48 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 positions should initially be recognized in the financial statements when it is more likely than not the position will be sustained upon examination by the tax authorities. Such tax positions should be initially and subsequently 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. The Company will be required to apply the provisions of FIN 48 to all tax positions upon initial adoption with any cumulative effect adjustment to be recognized as an adjustment to retained earnings. Upon adoption on January 1, 2007, management estimates that a cumulative effect adjustment of approximately $11 million will be charged to retained earnings to increase reserves for uncertain tax positions.

NOTE 12:  GOODWILL AND INTANGIBLE ASSETS

The recorded goodwill of $367.3 million at December 31, 2006 and 2005 was attributable to the Generation and Marketing segment. There were no additions to, or disposals of, goodwill during 2006 and 2005. Goodwill and intangible assets with indefinite lives are not amortized. Instead, they are tested annually for impairment, with impairment losses recognized in operating income. Absent any impairment indicators, Allegheny performs its annual impairment tests during its third quarter in connection with its annual budgeting process. The annual impairment test used a discounted cash flow methodology to determine the fair value of the Generation and Marketing segment and indicated no impairment of goodwill.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Intangible assets of $27.4 million as of December 31, 2005 related to an additional minimum pension liability, as discussed in Note 10, “Pension Benefits and Postretirement Benefits Other Than Pensions.”

Additional intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:

	December 31, 2006				December 31, 2005
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Land easements, amortized	$	97.9	$	28.4	$	97.7	$	27.1
Land easements, unamortized		30.7		—		30.6		—
Software		47.0		31.1		72.3		50.9
Total	$	175.6	$	59.5	$	200.6	$	78.0

Amortization expense for intangible assets was $14.9 million, $15.3 million and $19.1 million in 2006, 2005 and 2004, respectively.

Amortization expense for intangible assets at December 31, 2006 is estimated to be as follows:

(In millions)	2007		2008		2009		2010		2011
Annual amortization expense	$	8.2	$	4.6	$	4.0	$	3.0	$	2.1

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 13:  INCOME (LOSS) PER SHARE

The following table provides a reconciliation of the numerators and the denominators for the basic and diluted earnings (loss) per share computations:

(In millions, except per share amounts)	2006		2005			2004
Basic Income (Loss) per Share:
Numerator:
Income from continuing operations, net of tax	$	318.7	$	75.1		$	129.7
Redemption of preferred stock		—		(0.4	)		—
Income from continuing operations, net of tax after redemption of preferred stock		318.7		74.7			129.7
Income (loss) from discontinued operations, net of tax		0.6		(6.1	)		(440.3	)
Cumulative effect of accounting changes, net of tax		—		(5.9	)		—
Net income (loss)	$	319.3	$	62.7		$	(310.6	)
Denominator:
Weighted average common shares outstanding		164,184,165		155,016,346			129,485,679
Basic Income (Loss) per Share:
Income from continuing operations, net of tax	$	1.94	$	0.48		$	1.00
Loss from discontinued operations, net of tax		—		(0.04	)		(3.40	)
Cumulative effect of accounting changes, net of tax		—		(0.04	)		—
Net income (loss)	$	1.94	$	0.40		$	(2.40	)
Diluted Income (Loss) per Share:
Numerator:
Income from continuing operations, net of tax	$	318.7	$	75.1		$	129.7
Redemption of preferred stock		—		(0.4	)		—
Interest expense on convertible securities, net of tax		—		—			24.7
Income from continuing operations, net of tax after redemption of preferred stock and interest		318.7		74.7			154.4
Income (loss) from discontinued operations, net of tax		0.6		(6.1	)		(440.3	)
Cumulative effect of accounting changes, net of tax		—		(5.9	)		—
Net income (loss)	$	319.3	$	62.7		$	(285.9	)
Denominator:
Weighted average common shares outstanding		164,184,165		155,016,346			129,485,679
Effect of dilutive securities:
Stock options		2,611,827		1,366,238			355,983
Performance shares		30,668		53,557			85,235
Non-employee stock awards		47,470		25,200			2,800
Stock units		1,805,253		2,172,410			1,561,993
Convertible securities		—		—	(a)		25,000,000
Total shares		168,679,383		158,633,751			156,491,690
Diluted Income (Loss) per Share:
Income from continuing operations, net of tax	$	1.89	$	0.47		$	0.99
Loss from discontinued operations, net of tax		—		(0.04	)		(2.82	)
Cumulative effect of accounting changes, net of tax		—		(0.03	)		—
Net income (loss)	$	1.89	$	0.40		$	(1.83	)

(a) The table below shows the following anti-dilutive shares not included above:

	2006	2005	2004
Convertible securities	—	7,614,991	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 14:  RATES AND REGULATION

The interstate transmission services and wholesale power sales of the Distribution Companies and AE Supply are regulated by FERC under the Federal Power Act. The Distribution Companies’ local distribution service and sales at the retail level are subject to state regulation. Each of the states in Allegheny’s service territory other than West Virginia has, to some extent, deregulated its electric utility industry, although recent legislation under consideration in Virginia proposes some degree of re-regulation. Pennsylvania, Maryland and Virginia have instituted retail customer choice and are transitioning to market-based, rather than cost-based pricing for generation.

In West Virginia, the rates charged to retail customers are regulated by the West Virginia PSC and are determined through traditional, cost-based, regulated utility rate-making. In July 2006, Monongahela and Potomac Edison filed a request with the West Virginia PSC to increase rates related to fuel and purchased power costs, including reinstatement of a fuel cost recovery clause and a decrease in base rates. The proceeding is scheduled to be finalized in May 2007 with the resulting rate being effective immediately.

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

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

In December 2006, Allegheny proposed a rate stabilization and transition plan that would gradually transition Maryland residential customers from capped generation rates to rates based on market prices, while preserving for customers the benefit of previous rate caps. Under the proposed plan, customers would pay a distribution surcharge beginning March 31, 2007 and lasting through December 31, 2008. With the expiration of the capped generation rates on January 1, 2009, funds collected through the surcharge, plus interest, would be returned to customers as a credit on their electric bills. The credit would continue, with adjustments, to maintain rate stability until December 31, 2010. Amounts collected by Allegheny through the surcharge would not impact Allegheny’s net income. Following public hearings, Allegheny filed an alternate proposal that would, among other things, provide customers with the ability to opt out of the surcharge. Allegheny’s proposed rate stabilization plan is subject to final approval by the Maryland PSC.

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

The transition periods could be altered by legislative, judicial or, in some cases, regulatory actions.

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NOTE 15:  REGULATORY ASSETS AND LIABILITIES

Certain of Allegheny’s regulated utility operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:

(In millions)	2006		2005
Regulatory assets, including current portion:
Income taxes	$	300.4	$	312.2
Pension and other postretirement benefits		178.2		—
Pennsylvania stranded cost recovery		55.6		88.1
Pennsylvania Competitive Transition Charge (“CTC”) reconciliation		107.4		97.7
Unamortized loss on reacquired debt		39.6		44.8
Other		32.0		40.4
Subtotal		713.2		583.2
Regulatory liabilities, including current portion:
Net asset removal costs		421.4		413.0
Income taxes		38.9		41.3
Other		4.5		—
Subtotal		464.8		454.3
Net regulatory assets	$	248.4	$	128.9

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 17, “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 cost in the determination of rates charged to customers. In these jurisdictions a deferred income tax liability is recorded with an offsetting regulatory asset. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. These deferred income taxes primarily relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. No return is allowed on the regulatory asset for income taxes.

Pension and Other Postretirement Benefits

See Note 10, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for a discussion of regulatory assets relating to pension and other postretirement benefits.

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Pennsylvania Stranded Cost Recovery and CTC Reconciliation

Allegheny has recorded a regulatory asset for recovery in Pennsylvania of stranded cost, representing the portion of transition costs determined by the Pennsylvania PUC in 1998 to be recoverable by West Penn under its deregulation plan. The stranded cost recovery regulatory asset is being recovered over the transition period that was scheduled to end in 2008. In addition, the Pennsylvania PUC authorized West Penn to defer the difference between authorized and billed stranded cost recovery revenues, with an 11% return on the deferred amounts, for future full and complete recovery from customers. This difference represents a separate regulatory asset (“Pennsylvania CTC Reconciliation”). On April 21, 2005, the Pennsylvania PUC extended the transition period through 2010 and authorized West Penn to securitize additional transition costs including CTC from 1999 through 2004. Stranded cost recovery rates include return on, as well as recovery of, transition costs. The amount of under-recovery of CTC during the transition period, if any, will be determined at the end of the transition period through 2010.

NOTE 16:  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 No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71,” in 1998 to reflect the disallowances of certain costs in the order. This charge included an estimated amount for an adverse power purchase commitment 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, 2006, Allegheny’s reserve for adverse power purchase commitments was $184.2 million, including a current liability of $17.3 million. Allegheny’s liability for adverse power purchase commitments decreased as follows:

(In millions)	2006		2005		2004
Amortization of liability for adverse power purchase commitments	$	17.2	$	16.7	$	18.0

These decreases in the reserve for adverse power purchase commitments are recorded as expense reductions in “Purchased power and transmission” on the Consolidated Statements of Operations.

NOTE 17:  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 generating facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”).

The following is an analysis of the changes in the ARO liability in 2006:

(In millions)	ARO Liability
Balance at December 31, 2005	$	48.8
Accretion of the liability		5.5
New ARO liability		1.8
Settlements of ARO liabilities		(1.3	)
Balance at December 31, 2006	$	54.8

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Effective December 31, 2005, Allegheny adopted FIN 47. The effect of adopting FIN 47 on Allegheny’s Consolidated Financial Statements in 2005 was as follows:

	Effect of Adopting FIN 47 Increase (Decrease)
(In millions)	Property, Plant and Equipment, Net		Non-Current Regulatory Asset		Non-Current Liabilities (Conditional AROs)		Decrease in Pre-Tax Income			Decrease in Net Income (a)
AE Supply	$	0.5	$	—	$	9.8	$	(9.3	)	$	(5.9	)
Monongahela		0.3		5.3		5.6		—			—
Potomac Edison		—		0.3		0.4		—			—
West Penn		—		0.4		0.4		—			—
Total Allegheny	$	0.8	$	6.0	$	16.2	$	(9.3	)	$	(5.9	)

(a) Recorded within “Cumulative effect of accounting change” in 2005 on the Consolidated Statements of Operations.

The impact of adopting FIN 47 on years prior to 2005 was not material.

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 18:  DIVIDEND RESTRICTION

There were no dividends declared or paid on AE’s common stock during 2006, 2005 or 2004. AE may not declare or pay cash dividends on its common stock under the AE Credit Facility. See Note 4, “Capitalization,” for additional information regarding the AE Credit Facility.

NOTE 19:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year and preferred stock of a subsidiary, at December 31, 2006 and 2005 were as follows:

	2006				2005
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	3,585.2	$	3,694.9	$	4,101.7	$	4,272.6
Preferred stock of subsidiary (all series)	$	24.0	$	21.3	$	24.0	$	17.8

The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The fair value of preferred stock is based on quoted market prices. The carrying amounts of cash equivalents and short-term debt approximate the fair values of these financial instruments because of the short maturities of these instruments.

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NOTE 20:  OTHER INCOME AND EXPENSES, NET

Other income and expenses, net represent non-operating income and expenses before income taxes. The following table summarizes Allegheny’s other income and expenses, net:

(In millions)	2006		2005		2004
Interest and dividend income	$	18.3	$	14.3	$	6.5
Cash received from a former trading executive’s forfeited assets		—		11.2		—
Proceeds from sale of America’s Fiber Network, LLC		—		5.5		—
Premium services		4.2		3.7		3.9
Coal brokering income, net		1.9		2.2		2.1
Gain on land sales		1.3		1.7		9.7
Tax reimbursement on contributions in aid of construction		6.5		3.0		2.8
Impairment charges related to certain assets		—		—		(2.1	)
Impairment charges related to unregulated investments		—		—		(1.9	)
Storm restoration, net		—		—		1.9
Other		1.8		2.6		1.6
Total other income and expenses, net	$	34.0	$	44.2	$	24.5

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NOTE 21:  QUARTERLY FINANCIAL INFORMATION (Unaudited)

	2006 Quarter Ended (a)											2005 Quarter Ended (a)
(In millions, except per share data)	December 31		September 30			June 30			March 31			December 31			September 30			June 30			March 31
Total operating revenues	$	737.0	$	816.6		$	722.2		$	845.6		$	724.1		$	845.1		$	714.7		$	754.0
Operating income	$	157.9	$	211.2		$	115.4		$	247.8		$	73.6		$	171.1		$	112.1		$	180.0
Income (loss) from continuing operations	$	61.8	$	110.7		$	32.0		$	114.2		$	3.4		$	43.5		$	(6.1	)	$	34.4
Income (loss) from discontinued operations, net		2.8		(0.5	)		(0.9	)		(0.8	)		5.6			(7.8	)		(12.3	)		8.2
Cumulative effect of accounting change, net		—		—			—			—			(5.9	)		—			—			—
Net income (loss)	$	64.6	$	110.2		$	31.1		$	113.4		$	3.1		$	35.7		$	(18.4	)	$	42.6
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.37	$	0.67		$	0.20		$	0.70		$	0.02		$	0.27		$	(0.04	)	$	0.25
Income (loss) from discontinued operations, net		0.02		—			(0.01	)		—			0.04			(0.05	)		(0.08	)		0.06
Cumulative effect of accounting change, net		—		—			—			—			(0.04	)		—			—			—
Net income (loss)	$	0.39	$	0.67		$	0.19		$	0.70		$	0.02		$	0.22		$	(0.12	)	$	0.31
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.37	$	0.65		$	0.19		$	0.68		$	0.02		$	0.26		$	(0.04	)	$	0.24
Income (loss) from discontinued operations, net		0.01		—			(0.01	)		(0.01	)		0.04			(0.05	)		(0.08	)		0.05
Cumulative effect of accounting change, net		—		—			—			—			(0.04	)		—			—			—
Net income (loss)	$	0.38	$	0.65		$	0.18		$	0.67		$	0.02		$	0.21		$	(0.12	)	$	0.29

(a) Amounts may not total to year to date results due to rounding.

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NOTE 22:  GUARANTEES AND LETTERS OF CREDIT

In connection with certain sales, acquisitions and financings, and in the normal course of business, AE and certain of its subsidiaries enter into various agreements that may include guarantees or letters of credit. The AE Credit Facility includes a $400 million revolving facility, any unutilized portion of which is available for the issuance of letters of credit. In addition, the AE Supply Credit Facility includes a $200 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, 2006				December 31, 2005
(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:
Performance of a put option issued in connection with an asset sale (a)	$	—	$	—	$	6.4	$	6.4
Loans and other financing-related matters		—		8.4		—		8.7
Lease agreement		—		4.7		—		4.7
Purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services		—		20.4		—		3.9
Other		0.2		0.2		0.2		0.2
Total Guarantees	$	0.2	$	33.7	$	6.6	$	23.9
Letters of Credit:
Under AE’s Revolving Facility (b)	$	—	$	131.8	$	—	$	136.5
Other (c)		—		2.1		—		1.6
Total Letters of Credit		—		133.9		—		138.1
Total Guarantees and Letters of credit	$	0.2	$	167.6	$	6.6	$	162.0

(a) The $6.4 million guarantee outstanding at December 31, 2005 was terminated during the first quarter of 2006 in connection with the purchase by Allegheny Energy Hunlock Creek LLC (“AE Hunlock”), a wholly owned subsidiary of AE, of a 50% interest owned by UGI Hunlock Creek Development Company (“UGI”) in Hunlock Creek Energy Ventures, LLC (“HCEV”). See Note 24, “HCEV Partnership Interest,” for additional information.

(b) The December 31, 2006 amount is comprised of a letter of credit for $125.0 million that expires in June 2007 and was issued on September 23, 2005 on behalf of Allegheny as collateral to stay enforcement of the judgment in Allegheny’s litigation against Merrill Lynch while an appeal is pending and a letter of credit for $6.8 million issued due to a contractual obligation of Allegheny Ventures that expires in July 2007. The December 31, 2005 amount is comprised of the $125.0 million letter of credit described above, a letter of credit for $9.5 million issued due to an AE Ventures contractual obligation and a $2.0 million letter of credit related to Allegheny Energy Solutions, a subsidiary of Allegheny Ventures.

(c) These amounts are not issued under either the AE Revolving Credit Facility or the AE Supply Revolving Facility.

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NOTE 23:  VARIABLE INTEREST ENTITIES

FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities,” (“FIN 46R”) requires an investor with the majority of the variable interests in 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”) that represents a variable interest. Allegheny has been unable to obtain certain information from the IPPs necessary to determine if the related VIEs should be consolidated.

