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Allegheny Energy 10-K 2005
Form 10-K
Table of Contents

 

LOGO

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 


 

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

 

  x   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) of the SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004

 

OR

 

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

 

Commission

File Number


  

Registrant;

State of Incorporation;

Address; and Telephone Number


 

I.R.S. Employer

Identification Number


1-267

   ALLEGHENY ENERGY, INC.   13-5531602
     (A Maryland Corporation)    
     800 Cabin Hill Drive    
     Greensburg, Pennsylvania 15601    
     Telephone (724) 837-3000    

1-5164

   MONONGAHELA POWER COMPANY   13-5229392
     (An Ohio Corporation)    
     1310 Fairmont Avenue    
     Fairmont, West Virginia 26554    
     Telephone (304) 366-3000    

1-3376-2

   THE POTOMAC EDISON COMPANY   13-5323955
     (A Maryland and Virginia Corporation)    
     800 Cabin Hill Drive    
     Greensburg, Pennsylvania 15601    
     Telephone (724) 837-3000    

0-14688

   ALLEGHENY GENERATING COMPANY   13-3079675
     (A Virginia Corporation)    
     800 Cabin Hill Drive    
     Greensburg, Pennsylvania 15601    
     Telephone (724) 837-3000    


Table of Contents

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 an accelerated filer (as defined in Rule 12b-2 of the Act).

 

Allegheny Energy, Inc.

   Yes   x    No   ¨

Monongahela Power Company

   Yes   ¨    No   x

The Potomac Edison Company

   Yes   ¨    No   x

Allegheny Generating Company

   Yes   ¨    No   x

 

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

 

Registrant


 

Title of each class


 

Name of each exchange

on which registered


Allegheny Energy, Inc.

 

Common Stock,
$1.25 par value

 

New York Stock Exchange Chicago Stock Exchange

Pacific Stock Exchange

Monongahela Power Company

 

Cumulative Preferred Stock,
$100 par value:
4.40 %
4.50 %, Series C

  American Stock Exchange American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:    

Allegheny Generating Company

 

Common Stock,
$1.00 par value

  None

 


    

Aggregate market value of

voting and non-voting common

equity held by nonaffiliates of

the registrants at June 30, 2004

  

Number of shares of common stock

of the registrants outstanding at

March 7, 2005

Allegheny Energy, Inc.

   $1,953,831,404    137,474,924 ($1.25 par value)

Monongahela Power Company

   None (a)    5,891,000 ($50 par value)

The Potomac Edison Company

   None (a)    22,385,000 ($.01 par value)

Allegheny Generating Company

   None (b)    1,000 ($1.00 par value)

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

 

Documents Incorporated by Reference

 

Portions of the Allegheny Energy, Inc. definitive Proxy Statement for its 2005 Annual Meeting of Stockholders are incorporated by reference to Part III of this Annual Report on Form 10-K.

 



Table of Contents

GLOSSARY

 

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

 

ACC

   Allegheny Communications Connect, Inc., a subsidiary of Allegheny Ventures

AE

   Allegheny Energy, Inc., a diversified utility holding company

AESC

   Allegheny Energy Service Corporation, a wholly owned subsidiary of AE

AE 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

MGS

   Mountaineer Gas Services, Inc., a regulated subsidiary of Mountaineer

Monongahela

   Monongahela Power Company, a regulated subsidiary of AE

Mountaineer

   Mountaineer Gas Company, a regulated subsidiary of Monongahela

Potomac Edison

   The Potomac Edison Company, a regulated subsidiary of AE

West Penn

   West Penn Power Company, a regulated subsidiary of AE

WVP

   West Virginia Power, a division of Monongahela

 

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

 

Bcf

   Billion cubic feet

CDWR

   California Department of Water Resources

Clean Air Act

   Clean Air Act of 1970

CWA

   Clean Water Act

EPA

   United States Environmental Protection Agency

Exchange Act

   Securities Exchange Act of 1934, as amended

FERC

   Federal Energy Regulatory Commission, an independent commission within the U. S. Department of Energy

GAAP

   Generally accepted accounting principles used in the United States of America

kW

   Kilowatt, which is equal to 1,000 watts

kWh

   Kilowatt-hour, which is a unit of electric energy equivalent to one kilowatt operating for one hour

Maryland PSC

   Maryland Public Service Commission

Mmcf

   Million cubic feet

MW

   Megawatt, which is equal to 1,000,000 watts

MWh

   Megawatt-hour, which is a unit of electric energy equivalent to one megawatt operating for one hour

NSR

   The New Source Performance Review Standards, or “New Source Review,” applicable to facilities deemed “new” sources of emissions by the EPA

OVEC

   Ohio Valley Electric Corporation

Pennsylvania PUC

   Pennsylvania Public Utility Commission

PJM

   PJM Interconnection, L.L.C., a regional transmission organization

PLR

   Provider-of-last-resort

PUCO

   Public Utilities Commission of Ohio

PUHCA

   Public Utility Holding Company Act of 1935, as amended

PURPA

   Public Utility Regulatory Policies Act of 1978

RTO

   Regional Transmission Organization

SEC

   Securities and Exchange Commission

SERP

   Supplemental Executive Retirement Plan

T&D

   Transmission and Distribution

Virginia SCC

   Virginia State Corporate Commission

West Virginia PSC

   Public Service Commission of West Virginia


Table of Contents

 

LOGO


Table of Contents

CONTENTS

 

Item 1.