Potomac Edison and West Penn had power purchases from these two IPPs in the amount of $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 its 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.

NOTE 24:  HCEV PARTNERSHIP INTEREST

Through March 1, 2006, AE Hunlock owned a 50% interest in HCEV, which owned and operated a 48 MW coal-fired generation facility and a 44 MW gas-fired combustion turbine generation facility located on real property in Hunlock Township, Luzerne County, Pennsylvania. UGI also owned a 50% interest in HCEV. UGI held a put option under which it could require AE Supply to purchase UGI’s 50% interest in either the coal-fired facility, the gas-fired facility, or both for a 90-day period beginning on January 24, 2006.

AE, AE Hunlock and AE Supply entered into an agreement dated March 1, 2006 with UGI, UGI Development Company (“UGI Development”), and HCEV under which (a) HCEV distributed the coal-fired facility to UGI together with the working capital, including coal inventory, used in the operation of that facility and any known and unknown liabilities associated with that facility; (b) UGI agreed to indemnify AE, AE Hunlock and AE Supply from and against any known and unknown liabilities associated with the coal-fired facility; (c) after distribution of the coal-fired facility to UGI, AE Hunlock purchased UGI’s 50% interest in HCEV for a cash payment of approximately $13.9 million at closing and a post-closing adjustment of approximately $600,000 for aggregate cash consideration of approximately $14.5 million; (d) AE Hunlock thereby effectively obtained the gas-fired facility together with working capital, including inventory, used in the operation of that facility and any known and unknown liabilities associated with that facility; (e) HCEV was dissolved, and the assets and liabilities of HCEV, including the gas-fired facility, related working capital, including inventory, and any known and unknown liabilities associated with that facility, were contributed to AE Supply; (f) AE Supply agreed to indemnify UGI and its affiliates from and against any known and unknown liabilities associated with the gas-fired facility; (g) UGI Development granted AE Supply easement rights to the real property located in Hunlock Township, Luzerne County, Pennsylvania sufficient to allow for the operation of the gas-fired facility; and (h) AE and UGI agreed that they each will be responsible for 50% of any liabilities arising in connection with HCEV that are not directly attributable to either the coal unit or the gas unit.

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NOTE 25:  COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Allegheny is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.

Global Climate Change.    Allegheny’s generation facilities are primarily coal-fired facilities and, therefore, emit carbon dioxide as coal is consumed. Carbon dioxide, or “CO₂,” is one of the greenhouse gases implicated in global climate change. There is no current technology that enables control of such emissions from existing pulverized, coal-fired power plants, which constitute the majority of Allegheny’s generation fleet. At the same time, Allegheny takes its responsibility for environmental stewardship seriously and recognizes its obligation to its shareholders to address the issue of climate change. Despite the regulatory actions of some states and regional groups in 2006, Allegheny believes that the challenge presented by global climate change can only be resolved with global solutions. In addition, Allegheny believes that the United States must commit to a response that both encourages the development of technology and creates a workable control system. The United States Congress is moving towards the development of national legislation, yet the process is still in its infancy. As such, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures until the exact nature and requirements of a national regulation are known, and the capabilities of control or reduction technologies are more fully understood. Allegheny recognized the possibility that federal legislation and implementation regulations addressing climate change will be adopted some time in the future. Allegheny’s current strategy focuses on:

• developing an accurate CO₂ emissions inventory;

• improving the efficiency of its coal-burning fleet;

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

• following developing technologies for carbon sequestration;

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

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

To the extent that legislation is introduced and programs are developed, Allegheny intends to advocate for a national approach that protects its generating fleet and investments, enhances the environment, and ensures continued energy supply for its customers. Allegheny’s management is following this issue closely and will take further appropriate action as the economics and legislation, if any, unfold.

Clean Air Act Matters.    Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through 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 post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the EPA on March 10, 2005, may accelerate the need to install this equipment by phasing out a portion of currently available allowances.

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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 2007 of about 30,000 to 50,000 tons and may have exposure in 2008 of between 85,000 and 120,000 tons. Monongahela’s exposure is expected to be approximately 70% and 50% of Allegheny’s exposure in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Allegheny continues to evaluate options for compliance, and current plans include the installation of flue gas desulfurization equipment (“Scrubbers”) at its Hatfield’s Ferry and Fort Martin generating facilities by 2009 and the elimination of a scrubber bypass at its Pleasants generation facility by 2008. In July 2006, AE Supply entered into construction contracts with The Babcock & Wilcox Company (“B&W”) and Washington Group International (“WGI”) in connection with its plans to install scrubbers at its Hatfield’s Ferry generation facility.

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

AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. Allegheny estimates that its emission control activities, in concert with its inventory of banked allowances and future transactions, will facilitate its compliance with NOx limits established by the SIP through 2008. Based on these estimates, Allegheny estimates that it will have minimal exposure to the NOx allowance market through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities. Therefore, there can be no assurance that Allegheny’s need to purchase NO_X allowances for these periods will not vary from current estimates.

On March 15, 2005, the United States Environmental Protection Agency (the “EPA”) issued the Clean Air Mercury Rule (“CAMR”) establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and its strategy for compliance. The Pennsylvania Department of Environmental Protection (the “PA DEP”) proposed a more aggressive mercury control rule on June 24, 2006, which is going through the regulatory review process and which is expected to be finalized in the first quarter of 2007. Allegheny is assessing the proposed rule to determine what, if any, effect it would have on Allegheny’s Pennsylvania 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.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO₂ and NO_X, requires that greater reductions in mercury emissions be made more quickly than

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would be required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative and participate in that coalition’s regional efforts to reduce carbon dioxide emission. The 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 by June 2007 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 will work with the MDE on the R. Paul Smith-specific regulations.

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

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology. There are three recent, significant federal court decisions that have addressed the application of NSR requirements to electric utility generation facilities: the Ohio Edison decision, the Duke Energy decision and the Alabama Power decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy and Alabama Power decisions support the industry’s understanding of NSR requirements. The U.S. Court of Appeals for the Fourth Circuit affirmed the Duke Energy decision on June 15, 2005. On May 15, 2006, the U.S. Supreme Court agreed to hear an appeal of the Fourth Circuit’s decision in the Duke Energy case. Oral argument took place on November 1, 2006, and a decision is expected by the summer of 2007. The Supreme Court’s decision may provide clarity on whether the industry’s or the government’s interpretation of 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 Pennsylvania Department of Environmental Protection (the “PA DEP”). The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

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

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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 February 17, 2006, Allegheny filed a motion to dismiss the amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss. On June 30, 2006, Allegheny filed an answer to the plaintiff’s first amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies, and the liability phase of discovery should be completed by June 30, 2007.

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

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

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 joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. These motions remain pending. AE intends to vigorously defend against this action by cannot predict its outcome.

Claims Related to Alleged Asbestos Exposure:  The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their

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obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties in these actions are seeking an allocation of responsibility for historic and potential future asbestos liability.

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

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2006, Allegheny had 828 open cases remaining in West Virginia and four open cases remaining in Pennsylvania.

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 Federal Energy Regulatory Commission (“FERC”) against AE Supply seeking action by FERC to modify prices payable to AE Supply under three trade confirmations between Merrill Lynch and NPC. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with Merrill Lynch under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers. On December 19, 2002, the Administrative Law Judge (“ALJ”) issued findings that no contract modification was warranted. The ALJ determined in favor of NPC that AE Supply, rather than Merrill Lynch, was a proper subject of NPC’s complaint. On June 26, 2003, FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others. FERC did not decide whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, FERC issued an order, on rehearing, affirming its conclusion that the long-term contracts should not be modified. Snohomish County and other parties filed petitions for review of FERC’s June 26, 2003 order with the U.S. Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. 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.

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

Sierra/Nevada.  On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted claims against AE and AE Supply for: (a) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (b) conspiracy and (c) violations of the Nevada state Racketeer Influenced and Corrupt

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Organization (“RICO”) Act. Sierra/Nevada filed an amended complaint on May 30, 2003, which asserted a fourth cause of action against AE and AE Supply for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys’ fees and seeks in excess of $850 million under the RICO count. AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. Thereafter, plaintiffs filed a motion to stay the action, pending the outcome of certain state court proceedings in which they are seeking to reverse the Nevada PUC’s disallowance of expenses. On April 4, 2005, the District Court granted the stay motion, and the action is currently stayed. 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.

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

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

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, for which it had granted Merrill Lynch summary judgment, and with respect to AE and AE Supply’s counterclaims for fraudulent inducement and breach of contract. Following the

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trial, on July 18, 2005, the District Court entered an order: (a) ruling against AE and AE Supply on their fraudulent inducement and breach of contract claims; (b) requiring AE to pay $115 million plus interest to Merrill Lynch; and (c) requiring Merrill Lynch to return its equity interest in AE Supply to AE. On August 26, 2005, the Court entered its final judgment in accordance with its July 18, 2005 ruling. On September 22, 2005, AE and AE Supply filed a notice of appeal of the District Court’s judgment to the U.S. Court of Appeals for the Second Circuit, which heard oral argument on October 30, 2006. Although AE will not be required to pay Merrill Lynch the amount of the judgment while the appeal is pending, AE has posted a letter of credit to secure the judgment.

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

Putative Benefit Plan Class Actions.  In February and March 2003, two putative class action lawsuits were filed against AE in U.S. District Courts for the Southern District of New York and the District of Maryland. The suits alleged that AE and a senior manager violated ERISA by: (a) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (b) failing to diversify plan assets; (c) failing to monitor investment alternatives; (d) failing to avoid conflicts of interest and (e) violating fiduciary duties. The ERISA cases were consolidated in the District of Maryland. On April 26, 2004, the plaintiffs in the ERISA cases filed an amended complaint, adding a number of current and former directors of AE as defendants and clarifying the nature of their claims. Allegheny has entered into an agreement to settle the consolidated ERISA class actions and on February 13, 2007, the District Court entered an order preliminarily approving the settlement. The proposed settlement remains subject to court approval, following notice to class members. Under the proposed settlement, the consolidated ERISA class actions will be dismissed with prejudice in exchange for a cash payment of $4 million, of which approximately $3.9 million will be made by Allegheny Energy’s insurance carrier.

Suits Related to the Gleason Generation Facility.  Allegheny Energy Supply Gleason Generation Facility, LLC, a subsidiary of AE Supply, is the defendant in a suit brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generation facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the generation facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generation facility. They seek a restraining order with respect to the operation of the plant and damages of $200 million. Mediation sessions were held on June 17, 2004 and February 22 and 23, 2006, but the parties did not reach settlement. On September 18, 2006, the Court heard oral argument on Allegheny’s summary judgment motions regarding the plaintiffs’ claims for, among other causes of action, property and punitive damages, and a decision from the Court on these motions is pending. The case has been set for trial on April 2, 2007. AE has undertaken property purchases and other mitigation measures. AE intends to vigorously defend against this action but cannot predict its outcome.

Harrison Fuel Litigation.  On November 7, 2001, Harrison Fuel and its owner filed a lawsuit against Monongahela, “Allegheny Power” and AESC in the Circuit Court of Marion County, West Virginia. The lawsuit claims that Allegheny improperly and arbitrarily rejected bids from Harrison Fuel and other companies affiliated with its owner to supply coal to Allegheny. Plaintiffs seek damages of approximately $13 million. On January 5, 2007, the Court entered an order setting this case for trial on May 14, 2007. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

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.

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Construction and Capital Program

Allegheny estimates that its capital expenditures will approximate $1,030 million in 2007 and $1,120 million in 2008, including amounts relating to significant multiple year environmental control and transmission expansion projects. Capital expenditure levels in 2007 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. See “Environmental Matters and Litigation—Clean Air Act Matters,” above.

Leases

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 $17.8 million, $22.5 million and $28.4 million were recorded as rent expense in 2006, 2005 and 2004, 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)	2007		2008		2009		2010		2011		Thereafter		Total		Less: amount representing interest and fees		Present value of net minimum capital lease payments
Capital Leases	$	10.7	$	8.1	$	6.7	$	5.9	$	3.9	$	5.0	$	40.3	$	7.1	$	33.2
Operating Leases	$	4.6	$	3.5	$	3.4	$	3.4	$	3.3	$	16.1	$	34.3	$	—	$	—

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)	2006		2005
Equipment	$	32.9	$	24.1
Building		0.3		0.4
Property held under capital leases	$	33.2	$	24.5

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 2006, 2005 and 2004 were $203.8 million, $209.0 million and $197.8 million, respectively, before amortization of West Penn’s adverse power purchase commitment. The average cost of these power purchases was approximately 5.4, 5.3 and 5.2 cents per kilowatt-hour in 2006, 2005 and 2004, respectively.

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The table below reflects Allegheny’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2006, by entity. Actual values can vary substantially depending upon future conditions.

	Monongahela			Potomac Edison			West Penn
(In millions)	kWhs	Amount		kWhs	Amount		kWhs	Amount
2007	1,298.2	$	65.0	1,533.6	$	108.3	1,092.2	$	54.1
2008	1,301.2		65.7	1,537.9		110.2	1,095.0		55.6
2009	1,298.2		66.1	1,497.0		108.8	1,092.2		57.1
2010	1,298.2		66.6	1,497.0		110.3	1,092.2		58.9
2011	1,302.6		67.5	1,450.7		108.6	1,114.1		62.0
Thereafter	27,582.8		1,457.0	26,252.6		2,105.9	7,070.2		378.5
Total	34,081.2	$	1,787.9	33,768.8	$	2,652.1	12,555.9	$	666.2

Fuel Purchase and Transportation Commitments

Allegheny has entered into various long-term commitments for the procurement and transportation of fuel expense (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 $842.7 million, $759.1 million and $634.1 million in 2006, 2005 and 2004, respectively. In 2006, Allegheny purchased approximately 44% of its coal from one vendor. Total estimated long-term fuel purchase and transportation commitments (primarily coal and lime) at December 31, 2006 were as follows, by entity and in total:

(In millions)	AE Supply		Monongahela		Total
2007	$	518.1	$	232.0	$	750.1
2008		540.2		127.6		667.8
2009		436.5		112.7		549.2
2010		400.0		84.5		484.5
2011		403.1		78.2		481.3
Thereafter		2,246.6		618.6		2,865.2
Total	$	4,544.5	$	1,253.6	$	5,798.1

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)	2007		2008		2009		2010		2011		Thereafter		Total
Other purchase obligations	$	27.1	$	26.6	$	26.0	$	24.9	$	23.1	$	22.4	$	150.1

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NOTE 26:  SUBSEQUENT EVENT—ASSET SWAP

Effective January 1, 2007, AE Supply and Monongahela completed an Asset Swap that realigned generation ownership and contractual arrangements within the Allegheny system. As a result of the Asset Swap, Monongahela owns 100% of the Fort Martin generation facility in West Virginia (“Fort Martin”), which will allow Allegheny to finance the construction of Scrubbers at Fort Martin through the securitization of an environmental control charge that Monongahela and Potomac Edison will impose on their retail customers in West Virginia.

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 will sell 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 is required to pay 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, must be redeemed as a result of the change in ownership of Fort Martin.

The Asset Swap was recorded on January 1, 2007 at the net book value of the assets, liabilities and interests transferred, with certain adjustments, and resulted in an increase in stockholder’s equity by Monongahela of approximately $54 million, a decrease in members’ equity by AE Supply of approximately $61 million and a decrease in Allegheny consolidated stockholders’ equity of approximately $1 million.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

of Allegheny Energy, Inc.

We have completed integrated audits of Allegheny Energy, Inc.'s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedules

In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Allegheny Energy, Inc. and its subsidiaries (the “Company”) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 10, the Company changed the manner in which it presents pension and other postretirement benefits as of December 31, 2006. As discussed in Note 17, the Company changed the manner in which it accounts for conditional asset retirement obligations as of December 31, 2005.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 27, 2007

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Consolidated Statements of Operations

	Year ended December 31,
(In thousands)	2006			2005			2004
Operating revenues	$	773,722		$	789,886		$	683,760
Operating expenses:
Fuel		178,031			153,113			123,484
Purchased power and transmission		200,369			270,518			187,510
Loss on sale of Ohio T&D assets		—			29,256			—
Deferred energy costs, net		(2,038	)		—			—
Operations and maintenance		172,127			196,051			210,077
Depreciation and amortization		65,614			66,295			65,759
Taxes other than income taxes		36,543			49,727			50,176
Total operating expenses		650,646			764,960			637,006
Operating income		123,076			24,926			46,754
Other income and expenses, net (Note 14)		15,456			12,928			9,085
Interest expense		40,868			43,430			43,219
Income (loss) from continuing operations before income taxes		97,664			(5,576	)		12,620
Income tax expense (benefit) from continuing operations		27,560			(14,756	)		(3,812	)
Income from continuing operations		70,104			9,180			16,432
Income (loss) from discontinued operations, net of tax (Note 4)		(974	)		1,028			(13,945	)
Net income	$	69,130		$	10,208		$	2,487

See accompanying Notes to Consolidated Financial Statements.

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Consolidated Statements of Cash Flows

	Year ended December 31,
(In thousands)	2006			2005			2004
Cash Flows From Operating Activities:
Net income	$	69,130		$	10,208		$	2,487
Loss (income) from discontinued operations, net of tax		974			(1,028	)		13,945
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		65,614			66,295			65,759
Amortization of power sale liability related to Ohio sale		(25,900	)		—			—
Loss (gain) on asset sales and disposals		(286	)		29,060			(110	)
Deferred income taxes and investment tax credit, net		19,306			(15,222	)		(4,309	)
Deferred energy costs, net		(2,038	)		—			—
Other, net		3,402			3,560			2,853
Changes in certain assets and liabilities:
Accounts receivable, net		16,633			(23,359	)		(4,933	)
Materials, supplies and fuel		(2,585	)		1,657			(4,412	)
Collateral deposits		14,015			(12,722	)		1,528
Prepaid taxes		13,461			14,984			11,846
Prepayments		(154	)		1,056			941
Other current assets		402			(38	)		498
Accounts payable		(15,077	)		9,940			(1,577	)
Accounts payable to affiliates, net		5,212			60,253			17,150
Accrued taxes		(15,179	)		(987	)		(6,204	)
Accrued interest		(1,236	)		135			(1,891	)
Other current liabilities		(3,017	)		(2,262	)		11,080
Other assets		(2,079	)		1,742			(295	)
Other liabilities		575			795			(5,293	)
Net cash provided by (used in) operating activities of discontinued operations		—			63,883			(49,429	)
Net cash provided by operating activities		141,173			207,950			49,634
Cash Flows From Investing Activities:
Capital expenditures		(90,653	)		(70,042	)		(54,221	)
Proceeds from sale of business and assets		424			52,079			162
Notes receivable from affiliates		(1,864	)		(21,268	)		(4,205	)
Other investments		—			—			8
Net cash provided by (used in) investing activities of discontinued operations		—			127,644			(12,949	)
Net cash provided by (used in) investing activities		(92,093	)		88,413			(71,205	)
Cash Flows From Financing Activities:
Net repayments of short-term debt		—			—			(53,610	)
Issuance of long-term debt		149,452			69,201			117,179
Retirement of long-term debt		(300,000	)		(72,067	)		(66,316	)
Deferred financing costs		(1,553	)		—			—
Redemption of preferred stock		—			(50,000	)		—
Return of capital to AE		—			(80,000	)		—
Cash dividends paid on capital stock:
Preferred stock		(1,172	)		(5,037	)		(5,037	)
Common stock		(10,015	)		—			(33,226	)
Net cash provided by (used in) financing activities of discontinued operations		—			(67,061	)		63,702
Net cash provided by (used in) financing activities		(163,288	)		(204,964	)		22,692
Net increase (decrease) in cash and cash equivalents		(114,208	)		91,399			1,121
Cash and cash equivalents at beginning of period		136,491			45,092			43,971
Cash and cash equivalents at end of period	$	22,283		$	136,491		$	45,092
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest (net of amount capitalized)	$	38,432		$	44,150		$	49,947
Income taxes, net	$	6,495		$	(9,767	)	$	(2,764	)

See accompanying Notes to Consolidated Financial Statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets

	As of December 31,
(In thousands)	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	22,283		$	136,491
Accounts receivable:
Customer		38,007			45,061
Unbilled utility revenue		33,952			38,200
Wholesale and other		12,341			20,598
Allowance for uncollectible accounts		(2,095	)		(2,489	)
Note receivable from affiliate		27,337			25,473
Materials and supplies		15,695			15,916
Fuel		17,557			14,751
Prepaid taxes		20,114			20,075
Collateral deposits		—			9,533
Regulatory assets		6,417			4,379
Other		8,638			3,827
Total current assets		200,246			331,815
Property, Plant and Equipment, Net:
Generation		967,486			951,636
Transmission		283,497			281,048
Distribution		968,377			930,817
Other		74,762			73,807
Accumulated depreciation		(936,098	)		(890,548	)
Subtotal		1,358,024			1,346,760
Construction work in progress		38,114			17,401
Total property, plant and equipment, net		1,396,138			1,364,161
Investments and Other Assets:
Investment in AGC		46,765			48,197
Other		2,437			6,904
Total investments and other assets		49,202			55,101
Deferred Charges:
Regulatory assets		88,940			101,117
Other		9,791			6,985
Total deferred charges		98,731			108,102
Total Assets	$	1,744,317		$	1,859,179

See accompanying Notes to Consolidated Financial Statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets—(Continued)

	As of December 31,
(In thousands, except share data)	2006		2005
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Long-term debt due within one year (Note 2)	$	15,500	$	299,959
Accounts payable		35,844		48,232
Accounts payable to affiliates, net		62,853		57,434
Accrued taxes		37,836		41,766
Accrued interest		7,693		8,929
Ohio power commitment		10,500		25,900
Other		19,558		24,378
Total current liabilities		189,784		506,598
Long-term Debt (Note 2)		519,145		385,067
Deferred Credits and Other Liabilities:
Investment tax credit		—		442
Non-current affiliated income taxes payable		45,671		45,671
Deferred income taxes		213,987		194,248
Obligations under capital leases		7,353		5,554
Regulatory liabilities		239,120		242,416
Other		32,598		41,219
Total deferred credits and other liabilities		538,729		529,550
Commitments and Contingencies (Note 16)
Preferred Stock		24,000		24,000
Common Stockholder’s Equity:
Common stock, $50 par value, 8 million shares authorized and 5,891,000 shares outstanding at December 31, 2006 and 2005		294,550		294,550
Other paid-in capital		41,468		40,719
Retained earnings		136,639		78,694
Accumulated other comprehensive income		2		1
Total common stockholder’s equity		472,659		413,964
Total Liabilities and Stockholder’s Equity	$	1,744,317	$	1,859,179

See accompanying Notes to Consolidated Financial Statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Statements of Capitalization

			As of December 31,
(Dollar amounts in thousands)			2006			2005
Common Stockholder’s Equity			$	472,659		$	413,964
Preferred Stock of Subsidiary, $100 par value:
	As of December 31, 2006
Series	Regular Call Price Per Share	Interest Rate %
240,000 shares outstanding at December 31, 2006 and 2005	$102.86 to $106.50	4.40-6.28	$	24,000		$	24,000
	As of December 31, 2006
	Maturities	Interest Rate %
Long-term Debt:
Medium-term notes	2010	7.360	$	110,000		$	110,000
First mortgage bonds	2014-2017	5.375-6.700		340,000			490,000
Pollution control bonds	2007-2029	4.700-6.875		85,750			85,750
Unamortized debt discounts	—	—		(1,105	)		(724	)
Total long-term debt (including current portion of $15,500 and $299,959 at December 31, 2006 and 2005, respectively)				534,645			685,026
Total Capitalization			$	1,031,304		$	1,122,990

See accompanying Notes to Consolidated Financial Statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Consolidated Statements of Stockholder’s Equity

(In thousands, except shares)	Shares Outstanding	Common stock		Other paid-in capital			Retained earnings			Accumulated other comprehensive income (loss)			Total common stockholder’s equity
Balance at December 31, 2003	5,891,000	$	294,550	$	110,492		$	108,333		$	84		$	513,459
Net income	—		—		—			2,487			—			2,487
Pollution control bond interest paid by AE Supply	—		—		690			—			—			690
Dividends declared on preferred stock	—		—		—			(5,037	)		—			(5,037	)
Dividends declared on common stock	—		—		—			(33,226	)		—			(33,226	)
Other comprehensive income	—		—		—			—			(1	)		(1	)
Balance at December 31, 2004	5,891,000		294,550		111,182			72,557			83			478,372
Net income	—		—		—			10,208			—			10,208
Pollution control bond interest paid by AE Supply	—		—		749			—			—			749
Dividends declared on preferred stock	—		—		—			(4,071	)		—			(4,071	)
Return of capital to AE	—		—		(80,000	)		—			—			(80,000	)
Sale of sulfur dioxide allowance to affiliate	—		—		8,788			—			—			8,788
Other comprehensive income	—		—		—			—			(82	)		(82	)
Balance at December 31, 2005	5,891,000		294,550		40,719			78,694			1			413,964
Net income	—		—		—			69,130			—			69,130
Pollution control bond interest paid by AE Supply	—		—		749			—			—			749
Dividends declared on preferred stock	—		—		—			(1,171	)		—			(1,171	)
Dividends declared on common stock	—		—		—			(10,014	)		—			(10,014	)
Other comprehensive income	—		—		—			—			1			1
Balance at December 31, 2006	5,891,000	$	294,550	$	41,468		$	136,639		$	2		$	472,659

See accompanying Notes to Consolidated Financial Statements.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note No.		Page No.
1	Basis of Presentation	197
2	Capitalization	204
3	Jointly Owned Electric Utility Plants	206
4	Discontinued Operations	207
5	Asset Sales	207
6	Business Segments	208
7	Pension Benefits and Postretirement Benefits Other Than Pensions	209
8	Income Taxes	210
9	Intangible Assets	212
10	Asset Retirement Obligations (“ARO”)	213
11	Rates and Regulation	213
12	Regulatory Assets and Liabilities	213
13	Fair Value of Financial Instruments	214
14	Other Income and Expenses, Net	214
15	Quarterly Financial Information (Unaudited)	215
16	Commitments and Contingencies	215
17	Subsequent Event—Asset Swap	221

196

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1:  BASIS OF PRESENTATION

Monongahela Power Company, together with its consolidated subsidiaries (“Monongahela”), is a wholly owned subsidiary of Allegheny Energy, Inc. (“AE,” and together with its consolidated subsidiaries, “Allegheny”). Monongahela, along with its regulated utility affiliates, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”), collectively doing business as Allegheny Power, operates electric transmission and distribution (“T&D”) systems. Monongahela operates an electric T&D system in West Virginia. Monongahela also generates power for its West Virginia customers. Monongahela has two principal business segments. The Generation and Marketing segment includes Monongahela’s power generation operations. The Delivery and Services segment includes Monongahela’s electric T&D operations.

Monongahela conducted electric T&D operations in Ohio until December 31, 2005 and a natural gas T&D business in West Virginia until September 30, 2005.

Monongahela has an investment in AGC. Monongahela accounts for its investment in AGC using the equity method of accounting. As of December 31, 2006, Monongahela owned approximately 23% of AGC. As a result of a January 1, 2007 transfer of assets between AE Supply and Monongahela that realigned generation ownership and contractual arrangements within the Allegheny Energy system (the “Asset Swap”), Monongahela’s ownership interest in AGC increased to approximately 41%.

Monongahela is subject to regulation by the Securities and Exchange Commission (“SEC”), the Public Service Commission of West Virginia (the “West Virginia PSC”) and the Federal Energy Regulatory Commission (“FERC”).

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny. As of December 31, 2006, AESC employed approximately 4,362 employees, of which approximately 1,250 are subject to collective bargaining arrangements.

During the fourth quarter of 2006, Monongahela changed its classification of fuel handling and residual disposal costs within its Consolidated Statements of Operations from “Operations and maintenance” expenses to “Fuel” expenses, to improve comparability with other energy and utility companies and facilitate a better understanding of operating costs. Accordingly, Monongahela reclassified such costs previously reported in the amounts of $3.8 million, $4.7 million and $4.4 million for the nine months ended September 30, 2006 and the years ended December 31, 2005 and 2004, respectively, to conform to the financial statement presentation for the current period. Fuel handling and disposal costs for the full year 2006 were $5.2 million.

In addition, certain other amounts in previously issued financial statements have been reclassified to conform to the current presentation.

Significant accounting policies of Monongahela and its subsidiaries are summarized below.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires Monongahela to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a continuous basis, Monongahela evaluates its estimates, including those related to the calculation of unbilled revenues, provisions for depreciation and amortization, regulatory assets and liabilities, income taxes and contingencies related to environmental matters and litigation. Monongahela bases its estimates on historical

197

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Consolidation

The Consolidated Financial Statements reflect investments in controlled subsidiaries on a consolidated basis. The Consolidated Financial Statements include the accounts of Monongahela and all subsidiary companies after elimination of intercompany transactions and balances. The Consolidated Financial Statements are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of FERC and applicable state regulatory commissions.

Regulatory Assets and Liabilities

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

Monongahela accounts for its operations under the provisions of SFAS No. 71. The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs or revenues would be recognized by an unregulated enterprise. Accordingly, Monongahela records assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” Monongahela periodically evaluates the applicability of SFAS No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition significantly increases, Monongahela may have to adjust its regulatory assets and liabilities to reflect a market basis less than cost.

See Note 12, “Regulatory Assets and Liabilities,” for additional information.

Revenues

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

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

Deferred Energy Costs, Net

Historically, the difference between the costs of fuel, purchased energy and certain other costs billed to regulated electric utility customers has been deferred until it is either recovered from or credited to customers under state fuel and energy cost-recovery procedures. With the exception of the one power purchase agreement under the Public Utility Regulatory Policies Act of 1978 (“PURPA”) that remains subject to a deferred energy cost mechanism described below, fuel and purchased energy costs for the regulated electric utilities have been expensed as incurred, because the applicable state regulatory bodies eliminated their deferred energy cost mechanisms. However, Monongahela has filed a request with the West Virginia PSC to reinstate deferred fuel accounting. The outcome of this request is pending.

198

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 provides for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia PSC authorized Monongahela and Potomac Edison 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 will be tracked and reconciled by comparison to the aggregate amounts recovered from West Virginia customers through the temporary surcharge.

Debt Issuance Costs

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

Long-Lived Assets

Monongahela’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows. See Note 4, “Discontinued Operations” for information related to asset impairment charges recorded during 2005 and 2004.

Property, Plant and Equipment

Utility and electric generation property, plant and equipment are stated at original cost. Cost includes direct labor and materials, allowance for funds used during construction and indirect costs, such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes and other benefits related to employees engaged in construction. Upon normal retirement, the costs of depreciable property, less salvage, are charged to accumulated depreciation with no gain or loss recorded.

Allowance for Funds Used During Construction (“AFUDC”)

AFUDC, an item of income, reflected as “Other income and expense, net” and a reduction of interest expense that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” Rates used for computing AFUDC in 2006, 2005 and 2004 averaged 7.87%, 7.50% and 6.93%, respectively. Monongahela recorded AFUDC of $2.2 million, $1.2 million and $0.7 million in 2006, 2005 and 2004, respectively.

199

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Depreciation and Maintenance

Depreciation expense is determined in accordance with currently enacted regulatory rates. Depreciation expense was approximately 3.0% of average depreciable property in 2006, 2005 and 2004. Estimated service lives for generation, T&D and other property at December 21, 2006 are as follows:

Type of Property	Years
Generation property:
Steam scrubbers and equipment	20-40
Steam generator units	40-75
Transmission and distribution property:
Electric equipment	15-60
Other property:
Office buildings and improvements	46
General office/other equipment	20
Vehicles and transportation	7-25
Computers, software and information systems	5-10

The Delivery and Services segment’s depreciation expense was $30.6 million, $30.4 million and $30.3 million in 2006, 2005 and 2004, respectively. The Generation and Marketing segment’s depreciation expense was $35.0 million, $34.8 million and $34.4 million in 2006, 2005 and 2004, respectively. Depreciation expense is provided for under currently enacted regulatory rates.

Maintenance expenses represent costs incurred to maintain the generation facilities, the electric T&D systems and general plant. These expenses reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the generation facilities and periodic storm damage to the T&D system. Maintenance costs are expensed as incurred.

Investments

Investments are generally accounted for under the equity method of accounting. The income or loss on such investments is recorded in “Other income and expenses, net” in the Consolidated Statements of Operations.

As discussed above, Monongahela has an equity investment in AGC. AGC owns an undivided 40% interest (1,035 megawatts (“MWs”)) in the 2,525 MWs pumped-storage hydroelectric station in Bath County, Virginia. This station is operated by the 60% owner, Virginia Electric and Power Company, a nonaffiliated utility. See Note 3, “Jointly Owned Electric Utility Plants” and Note 17, “Subsequent Event—Asset Swap,” for additional information.

Following is a summary of financial information for AGC in its entirety:

	Year Ended December 31,
(In millions)	2006		2005		2004
Statement of Operations information:
Operating revenues	$	65.3	$	66.6	$	69.2
Operating expenses	$	25.6	$	24.8	$	26.1
Operating income	$	39.7	$	41.9	$	43.1
Net income	$	24.8	$	31.1	$	27.4

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	December 31,
(In millions)	2006		2005
Balance sheet information:
Assets:
Current assets	$	5.7	$	6.6
Property, plant and equipment, net		524.4		535.2
Deferred charges		7.9		8.4
Total assets	$	538.0	$	550.2
Liabilities and stockholders’ equity:
Current liabilities	$	10.7	$	9.7
Long-term debt		99.4		99.4
Deferred credits and other liabilities		224.3		231.3
Stockholders’ equity		203.6		209.8
Total liabilities and stockholders’ equity	$	538.0	$	550.2

Cash Equivalents

For purposes of the Consolidated Statements of Cash Flows and Balance Sheets, temporary cash investments, generally in the form of commercial paper, certificates of deposit, repurchase agreements and money market funds, are considered to be the equivalent of cash.

Transfer of Assets

On June 1, 2001, Monongahela transferred, at book value, approximately 352 MWs of Ohio and FERC jurisdictional generation assets to AE Supply. The Public Utilities Commission of Ohio approved the transfer as part of Ohio’s deregulation efforts. In conjunction with the transfer of these assets, AE Supply assumed Monongahela’s obligations with respect to certain pollution control bonds. As of December 31, 2006 and 2005, Monongahela and AE Supply were co-obligors with respect to $12.8 million principle amount of these pollution control bonds. These pollution control bonds are included as debt in Monongahela’s Consolidated Balance Sheets. Although AE Supply assumed responsibility for the payment of the pollution control bonds, Monongahela accrues interest expense associated with the bonds. As AE Supply remits payment, Monongahela reduces accrued interest and increases paid-in capital.

AE Supply and Monongahela own certain generation assets jointly as tenants in common. AE Supply operates these jointly-owned assets. Each owner is entitled to the available energy output and capacity in proportion to its ownership of the asset. Monongahela does the billing for the jointly-owned stations located in West Virginia, while AE Supply is responsible for the billing for the Hatfield’s Ferry generation facility, in Pennsylvania.

As a result of the Asset Swap, effective January 1, 2007, AE Supply’s and Monongahela’s joint ownership in certain generation assets and pollution control bond obligations have changed. See Note 3, “Jointly Owned Electric Utility Plants” and Note 17, “Subsequent Event—Asset Swap,” for additional information.

Intercompany Transactions

Monongahela has various operating transactions with affiliates. It is Monongahela’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented on a net basis on the Consolidated Balance Sheets and the Consolidated Statements of Cash Flows.

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Substantially all of the employees who work for Monongahela are employed by AESC, which performs services at cost for Monongahela and its affiliates. Monongahela is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to Monongahela in 2006, 2005 and 2004 were $157.7 million, $169.2 million and $209.7 million, respectively.

During 2004, Monongahela’s Delivery and Services segment purchased the majority of the power necessary to serve its Ohio customers who did not choose an alternate electricity generation provider directly from its unregulated generation company affiliate, AE Supply, in accordance with agreements approved by FERC. Monongahela’s expense for these purchases is reflected in “Purchased power and transmission” on its Consolidated Statements of Operations. Beginning in 2005, Monongahela purchased power to serve its commercial and industrial customers in Ohio directly from the PJM market. Monongahela continued purchasing power to serve its residential Ohio customers from AE Supply. Accordingly, purchased power for Monongahela’s commercial and industrial customers in Ohio was recorded in other purchased power and transmission in 2005. In December, 2005, Monongahela sold its Ohio service territory. In 2005 and 2004, Monongahela purchased power from AE Supply in the amount of $11.7 million and $48.3 million, respectively, to serve its Ohio customers. For 2005 and 2004, Monongahela also incurred $0.5 million and $0.7 million, respectively, for ancillary transmission expenses with AE Supply.

Through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela’s Generation and Marketing segment completed energy and capacity transactions with AE Supply at PJM market prices. Prior to January 2005, a power sales agreement with AE Supply covering these transactions contained a pricing mechanism that included financial transmission rights (“FTRs”) and congestion values. In January 2005, AE Supply and Monongahela signed a Revised Affiliated Power Sales Agreement. Under the Revised Affiliated Power Sales Agreement, AE Supply recorded these transactions with Monongahela as affiliated revenue or affiliated purchased power and transmission expense depending on hourly energy requirements. Congestion values under the Revised Affiliated Power Sales Agreement are recorded as affiliated revenues and affiliated purchased power and transmission expense. Monongahela also sells electricity and capacity to AE Supply under a market rate as affiliated revenue. In 2006, 2005 and 2004 Monongahela purchased power from AE Supply in the amount of $54.8 million, $94.0 million and $26.3 million, respectively. In 2006, 2005 and 2004, Monongahela purchased (sold) power to AE Supply in the amount of $(7.8) million, $(15.4) million and $19.6 million, respectively.

As discussed above, through December 31, 2006, to facilitate the economic dispatch of its generation, Monongahela sold the power that it generates 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. As part of the Asset Swap, effective January 1, 2007 and 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 its contractual obligations. 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, effective January 1, 2007, Potomac Edison purchases the power necessary to service its West Virginia customers from Monongahela at overall Monongahela generation costs. See Note 17, “Subsequent Event—Asset Swap,” for additional information.

Monongahela purchases power from AGC related to AGC’s capacity in the Bath County, Virginia pumped-storage hydroelectric station, in proportion to Monongahela’s equity ownership in AGC. In 2006, 2005 and 2004, these purchases from AGC amounted to $15.0 million, $15.3 million and $15.9 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In December 2005, Monongahela sold 9,500 vintage 2005 sulfur dioxide (“SO₂”) allowances to its affiliate, AE Supply, for $14.8 million. These allowances were transferred at their carrying value, and the difference between the cash received and the carrying value was recorded as an adjustment to Monongahela’s paid-in capital, net of tax.

In accordance with a consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various affiliated companies at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the intercompany balance. Income taxes payable to affiliates, including both short and long-term obligations, at December 31, 2006 and 2005, were $53.5 million and $51.3 million, respectively.

Monongahela manages both excess cash and short-term obligations through Allegheny’s internal money pool. The money pool provides funds at the lower of the Federal Reserve’s previous day’s federal funds effective interest rate, or the Federal Reserve’s previous day’s seven day commercial paper rate, less four basis points. Monongahela can place money into, or borrow money from, the money pool. At December 31, 2006 and 2005, Monongahela had $27.3 million and $25.5 million, respectively, invested in the money pool.

At December 31, 2006 and 2005, Monongahela had net accounts payable to affiliates of $62.9 million and $57.4 million, respectively.

Inventory

Monongahela values materials, supplies and fuel inventory using an average cost method.

Income Taxes

AE and its subsidiaries, including Monongahela, file a consolidated federal income tax return. The consolidated income tax liability is allocated between AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability.

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 8, “Income Taxes,” for additional information.

Taxes Collected from Customers and Remitted to Governmental Authorities

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Pension and Other Postretirement Benefits

AE has noncontributory, defined benefit pension plans 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.

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, are based upon an age and years-of-service vesting schedule, other plan provisions and 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.

Through AESC, Monongahela is responsible for its proportionate share of pension and postretirement benefit costs.

See Note 7, “Pension Benefits and Postretirement Benefits Other than Pensions,” for additional information.

Comprehensive Income

Comprehensive income was $69,131,000, $10,126,000 and $2,486,000 for the years ended December 31, 2006, 2005 and 2004, respectively, including other comprehensive income (loss) of $1,000, $(82,000) and $(1,000) for the years ended December 31, 2006, 2005 and 2004, respectively. Other comprehensive income consists of unrealized gains and losses, net of income taxes, from the temporary change in the fair value of available-for-sale securities.

Recent Accounting Pronouncement

The following accounting pronouncement was adopted by Monongahela during 2006:

In September 2006, the SEC issued Staff Accounting Bulletin 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 is effective for Monongahela for its December 31, 2006 annual financial statements and its adoption did not impact Monongahela’s financial statements.

NOTE 2:  CAPITALIZATION

Monongahela’s consolidated capital structure, including short-term debt and debt associated with assets held for sale, as of December 31, 2006 and 2005, was as follows:

	2006			2005
(In millions, except percent)	Amount		%	Amount		%
Debt	$	534.6	51.9	$	685.0	61.0
Common equity		472.7	45.8		414.0	36.9
Preferred equity		24.0	2.3		24.0	2.1
Total	$	1,031.3	100.0	$	1,123.0	100.0

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Preferred Stock

Each share of Monongahela’s preferred stock is entitled, upon voluntary liquidation, to its then current call price and, on involuntary liquidation, to $100 a share.

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

Return of Capital

During October 2005, Monongahela returned $80.0 million of capital to AE using a portion of the cash proceeds from the sale of Monongahela’s West Virginia natural gas operations.

Long-term Debt

At December 31, 2006, contractual maturities for long-term debt, excluding unamortized discounts of $1.1 million, are as follows. The table excludes changes resulting from the January 1, 2007 Asset Swap, which are discussed at Note 17, “Subsequent Event—Asset Swap.”

(In millions)	2007		2008		2009		2010		2011		Thereafter		Total
First Mortgage Bonds	$	—	$	—	$	—	$	—	$	—	$	340.0	$	340.0
Medium-Term Notes		—		—		—		110.0		—		—		110.0
Pollution Control Bonds		15.5		—		—		—		—		70.2		85.7
Total	$	15.5	$	—	$	—	$	110.0	$	—	$	410.2	$	535.7

At December 31, 2006, substantially all of Monongahela’s properties were held subject to liens of various relative priorities securing debt obligations.

2006 Debt Activity

In September 2006, Monongahela issued $150 million aggregate principal amount of 5.70% First Mortgage Bonds, which mature in 2017. In October 2006, 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.

See Note 17, “Subsequent Event—Asset Swap,” for debt changes resulting from the January 1, 2007 Asset Swap.

Issuances and repayments of indebtedness during 2006 were as follows:

(In millions)	Issuances		Repayments
First Mortgage Bonds	$	150.0	$	300.0

2005 Debt Activity

In connection with Monongahela’s sale of its West Virginia natural gas operations, $86.7 million of debt previously classified as liabilities associated with assets held for sale was transferred to the buyer.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On October 17, 2005, Monongahela issued $70.0 million of 5.375% First Mortgage Bonds due 2015. Monongahela used the proceeds and available cash to redeem $70.0 million of its 7 ⁵/8% First Mortgage Bonds due May 2025 on November 19, 2005.

The following issuances and repayments of debt were made during 2005:

(In millions)	Issuances		Repayments
First Mortgage Bonds	$	70.0	$	70.0
Debt associated with assets held for sale:
Other Notes (a)	$	—	$	86.7

(a) Represents debt related to Monongahela’s natural gas operations in West Virginia. In connection with the sale of these operations on September 30, 2005, the purchaser assumed this debt.

NOTE 3:  JOINTLY OWNED ELECTRIC UTILITY PLANTS

Through December 31, 2006, Monongahela had shared ownership of seven generation facilities with AE Supply, and recorded its proportionate share of operating costs, assets and liabilities in the corresponding line items in its Consolidated Financial Statements. The following table shows Monongahela’s utility plant investment and accumulated depreciation in these generating facilities as of December 31, 2006 and 2005 and Monongahela’s January 1, 2007 ownership percentages as a result of the Asset Swap.

	January 1, 2007						December 31, 2006						December 31, 2005
Generation facility (Dollars in millions)	Ownership %		Plant Investment		Accumulated Depreciation		Ownership %		Plant Investment		Accumulated Depreciation		Ownership %		Plant Investment		Accumulated Depreciation
Albright	100.0	%	$	119.2	$	89.9	57.5	%	$	68.7	$	46.5	57.6	%	$	68.9	$	49.1
Fort Martin	100.0	%	$	460.7	$	268.3	19.1	%	$	71.0	$	49.1	19.1	%	$	70.6	$	61.0
Harrison	20.5	%	$	286.8	$	162.4	21.3	%	$	297.0	$	168.1	21.3	%	$	294.8	$	174.7
Hatfield’s Ferry	—	%	$	—	$	—	23.4	%	$	154.5	$	60.3	23.4	%	$	143.9	$	77.3
Pleasants	7.7	%	$	90.2	$	50.6	21.3	%	$	249.4	$	140.0	21.3	%	$	247.1	$	148.9
Rivesville	100.0	%	$	57.5	$	43.6	85.1	%	$	48.9	$	36.9	85.1	%	$	48.9	$	39.0
Willow Island	100.0	%	$	106.5	$	70.9	85.1	%	$	90.6	$	59.6	85.1	%	$	89.7	$	63.0

Through its equity interest in AGC, Monongahela owns an interest in AGC’s jointly owned electric utility plant. As of December 31, 2006, Monongahela had an approximately 23% equity interest in AGC. Effective January 1, 2007, Monongahela’s ownership interest in AGC changed to approximately 41% as a result of the Asset Swap. The following table shows AGC’s utility plant investment and accumulated depreciation in the Bath County generation facility as of December 31, 2006 and 2005.

	December 31, 2006						December 31, 2005
Generation facility (Dollars in millions)	Ownership %		Plant Investment		Accumulated Depreciation		Ownership %		Plant Investment		Accumulated Depreciation
Bath County	40	%	$	835.6	$	318.1	40	%	$	839.0	$	316.3

See Note 17, “Subsequent Event—Asset Swap,” for additional information.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 4:  DISCONTINUED OPERATIONS

During 2004, Monongahela commenced efforts to sell its natural gas operations, and recorded impairment charges to adjust the carrying value of the assets to estimated net sales proceeds. The results of operations have been classified as discontinued operations in the accompanying Consolidated Statements of Operations, and, through the dates on which these sales concluded, their assets and liabilities have been classified as held for sale in the Consolidated Balance Sheets.

The components of income (loss) from discontinued operations are as follows:

(In millions)	2006			2005			2004
Operating revenues	$	—		$	218.1		$	306.4
Operating expenses		(1.7	)		(201.6	)		(285.2	)
Other income		—			1.0			0.2
Interest expense		—			(6.1	)		(8.3	)
Income (loss) before income taxes		(1.7	)		11.4			13.1
Income tax benefit (expense)		0.7			(3.4	)		(5.3	)
Impairment charge, net of tax		—			(7.0	)		(21.7	)
Income (loss) from discontinued operations, net of tax	$	(1.0	)	$	1.0		$	(13.9	)

NOTE 5:  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 will provide 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 6:  BUSINESS SEGMENTS

Monongahela accounts for intersegment sales based on cost or regulatory commission approved tariffs or contracts. Business segment information is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts. The majority of the eliminations relate to power sold by the Generation and Marketing segment to the Delivery and Services segment. Business segment information is summarized below.

(In millions)	Delivery and Services			Generation and Marketing			Other		Eliminations			Total
2006
External operating revenues	$	674.9		$	98.8		$	—	$	—		$	773.7
Internal operating revenues		—			302.3			—		(302.3	)		—
Total operating revenues		674.9			401.1			—		(302.3	)		773.7
Depreciation and amortization		30.6			35.0			—		—			65.6
Operating income		120.5			2.6			—		—			123.1
Interest expense		23.5			17.4			—		—			40.9
Income tax expense from continuing operations		25.4			2.2			—		—			27.6
Income (loss) from continuing operations		77.8			(7.7	)		—		—			70.1
Loss from discontinued operations, net of tax		(1.0	)		—			—		—			(1.0	)
Net income (loss)		76.8			(7.7	)		—		—			69.1
Capital expenditures		52.7			37.9			—		—			90.6
Identifiable assets		1,116.2			549.8			78.3		—			1,744.3
2005
External operating revenues	$	691.4		$	98.5		$	—	$	—		$	789.9
Internal operating revenues		—			317.0			—		(317.0	)		—
Total operating revenues		691.4			415.5			—		(317.0	)		789.9
Depreciation and amortization		31.5			34.8			—		—			66.3
Operating income (loss)		28.0			(3.1	)		—		—			24.9
Interest expense		25.1			18.3			—		—			43.4
Income tax benefit from continuing operations		(1.3	)		(13.5	)		—		—			(14.8	)
Income from continuing operations		8.4			0.8			—		—			9.2
Income from discontinued operations, net of tax		1.0			—			—		—			1.0
Net income		9.4			0.8			—		—			10.2
Capital expenditures		47.3			24.4			—		—			71.7
Identifiable assets		1,089.3			575.7			194.2		—			1,859.2
2004
External operating revenues	$	669.0		$	14.8		$	—	$	—		$	683.8
Internal operating revenues		—			298.0			—		(298.0	)		—
Total operating revenues		669.0			312.8			—		(298.0	)		683.8
Depreciation and amortization		31.4			34.4			—		—			65.8
Operating income (loss)		64.2			(17.4	)		—		—			46.8
Interest expense		24.8			18.5			—		—			43.3
Income tax expense (benefit) from continuing operations		11.4			(15.2	)		—		—			(3.8	)
Income (loss) from continuing operations		30.4			(14.0	)		—		—			16.4
Loss from discontinued operations, net of tax		(13.9	)		—			—		—			(13.9	)
Net income (loss)		16.5			(14.0	)		—		—			2.5
Capital expenditures		40.1			13.6			—		—			53.7

208

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 7:  PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Monongahela is responsible for its proportionate share of the net periodic cost for pension benefits and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by Allegheny, through AESC. Monongahela’s share of the costs was as follows:

(In millions)	2006		2005		2004
Pension plans	$	7.7	$	10.0	$	11.6
Postretirement benefit plans other than pension plans	$	6.8	$	9.0	$	9.3

For the years ended December 31, 2006, 2005 and 2004, Monongahela allocated $3.6 million, $4.0 million and $3.9 million, respectively, of the above net periodic cost amounts to “Construction work in progress,” a component of “Property, plant and equipment, net.”

The assumptions used to determine net periodic benefit costs for years ended December 31, 2006, 2005 and 2004 are shown in the table below.

	Pension Benefits						Postretirement Benefits Other Than Pensions
	2006		2005		2004		2006		2005		2004
Discount rate	5.60	%	5.90	%	6.00	%	5.60	%	5.90	%	6.00	%
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	3.25	%	3.25	%	3.75	%	3.25	%	3.25	%	3.75	%

(a) Excluding administrative expenses.

The assumptions used to determine benefit obligations at December 31, 2006 and 2005 are shown in the table below:

	Pension Benefits				Postretirement Benefits Other Than Pensions
	2006		2005		2006		2005
Discount rate	6.00	%	5.60	%	6.00	%	5.60	%
Rate of compensation increase	3.60	%(a)	3.25	%	3.60	%(a)	3.25	%

(a) Weighted-average rate for age graded scale.

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

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs in 2007 is 8.25%, which is net of administrative expenses.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Assumed health care cost trend rates at December 31 are as follows:

	2006		2005
Health care cost trend rate assumed for next year	9.0	%	9.5	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2015		2015

For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.0% beginning with 2007 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 effect on the amounts displayed in the table above.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) became law. 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, in 2006, Allegheny is receiving the federal subsidy offered under the Medicare Act.

NOTE 8:  INCOME TAXES

Details of federal and state income tax expense (benefit) from continuing operations are as follows:

(In millions)	2006			2005			2004
Income tax expense (benefit)—current:
Federal	$	3.4		$	3.6		$	(0.4	)
State		4.9			(3.2	)		0.8
Total		8.3			0.4			0.4
Income tax—expense (benefit) deferred, net		19.7			(13.1	)		(2.1	)
Amortization of deferred investment tax credit		(0.4	)		(2.1	)		(2.1	)
Total income tax expense (benefit) from continuing operations	$	27.6		$	(14.8	)	$	(3.8	)

During the second quarter of 2005, Allegheny determined that it had not claimed certain income tax deductions in its 2003 income tax returns relating to commodity trading contracts. Allegheny filed a claim for these additional deductions, which increased Monongahela’s allocated share of consolidated tax savings. Accordingly, Monongahela recorded a tax benefit of $4.3 million during the second quarter of 2005 to recognize the additional tax savings. The effect of this adjustment was not material to Monongahela’s results of operations for the year ended December 31, 2005.

Monongahela has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Total income tax expense (benefit) from continuing operations differs from the amount produced by applying the federal statutory income tax rate of 35% to income (loss) from continuing operations before income taxes and minority interest, due to the following reconciling items:

	2006					2005					2004
(In millions, except percent)	Amount			%		Amount			%		Amount			%
Income (loss) from continuing operations, before income taxes	$	97.7				$	(5.6	)			$	12.6
Income tax expense (benefit) calculated using the federal statutory rate of 35%		34.2		35.0			(1.9	)	35.0			4.4		35.0
Increases (reductions) resulting from:
Tax deductions for which deferred tax was not provided:
Depreciation		3.1		3.2			1.5		(26.8	)		0.7		5.5
Plant removal costs		(0.9	)	(0.9	)		(0.8	)	14.3			(0.9	)	(7.1	)
State income tax, net of federal income tax benefit		(1.9	)	(1.9	)		(7.1	)	126.8			(3.3	)	(26.2	)
Amortization of deferred investment tax credit		(0.4	)	(0.4	)		(2.1	)	37.5			(2.1	)	(16.7	)
Consolidated return benefit		(9.7	)	(9.9	)		(2.6	)	46.4			(0.2	)	(1.6	)
Equity in earnings of subsidiaries		(2.7	)	(2.8	)		(2.5	)	44.6			(2.2	)	(17.5	)
Accrual versus return adjustment		1.4		1.4			—		—			(0.9	)	(7.1	)
Emissions Allowance		4.8		4.9			—		—			—		—
Other, net		(0.3	)	(0.3	)		0.7		(13.5	)		0.7		5.5
Total income tax expense (benefit)	$	27.6		28.3		$	(14.8	)	264.3		$	(3.8	)	(30.2	)

The total provision for income tax expense (benefit) from discontinued operations differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount, as set forth below:

(In millions)	2006			2005			2004
Loss from discontinued operations, before income taxes	$	(1.6	)	$	(0.4	)	$	(23.6	)
Income tax benefit calculated using the federal statutory rate of 35%	$	(0.6	)	$	(0.1	)	$	(8.3	)
Adjusted for state income tax, net of federal income tax benefit		(0.1	)		(1.3	)		(1.3	)
Total income tax benefit	$	(0.7	)	$	(1.4	)	$	(9.6	)

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At December 31, the deferred tax assets and liabilities consisted of the following:

(In millions)	2006		2005
Deferred tax assets:
Unamortized investment tax credit	$	—	$	0.3
Tax effect of net operating loss carryforwards		32.3		66.2
Other		25.3		20.0
Total deferred tax assets		57.6		86.5
Deferred tax liabilities:
Plant asset basis differences, net		250.0		262.1
Other		16.3		18.4
Total deferred tax liabilities		266.3		280.5
Total net deferred tax liabilities		208.7		194.0
Portion above included in current assets		5.3		0.2
Total long-term net deferred tax liabilities	$	214.0	$	194.2

Monongahela recorded as deferred tax assets the effect of net operating losses, which will more likely than not be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2025. In addition, Monongahela is a party to a consolidated tax sharing agreement, which was amended effective July 1, 2003. Monongahela can realize the benefits of its net operating loss carryforwards generated prior to this date only to the extent of its future taxable income. Monongahela expects to realize benefits represented by deferred tax assets through its participation in the consolidated tax return in future years.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109 (“FIN 48”), which is effective for fiscal periods beginning after December 15, 2006. FIN 48 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 positions should initially be recognized in the financial statements when it is more likely than not the position will be sustained upon examination by the tax authorities. Such tax positions should be initially and subsequently 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. The Company will be required to apply the provisions of FIN 48 to all tax positions upon initial adoption with any cumulative effect adjustment to be recognized as an adjustment to retained earnings. Upon adoption on January 1, 2007, management estimates that a cumulative effect adjustment of approximately $1 million will be credited to retained earnings to decrease reserves for uncertain tax positions.

NOTE 9:  INTANGIBLE ASSETS

Intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:

	December 31, 2006				December 31, 2005
(In millions)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Land easements, amortized	$	0.5	$	0.2	$	0.5	$	0.2
Land easements, unamortized		30.7		—		30.6		—
Software		0.4		0.1		0.3		0.3
Total	$	31.6	$	0.3	$	31.4	$	0.5

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Amortization expense for other intangible assets in 2006, 2005 and 2004 was $0.1 million, $1.0 million and $2.3 million, respectively.

Amortization expense of intangible assets at December 31, 2006 is estimated to approximate $0.1 million annually for 2007 through 2011.

NOTE 10:  ASSET RETIREMENT OBLIGATIONS (“ARO”)

Monongahela has AROs primarily related to ash landfills and underground and aboveground storage tanks and Conditional AROs related to asbestos contained in its generating facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”).

In 2006, Monongahela’s total ARO balance, which includes AROs and Conditional AROs, increased $0.8 million, from $12.9 million at December 31, 2005 to $13.7 million at December 31, 2006. This increase was primarily due to accretion.

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 11:  RATES AND REGULATION

Monongahela’s interstate transmission services are regulated by FERC under the Federal Power Act. Monongahela’s local distribution service and sales at the retail level are subject to state regulation. West Virginia has not instituted retail customer choice.

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 July 2006, Monongahela and Potomac Edison filed a request with the West Virginia PSC to increase rates related to fuel and purchased power costs, including reinstatement of a fuel cost recovery clause and a decrease in base rates. The proceeding is scheduled to be finalized in May 2007 with the resulting rate being effective immediately.

NOTE 12:  REGULATORY ASSETS AND LIABILITIES

Monongahela’s electric generation and T&D operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:

(In millions)	2006		2005
Regulatory assets, including current portion:
Income taxes	$	72.0	$	77.4
Unamortized loss on reacquired debt		14.2		16.2
Other		9.1		11.9
Subtotal		95.3		105.5
Regulatory liabilities:
Non-legal asset removal costs		239.1		242.1
Other		—		0.3
Subtotal		239.1		242.4
Net regulatory liabilities	$	143.8	$	136.9

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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.

Income Taxes, Net

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

See Note 10, “Asset Retirement Obligations,” for additional information on non-legal ARO costs.

NOTE 13:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year, and preferred stock of subsidiary, at December 31, 2006 and 2005 were as follows:

	2006				2005
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	534.6	$	547.4	$	685.0	$	703.4
Preferred stock (all series)	$	24.0	$	21.3	$	24.0	$	17.8

The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The fair value of preferred stock is based on quoted market prices. The carrying amounts of cash equivalents and short-term debt approximate the fair values of these financial instruments because of the short maturities of these instruments.

NOTE 14:  OTHER INCOME AND EXPENSES, NET

Other income and expenses, net represents non-operating income and expenses before income taxes. The following table summarizes Monongahela’s other income and expenses, net:

(In millions)	2006		2005		2004
Equity in earnings of AGC	$	5.7	$	7.1	$	6.3
Interest income		7.6		4.4		0.8
Premium services		0.8		0.4		0.9
Storm restoration, net		—		—		0.5
Other		1.4		1.0		0.6
Total other income and expenses, net	$	15.5	$	12.9	$	9.1

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NOTE 15:  QUARTERLY FINANCIAL INFORMATION (Unaudited)

	2006 Quarters Ended (a)									2005 Quarters Ended (a)
(In millions)	December 31			September 30		June 30		March 31		December 31			September 30			June 30			March 31
Operating revenues	$	185.2		$	213.9	$	177.4	$	197.2	$	204.7		$	220.5		$	178.1		$	186.6
Operating income (loss)	$	34.7		$	29.1	$	17.4	$	41.9	$	(1.2	)	$	(1.8	)	$	8.4		$	19.5
Income (loss) from continuing operations	$	27.8		$	13.7	$	6.9	$	21.7	$	(5.8	)	$	(5.4	)	$	9.1		$	11.3
Income (loss) from discontinued operations, net		(1.0	)		—		—		—		3.4			(6.8	)		(6.5	)		10.9
Net income (loss)	$	26.8		$	13.7	$	6.9	$	21.7	$	(2.4	)	$	(12.2	)	$	2.6		$	22.2

(a) Amounts may not total to year to date results due to rounding.

NOTE 16:  COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Allegheny is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.

Global Climate Change.  Allegheny’s generation facilities are primarily coal-fired facilities and, therefore, emit carbon dioxide as coal is consumed. Carbon dioxide, or “CO₂,” is one of the greenhouse gases implicated in global climate change. There is no current technology that enables control of such emissions from existing pulverized, coal-fired power plants, which constitute the majority of Allegheny’s generation fleet. At the same time, Allegheny takes its responsibility for environmental stewardship seriously and recognizes its obligation to its shareholders to address the issue of climate change. Despite the regulatory actions of some states and regional groups in 2006, Allegheny believes that the challenge presented by global climate change can only be resolved with global solutions. In addition, Allegheny believes that the United States must commit to a response that both encourages the development of technology and creates a workable control system. The United States Congress is moving towards the development of national legislation, yet the process is still in its infancy. As such, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures until the exact nature and requirements of a national regulation are known, and the capabilities of control or reduction technologies are more fully understood. Allegheny recognized the possibility that federal legislation and implementation regulations addressing climate change will be adopted some time in the future. Allegheny’s current strategy focuses on:

• developing an accurate CO₂ emissions inventory;

• improving the efficiency of its coal-burning fleet;

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

• following developing technologies for carbon sequestration;

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

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

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To the extent that legislation is introduced and programs are developed, Allegheny intends to advocate for a national approach that protects its generating fleet and investments, enhances the environment, and ensures continued energy supply for its customers. Allegheny’s management is following this issue closely and will take further appropriate action as the economics and legislation, if any, unfold.

Clean Air Act Matters.  Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through 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 1970 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule (“CAIR”) promulgated by the 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 2007 of about 30,000 to 50,000 tons and may have exposure in 2008 of between 85,000 and 120,000 tons. Monongahela’s exposure is expected to be approximately 70% and 50% of Allegheny’s exposure in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO₂ allowances for these periods will not vary from current estimates. Allegheny continues to evaluate options for compliance, and current plans include the installation of flue gas desulfurization equipment (“Scrubbers”) at its Hatfield’s Ferry and Fort Martin generating facilities by 2009 and the elimination of a scrubber bypass at its Pleasants generation facility by 2008. In July 2006, AE Supply entered into construction contracts with The Babcock & Wilcox Company (“B&W”) and Washington Group International (“WGI”) in connection with its plans to install scrubbers at its Hatfield’s Ferry generation facility.

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

AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. The NOx compliance plan functions on a system-wide basis, similar to the SO₂ compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. Allegheny estimates that its emission control activities, in concert with its inventory of banked allowances and future transactions, will facilitate its compliance with NOx limits established by the SIP through 2008. Based on these estimates, Allegheny estimates that it will have minimal exposure to the NOx allowance market through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities. Therefore, there can be no assurance that Allegheny’s need to purchase NO_X allowances for these periods will not vary from current estimates.

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On March 15, 2005, the United States Environmental Protection Agency (the “EPA”) issued the Clean Air Mercury Rule (“CAMR”) establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and its strategy for compliance. The Pennsylvania Department of Environmental Protection (the “PA DEP”) proposed a more aggressive mercury control rule on June 24, 2006, which is going through the regulatory review process and which is expected to be finalized in the first quarter of 2007. Allegheny is assessing the proposed rule to determine what, if any, effect it would have on Allegheny’s Pennsylvania 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.

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

If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology. There are three recent, significant federal court decisions that have addressed the application of NSR requirements to electric utility generation facilities: the Ohio Edison decision, the Duke Energy decision and the Alabama Power decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy and Alabama Power decisions support the industry’s understanding of NSR requirements. The U.S. Court of Appeals for the Fourth Circuit affirmed the Duke Energy decision on June 15, 2005. On May 15, 2006, the U.S. Supreme Court agreed to hear an appeal of the Fourth Circuit’s decision in the Duke Energy case. Oral argument took place on November 1, 2006, and a decision is expected by the summer of 2007. The Supreme Court’s decision may provide clarity on whether the industry’s or the government’s interpretation of 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 Pennsylvania Department of Environmental Protection (the “PA DEP”). The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

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

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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 February 17, 2006, Allegheny filed a motion to dismiss the amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss. On June 30, 2006, Allegheny filed an answer to the plaintiff’s first amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies, and the liability phase of discovery should be completed by June 30, 2007.

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

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

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

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

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2006, Allegheny had 828 open cases remaining in West Virginia and four open cases remaining in Pennsylvania.

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

Other Litigation

Harrison Fuel Litigation.  On November 7, 2001, Harrison Fuel and its owner filed a lawsuit against Monongahela, “Allegheny Power” and AESC in the Circuit Court of Marion County, West Virginia. The lawsuit claims that Allegheny improperly and arbitrarily rejected bids from Harrison Fuel and other companies affiliated with its owner to supply coal to Allegheny. Plaintiffs seek damages of approximately $13 million. On January 5, 2007, the Court entered an order setting this case for trial on May 14, 2007. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

Ordinary Course of Business.  Monongahela is 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

Monongahela estimates that its capital expenditures will approximate $260 million in 2007 and $355 million in 2008, including amounts relating to significant multiple year environmental and transmission expansion projects. Capital expenditure levels in 2007 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. See “Environmental Matters and Litigation—Clean Air Act Matters,” above.

Leases

Monongahela has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles, buildings and computer equipment.

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Total capital and operating lease rent payments of $5.2 million in 2006, $7.3 million in 2005 and $7.8 million in 2004 were recorded as rent expense. Monongahela’s estimated future minimum lease payments for capital and operating leases, including those leases entered into by AESC which are allocated to Monongahela and certain other leases related to discontinued operations, with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are:

(In millions)	2007		2008		2009		2010		2011		Thereafter		Total		Less amounts representing interest and Fees		Present value of net minimum capital lease
Capital Leases	$	3.1	$	2.3	$	1.9	$	1.4	$	1.1	$	1.7	$	11.5	$	2.0	$	9.5
Allocated Capital Leases		0.1		0.1		0.1		0.2		—		—		0.5		0.1		0.4
Total Capital Leases	$	3.2	$	2.4	$	2.0	$	1.6	$	1.1	$	1.7	$	12.0	$	2.1	$	9.9
Operating Leases	$	0.4	$	0.2	$	—	$	—	$	—	$	—	$	0.6	$	—	$	—

The carrying amount of assets recorded under capitalized lease agreements included in “Property, plant and equipment, net” at December 31 consists of the following:

(In millions)	2006		2005
Equipment	$	9.2	$	8.4
Building		0.3		0.4
Property held under capital leases	$	9.5	$	8.8

PURPA

The Energy Policy Act of 2005 (the “Energy Policy Act”) has amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contract obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission. This change does not impact Monongahela’s current PURPA contracts.

Monongahela is committed to purchase the electrical output from 161 MWs of qualifying PURPA capacity. Payments for PURPA capacity and energy in 2006, 2005 and 2004 totaled $61.8 million, $57.9 million and $56.6 million, respectively. The average cost to Monongahela of these power purchases was approximately 4.6, 4.4 and 4.3 cents per kWh in 2006, 2005 and 2004, respectively. Monongahela is currently authorized to recover PURPA costs in its retail rates.

The table below reflects Monongahela’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2006. Actual values can vary substantially depending upon future conditions.

(In millions)	KWhs	Amount
2007	1,298.2	$	65.0
2008	1,301.2		65.7
2009	1,298.2		66.1
2010	1,298.2		66.6
2011	1,302.6		67.5
Thereafter	27,582.8		1,457.0
Total	34,081.2	$	1,787.9

220

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Fuel Purchase and Transportation Commitments

Monongahela has entered into various long-term commitments for the procurement and transportation of fuel (primarily coal and lime) to supply its generation facilities. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Monongahela’s fuel expense was $178.0 million, $153.1 million and $123.4 million in 2006, 2005 and 2004, respectively. In 2006, Monongahela purchased approximately 44% of its fuel from one vendor. Total estimated long-term fuel purchase and transportation commitments (primarily coal and lime), were as follows, by year, and in total:

(In millions)	Amount
2007	$	232.0
2008		127.6
2009		112.7
2010		84.5
2011		78.2
Thereafter		618.6
Total	$	1,253.6

NOTE 17:  SUBSEQUENT EVENT—ASSET SWAP

Effective January 1, 2007, AE Supply and Monongahela completed an Asset Swap that realigned generation ownership and contractual arrangements within the Allegheny system. As a result of the Asset Swap, Monongahela owns 100% of the Fort Martin generation facility in West Virginia (“Fort Martin”), which will allow Allegheny to finance the construction of Scrubbers at Fort Martin through the securitization of an environmental control charge that Monongahela and Potomac Edison will impose on their retail customers in West Virginia.

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 will sell 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 is required to pay 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, must be redeemed as a result of the change in ownership of Fort Martin.

The Asset Swap was recorded on January 1, 2007 at the net book value of the assets, liabilities and interests transferred, with certain adjustments, and resulted in an increase in stockholder’s equity by Monongahela of approximately $54 million.

221

R eport of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Monongahela Power Company:

In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of operations, stockholder's equity and cash flows present fairly, in all material respects, the financial position of Monongahela Power Company and its subsidiaries (the “Company”) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 27, 2007

222

A LLEGHENY GENERATING COMPANY

Statements of Operations

	Year Ended December 31,
(In thousands)	2006		2005		2004
Operating revenues	$	65,319	$	66,602	$	69,200
Operating expenses:
Operations and maintenance		5,604		4,642		6,181
Depreciation		17,124		17,180		17,056
Taxes other than income taxes		2,866		2,928		2,886
Total operating expenses		25,594		24,750		26,123
Operating income		39,725		41,852		43,077
Other income, net		909		226		94
Interest expense		7,188		7,395		8,455
Income before income taxes		33,446		34,683		34,716
Income tax expense		8,677		3,562		7,324
Net income	$	24,769	$	31,121	$	27,392

See accompanying Notes to Financial Statements.

223

ALLEGHENY GENERATING COMPANY

Statements of Cash Flows

	Year Ended December 31,
(In thousands)	2006			2005			2004
Cash Flows From Operating Activities:
Net income	$	24,769		$	31,121		$	27,392
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		17,124			17,180			17,056
Deferred income taxes and investment tax credit, net		(6,709	)		(4,960	)		(5,937	)
Other, net		287			286			1,202
Changes in certain assets and liabilities:
Accounts receivable due from/payable to affiliates, net		936			4,195			1,472
Materials and supplies		(169	)		(120	)		(53	)
Taxes receivable/accrued, net		2,242			(6,081	)		668
Prepayments		(128	)		39			19
Other current assets		(7	)		(4	)		(10	)
Accounts payable		(2,096	)		2,662			26
Other current liabilities		1			—			—
Other assets		1			(129	)		1
Other liabilities		—			—			1
Net cash provided by operating activities		36,251			44,189			41,837
Cash Flows From Investing Activities:
Capital expenditures		(4,263	)		(13,031	)		(9,109	)
Cash Flows From Financing Activities:
Note payable to parent		—			(15,000	)		(15,000	)
Cash dividends paid on common stock		(31,000	)		(21,800	)		(12,500	)
Net cash used in financing activities		(31,000	)		(36,800	)		(27,500	)
Net increase (decrease) in cash and cash equivalents		988			(5,642	)		5,228
Cash and cash equivalents at beginning of period		1,858			7,500			2,272
Cash and cash equivalents at end of period	$	2,846		$	1,858		$	7,500
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest	$	6,902		$	7,109		$	8,169
Income taxes, net	$	16,305		$	14,603		$	12,592

See accompanying Notes to Financial Statements.

224

ALLEGHENY GENERATING COMPANY

Balance Sheets

	As of December 31,
(In thousands)	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	2,846		$	1,858
Materials and supplies		1,720			1,551
Taxes receivable		762			3,004
Other		360			225
Total current assets		5,688			6,638
Property, Plant and Equipment, Net:
Generation		777,507			788,952
Transmission		55,169			47,098
Other		2,949			2,960
Accumulated depreciation		(318,164	)		(316,250	)
Subtotal		517,461			522,760
Construction work in progress		6,963			12,372
Total property, plant and equipment, net		524,424			535,132
Deferred Charges:
Regulatory assets		7,842			8,295
Other		92			97
Total deferred charges		7,934			8,392
Total Assets	$	538,046		$	550,162

See accompanying Notes to Financial Statements.

225

ALLEGHENY GENERATING COMPANY

Balance Sheets—(Continued)

	As of December 31,
(In thousands, except share data)	2006		2005
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	2,746	$	2,687
Accounts payable to affiliates, net		5,632		4,696
Accrued interest		2,292		2,292
Total current liabilities		10,670		9,675
Long-term Debt (Note 2)		99,458		99,425
Deferred Credits and Other Liabilities:
Investment tax credit		35,953		37,273
Non-current affiliated income taxes payable		17,544		17,544
Deferred income taxes		148,824		153,630
Regulatory liabilities		22,018		22,806
Total deferred credits and other liabilities		224,339		231,253
Commitments and Contingencies (Note 9)
Stockholders’ Equity:
Common stock, $1.00 par value, 5,000 shares authorized and 1,000 shares outstanding at December 31, 2006 and 2005		1		1
Other paid-in capital		172,669		172,669
Retained earnings		30,909		37,139
Total stockholders’ equity		203,579		209,809
Total Liabilities and Stockholders’ Equity	$	538,046	$	550,162

See accompanying Notes to Financial Statements.

226

ALLEGHENY GENERATING COMPANY

Statements of Stockholders’ Equity

(In thousands, except shares)	Shares outstanding	Common stock		Other paid-in capital		Retained earnings			Total stockholders’ equity
Balance at December 31, 2003	1,000	$	1	$	172,669	$	12,926		$	185,596
Net income	—		—		—		27,392			27,392
Dividends declared on common stock	—		—		—		(12,500	)		(12,500	)
Balance at December 31, 2004	1,000		1		172,669		27,818			200,488
Net income	—		—		—		31,121			31,121
Dividends declared on common stock	—		—		—		(21,800	)		(21,800	)
Balance at December 31, 2005	1,000		1		172,669		37,139			209,809
Net income	—		—		—		24,769			24,769
Dividends declared on common stock	—		—		—		(31,000	)		(31,000	)
Other	—		—		—		1			1
Balance at December 31, 2006	1,000	$	1	$	172,669	$	30,909		$	203,579

See accompanying Notes to Financial Statements.

227

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS

Note No.		Page No.
1	Basis of Presentation	229
2	Capitalization	232
3	Jointly Owned Electric Utility Plants	233
4	Pension Benefits and Postretirement Benefits Other Than Pensions	233
5	Income Taxes	234
6	Regulatory Assets and Liabilities	236
7	Fair Value of Financial Instruments	236
8	Quarterly Financial Information (Unaudited)	236
9	Commitments and Contingencies	237

228

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS

NOTE 1:  BASIS OF PRESENTATION

Allegheny Energy Supply Company, LLC (“AE Supply”) and Monongahela Power Company (“Monongahela” and together with AE Supply, the “Parents”), own 100% of Allegheny Generating Company (“AGC”). Through December 31, 2006, AE Supply owned approximately 77% and Monongahela owned approximately 23% of AGC. AGC owns an undivided 40% interest (1,035 megawatts (“MWs”)) in the 2,525 MWs pumped storage, hydroelectric station in Bath County, Virginia, operated by the 60% owner, Virginia Electric and Power Company, a nonaffiliated utility. AGC sells its generation capacity to its Parents. AGC operates under a single business segment, Generation and Marketing. As a result of a realignment of generation ownership and contractual arrangements within the Allegheny system, effective January 1, 2007, AE Supply’s and Monongahela’s ownership interests in AGC changed to approximately 59% and 41%, respectively.

AGC is subject to regulation by the Securities and Exchange Commission (“SEC”), the Virginia State Corporation Commission and the Federal Energy Regulatory Commission (“FERC”).

Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who are employed by Allegheny. As of December 31, 2006, AESC employed approximately 4,362 employees, of which approximately 1,250 are subject to collective bargaining arrangements.

Significant accounting policies of AGC are summarized below.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires AGC to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a continuous basis, AGC evaluates its estimates, including those related to the calculation of the provisions for depreciation and amortization, regulatory assets and liabilities, income taxes and contingencies related to environmental matters and litigation. AGC bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Regulatory Assets and Liabilities

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

AGC accounts for its regulated operations under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs or revenues would be recognized by an unregulated enterprise. Accordingly, AGC records assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” AGC periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, AGC may have to adjust its regulatory assets and liabilities to reflect a market basis less than cost.

See Note 6, “Regulatory Assets and Liabilities,” for additional information.

229

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

Revenues

Revenues are determined under a “cost-of-service” formula wholesale rate schedule approved by FERC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment. All capacity sales of AGC are made to AE Supply and Monongahela.

Debt Issuance Costs

Costs incurred to issue debt are recorded as deferred charges on the 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.

Long-Lived Assets

AGC’s long-lived assets owned by AGC are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows.

Property, Plant and Equipment

AGC’s property, plant and equipment are stated at original cost and consist of a 40% undivided interest in the Bath County pumped-storage hydroelectric station and its connecting transmission facilities. Upon retirement, the costs of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation with no gain or loss recorded.

Depreciation and Maintenance

Depreciation expense is determined in accordance with currently enacted regulatory rates. Depreciation expense amounted to approximately 2.1% of average depreciable property in 2006, 2005 and 2004. Estimated service lives for Generation, Transmission and other property at December 31, 2006 are as follows:

	Years
Generation property:
Hydroelectric dams and facilities	50
Transmission property:
Electric equipment	35
Other property:
Office buildings and improvements	35
Computers, software and information systems	20

Maintenance expenses represent costs incurred to maintain the power station and general plant. These expenses reflect routine maintenance of equipment, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power station. Maintenance costs are expensed as incurred.

230

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

Intercompany Transactions

AGC has various operating transactions with its affiliates. AGC’s policy is that the affiliated receivable and payable balances outstanding from these transactions are presented on a net basis on the Balance Sheets and the Statements of Cash Flows.

Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for AGC and its affiliates. AGC is responsible for its proportionate share of services provided by AESC. Total billings by AESC (including capital) to AGC in 2006, 2005 and 2004 were not material.

Pursuant to an agreement, AE Supply and Monongahela purchase all of AGC’s capacity in the Bath County, Virginia pumped-storage hydroelectric station priced under a “cost-of-service formula” wholesale rate schedule approved by FERC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment. AE Supply and Monongahela purchase power from AGC on a proportional basis, based on their respective equity ownership of AGC.

In accordance with a consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various affiliated companies at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the intercompany balance.

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’s federal funds effective interest rate, or the Federal Reserve’s previous day’s seven day commercial paper rate, less four basis points. AGC can only borrow money from the money pool. At December 31, 2006 and 2005, AGC did not have any outstanding borrowings from the money pool.

At December 31, 2006 and 2005, AGC had net accounts payable to affiliates of $5.6 million and $4.7 million, respectively.

Cash Equivalents

For purposes of the Statements of Cash Flows and Balance Sheets, temporary cash investments, generally in the form of commercial paper, certificates of deposit, repurchase agreements and money market funds, are considered to be the equivalent of cash.

Inventory

AGC values materials and supplies inventory using an average cost method.

Income Taxes

AE and its subsidiaries, including AGC, file a consolidated federal income tax return. The consolidated income tax liability is allocated among AE and its subsidiaries, generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability.

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

231

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

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 5, “Income Taxes,” for additional information.

Pension and Other Postretirement Benefits

AE has noncontributory, defined benefit pension plans 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.

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, are based upon an age and years-of-service vesting schedule, other plan provisions and 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.

Through AESC, AGC is responsible for its proportionate share of pension and postretirement benefit costs.

See Note 4, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for additional information.

Recent Accounting Pronouncement

The following accounting pronouncement was adopted by AGC during 2006:

In September 2006, the SEC issued Staff Accounting Bulletin 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 is effective for AGC for its December 31, 2006 annual financial statements and its adoption did not impact AGC’s financial statements.

NOTE 2:  CAPITALIZATION

AGC’s capital structure, including short-term debt, as of December 31, 2006 and 2005, was as follows:

	2006			2005
(In millions, except percent)	Amount		%	Amount		%
Debt	$	99.4	32.8	$	99.4	32.1
Common equity		203.6	67.2		209.8	67.9
Total	$	303.0	100.0	$	309.2	100.0

232

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

Long-term Debt

As of December 31, 2006, contractual maturities of long-term debt excluding unamortized debt discounts of $0.5 million, are as follows:

(In millions)	2007		2008		2009		2010		2011		Thereafter		Total
Debentures	$	—	$	—	$	—	$	—	$	—	$	100.0	$	100.0

Debt Activity

AGC repaid $15.0 million of its note payable to AE Supply during 2005.

NOTE 3:  JOINTLY OWNED ELECTRIC UTILITY PLANTS

AGC jointly owns an electric generation facility with a third party. AGC records its proportionate share of operating costs, assets and liabilities related to this generation facility in the corresponding lines in the Financial Statements. As of December 31, 2006 and 2005, AGC’s investment and accumulated depreciation in the Bath County generation facility, were as follows:

(Dollars in millions)	2006			2005
Utility plant investment	$	835.6		$	839.0
Accumulated depreciation	$	318.1		$	316.3
Ownership %		40	%		40	%

NOTE 4:  PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

AGC is responsible for its proportionate share of the net periodic cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by Allegheny, through AESC. AGC’s share of these costs was not material for the years ended December 31, 2006, 2005 and 2004, respectively.

The assumptions used to determine net periodic benefit costs for years ended December 31, 2006, 2005 and 2004 are shown in the table below.

	Pension Benefits						Postretirement Benefits Other Than Pension
	2006		2005		2004		2006		2005		2004
Discount rate	5.60	%	5.90	%	6.00	%	5.60	%	5.90	%	6.00	%
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	3.25	%	3.25	%	3.75	%	3.25	%	3.25	%	3.75	%

(a) Excluding administrative expenses.

The assumptions used to determine benefit obligations at December 31, 2006 and 2005 and are shown in the table below:

	Pension Benefits				Postretirement Benefits Other Than Pensions
	2006		2005		2006		2005
Discount rate	6.00	%	5.60	%	6.00	%	5.60	%
Rate of compensation increase	3.60	%(a)	3.25	%	3.60	%(a)	3.25	%

(a) Weighted-average rate for age graded scale.

233

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

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

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs in 2007 is 8.25%, which is net of administrative expenses.

Assumed health care cost trend rates at December 31 are as follows:

	2006		2005
Health care cost trend rate assumed for next year	9.0	%	9.5	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2015		2015

For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.0% beginning with 2007 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 effect on the amounts allocated to AGC.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) became law. 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, in 2006, Allegheny is receiving the federal subsidy offered under the Medicare Act.

NOTE 5:  INCOME TAXES

Details of federal and state income tax expense (benefit) are:

(In millions)	2006			2005			2004
Income tax expense—current:
Federal	$	17.4		$	12.5		$	11.6
State		(2.0	)		(4.0	)		1.7
Total		15.4			8.5			13.3
Income tax benefit deferred, net of amortization		(5.4	)		(3.6	)		(4.7	)
Amortization of deferred investment tax credit		(1.3	)		(1.3	)		(1.3	)
Total income tax expense	$	8.7		$	3.6		$	7.3

234

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

AGC has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.

The total provision for income tax expense differs from the amount produced by applying the federal statutory income tax rate of 35% to financial accounting income before income taxes, due to the following reconciling items:

	2006					2005					2004
(In millions, except %)	Amount			%		Amount			%		Amount			%
Income before income taxes	$	33.5				$	34.7				$	34.7
Income tax expense calculated using the federal statutory rate of 35%	$	11.7		35.0		$	12.2		35.0		$	12.2		35.0
Increases (reductions) resulting from:
Consolidated return benefit		(0.3	)	(0.9	)		(5.8	)	(16.7	)		(3.2	)	(9.1	)
Amortization of deferred investment tax credit		(1.3	)	(3.9	)		(1.3	)	(3.7	)		(1.3	)	(3.8	)
State income tax, net of federal income tax		(1.6	)	(4.8	)		(1.6	)	(4.6	)		0.7		2.1
Other, net		0.2		0.6			0.1		0.3			(1.1	)	(3.2	)
Total income tax expense	$	8.7		26.0		$	3.6		10.3		$	7.3		21.0

At December 31, the deferred income tax assets and liabilities consisted of the following:

(In millions)	2006		2005
Deferred tax assets:
Unamortized investment tax credit	$	22.0	$	22.8
Other deferred tax assets		0.3		0.3
Total deferred tax assets		22.3		23.1
Deferred tax liabilities:
Plant asset basis differences, net		169.6		175.1
Other deferred tax liabilities		1.5		1.6
Total deferred tax liabilities		171.1		176.7
Total net deferred tax liabilities	$	148.8	$	153.6

AGC is a party to a consolidated tax sharing agreement that allocates a portion of the consolidated tax liability or benefit on the basis of AGC’s relative contribution to such liability or benefit. To the extent AGC has a net operating loss, such loss may only be used to offset its past or future income tax liability determined on a separate company basis to the extent of AGC’s accumulated earnings and profits.

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109 (“FIN 48”), which is effective for fiscal periods beginning after December 15, 2006. FIN 48 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 positions should initially be recognized in the financial statements when it is more likely than not the position will be sustained upon examination by the tax authorities. Such tax positions should be initially and subsequently 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. The Company will be required to apply the provisions of FIN 48 to all tax positions upon initial

235

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

adoption with any cumulative effect adjustment to be recognized as an adjustment to retained earnings. The Company does not expect that the adoption of FIN 48 will have a significant impact on its consolidated financial statements.

NOTE 6:  REGULATORY ASSETS AND LIABILITIES

AGC’s operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process. Regulatory assets and regulatory liabilities, reflected in the Balance Sheets at December 31 relate to:

(In millions)	2006		2005
Regulatory assets:
Income taxes	$	3.7	$	3.9
Unamortized loss on reacquired debt		4.1		4.4
Subtotal		7.8		8.3
Regulatory liabilities:
Income taxes		22.0		22.8
Net regulatory liabilities	$	14.2	$	14.5

NOTE 7:  FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of long-term debt, at December 31, were as follows:

	As of December 31,
	2006				2005
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	99.5	$	101.8	$	99.4	$	101.6

The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The carrying amounts of cash equivalents and short-term debt approximate the fair values of such financial instruments because of the short maturities of these instruments.

NOTE 8:  QUARTERLY FINANCIAL INFORMATION (Unaudited)

	2006 Quarters Ended (a)								2005 Quarters Ended (a)
(In millions)	December 31		September 30		June 30		March 31		December 31		September 30		June 30		March 31
Operating revenues	$	17.2	$	16.9	$	13.9	$	17.3	$	15.7	$	17.4	$	16.7	$	16.9
Operating income	$	10.8	$	10.4	$	7.8	$	10.7	$	9.4	$	11.1	$	10.6	$	10.7
Net income	$	6.0	$	5.9	$	6.7	$	6.1	$	8.6	$	7.4	$	7.8	$	7.4

(a) Amounts may not total to year to date results due to rounding.

236

ALLEGHENY GENERATING COMPANY

NOTES TO FINANCIAL STATEMENTS—(Continued)

NOTE 9:  COMMITMENTS AND CONTINGENCIES

Environmental Matters and Litigation

Allegheny is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.

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

Ordinary Course of Business

AGC is, from time to time, involved in litigation and other legal disputes in the ordinary course of business. AGC is of the belief that there are no other legal proceedings that could have a material effect on its business or financial condition.

Construction and Capital Program

AGC estimates that its capital expenditures will approximate $7 million in 2007 and $5 million in 2008.

237

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

of Allegheny Generating Company:

In our opinion, the accompanying balance sheets and the related statements of operations, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of Allegheny Generating Company (the “Company”) at December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 27, 2007

238

S-1

SCHEDULE I

ALLEGHENY ENERGY, INC. (Parent Company)

Condensed Financial Statements

Statements of Operations:
	Year ended December 31,
(In thousands)	2006			2005			2004
Operating revenues	$	—		$	—		$	—
Operating expenses		6,839			5,241			(572	)
Operating income (loss)		(6,839	)		(5,241	)		572
Equity in earnings (loss) of subsidiaries		348,314			200,319			(237,983	)
Other income and expenses, net		3,072			1,743			546
Interest expense		23,131			132,148			72,641
Income (loss) before income taxes		321,416			64,673			(309,506	)
Income tax expense (benefit)		2,095			1,608			1,092
Net income (loss)	$	319,321		$	63,065		$	(310,598	)
Statements of Cash Flows:
	Year ended December 31,
(In thousands)	2006			2005			2004
Net cash provided by operating activities	$	137,951		$	155,442		$	408,658
Cash flows from investing activities:
Notes receivable from subsidiaries		4,895			887			(18,217	)
Proceeds from sale of asset		—			—			7,140
Contributions to subsidiaries		(13,911	)		—			(467,999	)
Return of capital from subsidiaries		—			88,000			—
Net cash provided by (used in) investing activities		(9,016	)		88,887			(479,076	)
Cash flows from financing activities:
Issuance of long-term debt, net of $1.1 million, $9.1 million and $6.8 million in debt issuance costs, respectively		217,997			459,861			218,243
Retirement of long-term debt		(418,071	)		(670,000	)		(381,980	)
Proceeds from issuance of common stock		—			—			151,360
Exercise of stock options		24,691			2,941			227
Net cash provided by (used in) financing activities		(175,383	)		(207,198	)		(12,150	)
Net increase (decrease) in cash and cash equivalents		(46,448	)		37,131			(82,568	)
Cash and cash equivalents at beginning of period		56,079			18,948			101,516
Cash and cash equivalents at end of period	$	9,631		$	56,079		$	18,948
Cash dividends received from consolidated subsidiaries	$	147,702		$	244,491		$	475,607

Balance Sheets:
	As of December 31,
(In thousands)	2006		2005
ASSETS
Current assets	$	54,492	$	93,038
Investments and other assets		2,089,492		1,839,431
Deferred charges		8,302		63,253
Total asset	$	2,152,286	$	1,995,722
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	71,389	$	102,201
Long-term debt		—		197,500
Deferred credits and other liabilities		502		726
Stockholders’ equity		2,080,395		1,695,295
Total liabilities and stockholders’ equity	$	2,152,286	$	1,995,722

See accompanying Notes to Condensed Financial Statements.

239

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 $107.2 million and $142.7 million at December 31, 2006 and 2005, respectively.

The condensed balance sheet as of December 31, 2005 was revised during 2006 to reflect the accumulated other comprehensive loss of AE’s subsidiaries at that date, resulting in a decrease in investments in subsidiaries and a decrease in stockholders’ equity in the amount of $142.7 million, compared to amounts previously reported. This revision did not affect reported net income or cash flows of AE.

240

S-2

SCHEDULE II

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

For Years Ended December 31, 2006, 2005 and 2004

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses (a)		Charged to Other Accounts (b)		Deductions (c)		Balance at End of Period (d)
Allowance for uncollectible accounts:
Year Ended 12/31/06	$	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
Year Ended 12/31/04	$	29,329,476	$	18,930,902	$	4,299,139	$	32,705,349	$	19,854,168

(a) Amount charged to bad debt expense.

(b) Collection of accounts previously written off.

(c) Uncollectible accounts written off during the year. In 2004, the amount also includes $1,722,744 related to the gas business that was reclassified to assets held for sale.

(d) Balance at December 31, 2004 excludes the allowance for uncollectible accounts for the gas business of $3,525,033.

241

S-3

SCHEDULE II

MONONGAHELA POWER COMPANY AND SUBSIDIARIES

Valuation and Qualifying Accounts

For Years Ended December 31, 2006, 2005 and 2004

			Additions
Description	Balance at Beginning of Period		Charged to Costs and Expenses (a)		Charged to Other Accounts (b)		Deductions (c)		Balance at End of Period (d)
Allowance for uncollectible accounts:
Year Ended 12/31/06	$	2,488,800	$	2,486,643	$	1,081,434	$	3,961,731	$	2,095,146
Year Ended 12/31/05	$	2,616,205	$	2,687,770	$	1,292,125	$	4,107,300	$	2,488,800
Year Ended 12/31/04	$	4,955,196	$	3,165,129	$	1,048,752	$	6,552,872	$	2,616,205

(a) Amount charged to bad debt expense.

(b) Collection of accounts previously written off.

(c) Uncollectible accounts written off during the year. In 2004, the amount also includes $1,722,744 related to the gas business that was reclassified to assets held for sale.

(d) Balance at December 31, 2004 excludes the allowance for uncollectible accounts for the gas business of $3,525,033.

242

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not Applicable.

ITEM 9A.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.    Each Registrant carried out an evaluation, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, of the effectiveness of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, as of December 31, 2006 (the “Evaluation Date”). These disclosure controls and procedures are designed to provide reasonable assurance to each registrant’s management and board of directors that information required to be disclosed by us in the reports that we filed under the Exchange Act is accumulated and communicated to our management as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, the principal executive officer and principal financial officer of each Registrant have concluded that the applicable Registrant’s disclosure controls and procedures as of December 31, 2006 were effective, at the reasonable assurance level, to ensure that (a) material information relating to each Registrant is accumulated and made known to the Registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure and (b) is recorded, processed, summarized and reported within the time periods specified in 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;

(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that AE’s receipts and expenditures are being made only in accordance with authorizations of its management and directors; and

(3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the AE’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

AE’s management assessed the effectiveness of AE’s internal control over financial reporting as of December 31, 2006. 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, 2006, AE’s internal control over financial reporting is effective based on those criteria.

243

Management’s assessment of the effectiveness of AE’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that appears herein.

Changes in Internal Control over Financial Reporting:    There have been no changes in the registrants’ 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, 2006. Effective January 1, 2007, Allegheny implemented SAP enterprise resource planning software in its operations.

ITEM 9B. OTHER INFORMATION

Not Applicable.

244

PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

The information required by this Item (other than the information set forth below) is contained in AE’s Proxy Statement for its 2007 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 of the Registrants.”

Code of Business Conduct and Ethics

In early 2004, Allegheny adopted a new Code of Business Conduct and Ethics for its directors, officers and employees in order to promote honest and ethical conduct and compliance with the laws and regulations to which Allegheny is subject. All directors, officers and employees of Allegheny are expected to be familiar with the Code of Business Conduct and Ethics and to adhere to its principles and procedures.

ITEM 11.    EXECUTIVE COMPENSATION

The information required by this Item is contained in AE’s Proxy Statement for the 2007 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

The information required by this Item is contained in AE’s Proxy Statement for the 2007 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors” and “Executive Compensation” and is incorporated herein by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this Item is contained in AE’s Proxy Statement for the 2007 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors” and “Executive Compensation” and is incorporated herein by reference.

ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is contained in AE’s Proxy Statement for the 2007 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors” and “Executive Compensation” and is incorporated herein by reference.

245

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 125.
(b)	Exhibits for AE, Monongahela and AGC are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE EXCHANGE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE EXCHANGE ACT

No annual report or proxy material has been sent to security holders for:

Monongahela

AGC

246

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, 2007

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, 2007
(ii)	Principal Financial Officer:
	/S/    PHILIP L. GOULDING         (Philip L. Goulding)	Senior Vice President and Chief Financial Officer	February 27, 2007
(iii)	Principal Accounting Officer:
	/S/    THOMAS R. GARDNER         (Thomas R. Gardner)	Vice President, Controller, Chief Accounting Officer and Chief Information Officer	February 27, 2007
(iv)	Directors:
	/S/    H. FURLONG BALDWIN         (H. Furlong Baldwin)	/S/    TED J. KLEISNER         (Ted J. Kleisner)
	/S/    ELEANOR BAUM         (Eleanor Baum)	/S/    STEVEN H. RICE         (Steven H. Rice)
	/S/    PAUL J. EVANSON         (Paul J. Evanson)	/S/    GUNNAR E. SARSTEN         (Gunnar E. Sarsten)	February 27, 2007
	/S/    CYRUS F. FREIDHEIM, JR.         (Cyrus F. Freidheim, Jr.)	/S/    MICHAEL H. SUTTON         (Michael H. Sutton)
	/S/    JULIA L. JOHNSON         (Julia L. Johnson)

247

SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

MONONGAHELA POWER COMPANY
By:	/S/    DAVID E. FLITMAN
	(David E. Flitman, President)

Date: February 27, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

	Signature	Title	Date
(i)	Principal Executive Officer:
	/S/    PAUL J. EVANSON         (Paul J. Evanson)	Chairman and Chief Executive Officer	February 27, 2007
(ii)	Principal Financial Officer:
	/S/    PHILIP L. GOULDING         (Philip L. Goulding)	Vice President and Director	February 27, 2007
(iii)	Principal Accounting Officer:
	/S/    THOMAS R. GARDNER         (Thomas R. Gardner)	Controller	February 27, 2007
(iv)	Directors:
	/S/    PAUL J. EVANSON         (Paul J. Evanson)
	/S/    PHILIP L. GOULDING         (Philip L. Goulding)		February 27, 2007
	/S/    DAVID E. FLITMAN         (David E. Flitman)

248

SIGNATURES

Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

ALLEGHENY GENERATING COMPANY
By:	/S/    PAUL J. EVANSON
	(Paul J. Evanson, Chairman and Chief Executive Officer)

Date: February 27, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

	Signature	Title	Date
(i)	Principal Executive Officer:
	/S/    PAUL J. EVANSON         (Paul J. Evanson)	Chairman and Chief Executive Officer	February 27, 2007
(ii)	Principal Financial Officer:
	/S/    PHILIP L. GOULDING         (Philip L. Goulding)	Vice President and Director	February 27, 2007
(iii)	Principal Accounting Officer:
	/S/    THOMAS R. GARDNER         (Thomas R. Gardner)	Vice President and Controller	February 27, 2007
(iv)	Directors:
	/S/    PAUL J. EVANSON         (Paul J. Evanson)	/S/    DAVID E. FLITMAN         (David E. Flitman)	February 27, 2007
	/S/    PHILIP L. GOULDING         (Philip L. Goulding)

249

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, 2007 relating to the financial statements, financial statement schedules, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

We also hereby consent to the incorporation by reference in Registration Statements on Form S-3 (Nos. 333-31493, 33-51301, 33-56262, 033-59131, 333-31493 and 333-38484) of Monongahela Power Company of our report dated February 27, 2007 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 27, 2007

250

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, 2006, 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, 2007

/S/    H. FURLONG BALDWIN	/S/    TED J. KLEISNER
(H. Furlong Baldwin)	(Ted J. Kleisner)
/S/    ELEANOR BAUM	/S/    STEVEN H. RICE
(Eleanor Baum)	(Steven H. Rice)
/S/    PAUL J. EVANSON	/S/    GUNNAR E. SARSTEN
(Paul J. Evanson)	(Gunnar E. Sarsten)
/S/    CYRUS F. FREIDHEIM, JR.	/S/    MICHAEL H. SUTTON
(Cyrus F. Freidheim, Jr.)	(Michael H. Sutton)
/S/    JULIA L. JOHNSON
(Julia L. Johnson)

251

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Monongahela Power Company, an Ohio corporation, do hereby constitute and appoint PAUL J. EVANSON and PHILIP L. GOULDING, and each of them, a true and lawful attorney in his name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2006, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said companies, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

Dated: February 27, 2007

/S/    PAUL J. EVANSON        

(Paul J. Evanson)

/S/    PHILIP L. GOULDING        

(Philip L. Goulding)

/S/    DAVID E. FLITMAN        

(David E. Flitman)

252

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Generating Company, a Virginia corporation, do hereby constitute and appoint PAUL J. EVANSON and PHILIP L. GOULDING, and each of them, a true and lawful attorney in his name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2006, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.

Dated: February 27, 2007

/S/    PAUL J. EVANSON        

(Paul J. Evanson)

/S/    PHILIP L. GOULDING        

(Philip L. Goulding)

/S/    DAVID E. FLITMAN        

(David E. Flitman)

253

E-1

EXHIBIT INDEX

(Rule 601(a))

Allegheny Energy, Inc.

	Documents	Incorporation by Reference
3.1	Charter of the Company, as amended, September 16, 1997	Form 10-K of the Company (1-267), December 31, 1997, exh. 3.1
3.1a	Articles Supplementary, dated July 15, 1999 and filed July 20, 1999	Form 8-K of the Company (1-267), July 20, 1999, exh. 3.1
3.1b	Articles of Amendment, dated March 18, 2003	Form 10-K of the Company (1-267), December 31, 2002, exh. 3.1c
3.1c	Articles Supplementary to Articles of Incorporation, dated July 19, 2004	Form 10-Q of the Company (1-267), June 30, 2004, exh. 3.1
3.2	Amended & Restated By-laws of the Company, as adopted December 7, 2006	Form 8-K of the Company (1-267), filed December 13, 2006, 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	Executive Compensation Plan	Form 10-K of the Company (1-267), December 31, 1996, exh. 10.2
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	Executive Life Insurance Program and Collateral Assignment Agreement	Form 10-K of the Company (1-267), December 31, 1994, exh. 10.5
10.5	Restricted Stock Plan for Outside Directors	Form 10-K of the Company (1-267), December 31, 1998, exh. 10.7
10.6	Deferred Stock Unit Plan for Outside Directors	Form 10-K of the Company (1-267), December 31, 1997, exh. 10.8
10.7	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
10.8	Allegheny Energy, Inc. Annual Incentive Plan	Schedule 14A Definitive Proxy Statement of the Company (1-267), filed April 4, 2004, Annex B
10.9	Form of Stock Option Agreement	Form 10-K of the Company (1-267), December 31, 2004 exh. 10.12
10.10	Stock Unit Plan	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.13
10.11	Form of Stock Unit Agreement	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.14
10.12	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
10.13	Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-267), December 31, 2002, exh. 10.13
10.14	Employment Contract of Vice President	Form 10-K of the Company (1-267), December 31, 2002, exh. 10.16
10.15	Employment Contract of Vice President	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.15
10.16	Amendment to Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.17
10.17	Amendment to Employment Contract of Vice President	Form 10-K of the Company (1-267), December 31, 2003, exh. 10.20

E-1 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Allegheny Energy, Inc.

	Documents	Incorporation by Reference
10.18	Employment Agreement of Vice President and Controller	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.25
10.19	Employment Agreement of Vice President	Form 10-K of the Company (1-267), December 31, 2004, exh. 10.27
10.20	Indenture, dated as of July 26, 2000, between Allegheny Energy, Inc. and Banc One Trust Company, N.A., as Trustee	Form 8-K of the Company (1-267), filed August 17, 2000, exh. 4.1
10.21	Registration Rights Agreement, dated July 24, 2003, by and among Allegheny Energy, Inc., Allegheny Capital Trust I, Perry Principals, LLC, and additional Purchasers	Form 8-K of the Company (1-267), filed August 1, 2003, exh. 4.1
10.22	Indenture, dated as of July 24, 2003, between Allegheny Energy, Inc. and Wilmington Trust Company, as Trustee	Form 8-K of the Company (1-267), filed August 1, 2003, exh. 4.2
10.23	Amended and Restated Declaration of Trust of Allegheny Capital Trust I among Allegheny Energy, Inc., Wilmington Trust Company, and The Regular Trustees Named Herein	Form 8-K of the Company (1-267), filed August 1, 2003, exh. 4.3
10.24	Stock Purchase and ICPA Assignment Agreement, dated as of May 17, 2004, between Allegheny Energy Inc., Allegheny Energy Supply Company, LLC and Buckeye Power Generating, LLC	Form 10-Q of the Company (1-267), September 30, 2004, exh. 10.3
10.25	Registration Rights Agreement, dated as of October 5, 2004	Form 8-K of the Company (1-267), filed October 8, 2004, exh. 10.1
10.26	Supplemental Indenture, dated as of April 22, 2005, between Allegheny Energy, Inc. and Wilmington Trust Company.	Form 8-K of the Company (1-267), filed April 26, 2005, exh. 4.1
10.27	Employment Agreement of Vice President, Human Resources	Form 8-K of the Company (1-267), filed January 6, 2006, exh. 10.1
10.28	Employment Agreement of Vice President	Form 8-K of the Company (1-267), filed January 6, 2006, exh. 10.3
10.29	$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
10.30	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
10.31	$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

E-1 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Allegheny Energy, Inc.

	Documents	Incorporation by Reference
10.32	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
10.33	Amendment to Employment Contract of Chief Operating Officer—Generation	Form 8-K of the Company (1-267), filed July 19, 2006, exh. 10.2
10.34	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
10.35	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), June 30, 2006, exh. 10.1
10.36	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), June 30, 2006, exh. 10.2
10.37	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
10.38	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
10.39	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
10.40	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 250 herein.
24	Powers of Attorney	See page 251 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

E-1 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Allegheny Energy, Inc.

	Documents	Incorporation by Reference
	Name of Company	State of Organization
99.1	Committee of Chief Risk Officers Organizational Independence and Governance Working Group White Paper, dated November 19, 2002	Form 10-K of the Company (1-267), December 31, 2002, exh. 99.1

* Confidential treatment has been requested from the commission for portions of this document.

E-2

EXHIBIT INDEX

(Rule 601(a))

Monongahela Power Company

	Documents	Incorporation by Reference
3.1	Charter of the Company, as amended	Form 10-Q of the Company (1-5164), September 1995, exh. (a)(3)(i)
3.1(a)	Certificate of Amendment to Charter, effective November 16, 2005	Form 10-K of the Company (1-5164), December 31, 2005, exh. 3.1(a)
3.2	Code of Regulations, as amended April 14, 2003	Form 10-K of the Company (1-5164), December 31, 2002, exh. 3.2
4.1	Indenture, dated as of August 1, 1945, and certain Supplemental Indentures of the Company defining rights of security holders*	S 2-5819, exh. 7(f) S 2-8881, exh. 7(b) S 2-10548, exh. 4(b) S 2-14763, exh. 2(b)(i); Form 8-K of the Company (1-5164), dated May 23, 1995, exh. 4(a); Amendment No. 1 to Form S-4, dated January 19, 2005, exh. 4.3; Form 8-K of the Company (1-5164), filed October 20, 2005, exh. 99.1; Form 8-K of the Company (1-5164), dated September 27, 2006, exh. 99.1
4.2	Indenture, dated as of May 15, 1995, between Monongahela Power Company and The Bank of New York, as Trustee	Form 8-K of the Company, filed June 21, 1995, exh. 4(a)
10.1	Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-5164), December 31, 2002, exh. 10.3
10.2	Amendment to Employment Contract of Chief Executive Officer	Form 10-K of the Company (1-5164), December 31, 2003, exh. 10.8
10.3	Employment Agreement of Vice President and Controller	Form 10-K of the Company (1-5164), December 31, 2004, exh. 10.13
10.4	Employment Agreement of Vice President	Form 10-K of the Company (1-5164), December 31, 2004, exh. 10.15
10.5	Registration Rights Agreement, made and entered into as of June 9, 2004, by Monongahela Power Company, and Citigroup Global Markets Inc. and Scotia Capital (USA) Inc., as representatives of the Initial Purchasers	Form S-4, dated January 19, 2005, exh. 4.3
10.6	Master Asset Swap Agreement dated as of December 31, 2006, by and between Monongahela Power Company and Allegheny Energy Supply Company, LLC	Filed herewith
10.7	Employment Agreement of Vice President, Human Resources	Form 8-K of AE, filed January 6, 2006, exh. 10.1
10.8	Amendment to Employment Contract of Vice President	Form 8-K of AE (1-267), filed July 19, 2006, exh. 10.1
10.9	Letter Agreement, dated August 3, 2006, between Allegheny Energy Service Corporation and President	Form 10-Q of AE (1-267), June 30, 2006, exh. 10.3
10.10	Change in Control Agreement, dated October 18, 2006, between Allegheny Energy Service Corporation and Vice President and General Counsel	Form 8-K of AE (1-267), filed October 24, 2006, exh. 10.1
10.11	Letter Agreement, dated October 18, 2006, between Allegheny Energy Service Corporation and Vice President and General Counsel	Form 8-K of AE (1-267), filed October 24, 2006, exh. 10.2

E-2 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Monongahela Power Company

	Documents	Incorporation by Reference
12	Computation of ratio of earnings to fixed charges	Filed herewith
21	Subsidiaries of Monongahela
	Name of Company	State of Organization
	Allegheny Energy OVEC Supply Company, LLC—100%	Delaware
	Mon Power Renaissance, LLC—100%	Delaware
	MP Renaissance Funding, LLC—100%	Delaware
	Allegheny Generating Company—41.2325%	Virginia
	Allegheny Pittsburgh Coal Company—25%	Pennsylvania
23	Consent of Independent Registered Public Accounting Firm	See page 250 herein.
24	Powers of Attorney	See page 252 herein.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Committee of Chief Risk Officers Organizational Independence and Governance Working Group White Paper, dated November 19, 2002	Form 10-K of the Company (1-5164), December 31, 2002, exh. 99.1

* There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the SEC on its request with copies of such Supplemental Indentures.

E-3

EXHIBIT INDEX

(Rule 601(a))

Allegheny Generating Company

	Documents	Incorporation by Reference
3.1(a)	Charter of the Company, as amended*
3.1(b)	Certificate of Amendment to Charter, effective July 14, 1989**
3.2	By-laws of the Company, as amended February 7, 2005	Form 10-Q of the Company (0-14688), March 31, 2005, exh. 3.1
4	Indenture, dated as of December 1, 1986, and Supplemental Indenture, dated as of December 15, 1988, of the Company defining rights of security holders***
10.1	APS Power Agreement-Bath County Pumped Storage Project, as amended, dated as of August 14, 1981, among Monongahela Power Company, Allegheny Energy Supply Company, LLC, The Potomac Edison Company and Allegheny Generating Company****
10.2	Amendment No. 8, effective date January 1, 1999, to the APS Power Agreement-Bath County Pumped Storage Project	Form 10-K of the Company (0-14688), December 31, 1998
10.3	Operating Agreement, dated as of June 17, 1981, among Virginia Electric and Power Company, Allegheny Generating Company, Monongahela Power Company, Allegheny Energy Supply Company, LLC and The Potomac Edison Company****
10.4	Equity Agreement, dated June 17, 1981, between and among Allegheny Generating Company, Monongahela Power Company, Allegheny Energy Supply Company, LLC, and The Potomac Edison Company****
10.5	United States of America Before The Federal Energy Regulatory Commission, Allegheny Generating Company, Docket No. ER84-504-000, Settlement Agreement effective October 1, 1985****
10.6	Employment Contract of Chief Executive Officer	Form 10-K of AE (1-267), December 31, 2002, exh. 10.13
10.7	Employment Contract of Vice President	Form 10-K of AE (1-267), December 31, 2002, exh. 10.16
10.8	Amendment to Employment Contract of Chief Executive Officer	Form 10-K of the Company, December 31, 2003, exh. 10.10
10.9	Employment Agreement of Vice President and Controller	Form 10-K of the Company (0-14688), December 31, 2004, exh. 10.13
10.10	Employment Agreement of Vice President	Form 10-K of the Company (0-14688), December 31, 2004, exh. 10.15
10.11	Employment Agreement of Vice President, Human Resources	Form 8-K of AE filed January 6, 2006, exh. 10.1
10.12	Employment Agreement of Vice President	Form 8-K of AE, filed January 6, 2006, exh. 10.2
10.13	Amendment to Employment Contract of Vice President	Form 8-K of AE (1-267), filed July 19, 2006, exh. 10.1

E-3 (cont’d.)

EXHIBIT INDEX

(Rule 601(a))

Allegheny Generating Company

	Documents	Incorporation by Reference
10.14	Change in Control Agreement, dated October 18, 2006, between Allegheny Energy Service Corporation and Vice President and Secretary	Form 8-K of AE (1-267), filed October 24, 2006, exh. 10.1
10.15	Letter Agreement, dated October 18, 2006, between Allegheny Energy Service Corporation and Vice President and Secretary	Form 8-K of AE (1-267), filed October 24, 2006, exh. 10.2
12	Computation of ratio of earnings to fixed charges	Filed herewith
24	Powers of Attorney	See page 253 herein.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934	Filed herewith
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Committee of Chief Risk Officers Organizational Independence and Governance Working Group White Paper, dated November 19, 2002	Form 10-K of the Company (0-14688), December 31, 2002 exh. 99.1

* Incorporated by reference to the designated exhibit to AGC’s registration statement on Form 10, File No. 0-14688.

** Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a).

*** Incorporated by reference to Forms 8-K of the Company (0-14688) for December 1986, exh. 4(A), and December 1988, exh. 4.1.

**** Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a).

EX-12

EXHIBIT 12

ALLEGHENY GENERATING COMPANY

COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES

	Years Ended December 31,
($ in thousands)	2006		2005		2004		2003		2002
Earnings:
Income from continuing operations	$	24,769	$	31,121	$	27,392	$	20,827	$	18,599
Exclude amounts reflected in line above:
Income tax expense		8,677		3,562		7,324		11,989		7,525
Add fixed charges (see below)		7,188		7,395		8,455		12,447		12,264
Total Earnings (as defined)	$	40,634	$	42,078	$	43,171	$	45,263	$	38,388
Fixed charges:
Interest expensed and capitalized	$	7,188	$	7,395	$	8,455	$	12,447	$	12,264
Total Fixed Charges (as defined)	$	7,188	$	7,395	$	8,455	$	12,447	$	12,264
Ratio of Earnings to Fixed Charges		5.65x		5.69x		5.11x		3.64x		3.13x

EX-31.1

Exhibit 31.1

CERTIFICATION

I, PAUL J. EVANSON, certify that:

1. I have reviewed this annual report on Form 10-K of ALLEGHENY GENERATING COMPANY.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ Paul J. Evanson
	Paul J. Evanson
Date: February 27, 2007	Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, PHILIP L. GOULDING, certify that:

1. I have reviewed this annual report on Form 10-K of ALLEGHENY GENERATING COMPANY.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ Philip L. Goulding
	Philip L. Goulding
Date: February 27, 2007	Principal Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION

Pursuant to 18 U.S.C. § 1350, the undersigned officer of ALLEGHENY GENERATING COMPANY (the “Company”), hereby certifies, to such officer’s knowledge, that the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Paul J. Evanson
	Paul J. Evanson
February 27, 2007	Principal Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION

Pursuant to 18 U.S.C. § 1350, the undersigned officer of ALLEGHENY GENERATING COMPANY (the “Company”), hereby certifies, to such officer’s knowledge, that the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Philip L. Goulding
	Philip L. Goulding
February 27, 2007	Principal Financial Officer