  

Business

   1
    

Overview

   1
    

Where You Can Find More Information

   5
    

Special Note Regarding Forward-Looking Statements

   6
    

Risk Factors

   7
    

Allegheny’s Sales and Revenues

   15
    

Capital Expenditures

   17
    

Electric Facilities

   18
    

Allegheny Map

   21
    

Fuel, Power and Resource Supply

   23
    

Regulatory Framework Affecting Allegheny

   27
    

Federal Regulation and Rate Matters

   27
    

State Legislation, Rate Matters and Regulatory Developments

   29
    

Employees

   34
    

Environmental Matters

   35
    

Research and Development

   38

Item 2.

  

Properties

   39

Item 3.

  

Legal Proceedings

   40

Item 4.

  

Submission of Matters to a Vote of Security Holders

   44

Item 5.

  

Market for the Registrants’ Common Equity and Related Stockholder Matters

   45

Item 6.

  

Selected Financial Data

   46
    

Allegheny Energy, Inc. and Subsidiaries

   47
    

Monongahela Power Company and Subsidiaries

   48
    

The Potomac Edison Company and Subsidiaries

   48
    

Allegheny Generating Company

   49

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   50
    

Executive Summary

   51
    

Overview

   51
    

Key Indicators and Performance Factors

   54
    

Primary Factors Affecting Allegheny’s Performance

   56
    

Results of Operation

   60
    

Allegheny Energy, Inc. and Subsidiaries

   60
    

Monongahela Power Company and Subsidiaries

   76
    

The Potomac Edison Company and Subsidiaries

   85
    

Allegheny Generating Company

   89
    

Financial Condition, Requirements and Resources

   91
    

Liquidity and Capital Requirements

   91
    

2004 Asset Sales

   94
    

2003 Asset Sales

   95
    

Anticipated Asset Sales

   95
    

Terminated Trading Payments

   95
    

Dividends

   95
    

Other Matters Concerning Liquidity and Capital Requirements

   95
    

Cash Flows

   99
    

Financing

   103
    

Change in Credit Ratings

   103
    

Derivative Instruments and Hedging Activities

   105
    

New Accounting Standards

   106

Item 7a.

  

Quantitative and Qualitative Disclosure About Market Risk

   108

 

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Table of Contents

CONTENTS (cont’d)

 

Item 8.

  

Financial Statements and Supplementary Data

   112
    

Allegheny Energy, Inc. and Subsidiaries

   113
    

Report of Independent Registered Public Accounting Firm

   180
    

Monongahela Power Company and Subsidiaries

   182
    

Report of Independent Registered Public Accounting Firm

   217
    

The Potomac Edison Company and Subsidiaries

   218
    

Report of Independent Registered Public Accounting Firm

   240
    

Allegheny Generating Company

   241
    

Report of Independent Registered Public Accounting Firm

   257
    

Schedule I AE (Parent Company) Condensed Financial Statements

   258
    

Schedule II Valuation and Qualifying Accounts

   260

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   263

Item 9a.

  

Controls and Procedures

   263

Item 9b.

  

Other Information

   264

Item 10.

  

Directors and Executive Officers of the Registrants

   265

Item 11.

  

Executive Compensation

   269

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   280

Item 13.

  

Certain Relationships and Related Transactions

   281

Item 14.

  

Principal Accountant Fees and Services

   281

Item 15.

  

Exhibits, Financial Statement Schedules, and Reports on Form 8-K

   282

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

   282

Signatures

   283

 

ii


Table of Contents

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

 

PART I

 

ITEM 1.    BUSINESS

 

Overview

 

Allegheny is an integrated energy business that owns and operates electric generation facilities and delivers electric and natural gas services to customers in Pennsylvania, West Virginia, Maryland, Virginia and Ohio. AE, Allegheny’s parent holding company, was incorporated in Maryland in 1925 and is registered as a holding company under PUHCA. 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 and natural gas 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. The Distribution Companies’ principal businesses are the operation of electric and natural gas public utility systems.

 

    Monongahela was incorporated in Ohio in 1924. It conducts an electric T&D business that serves approximately 400,000 electric customers in northern West Virginia and an adjacent portion of Ohio. Monongahela also conducts a natural gas T&D business, primarily through Mountaineer. Monongahela serves approximately 226,000 residential, commercial, industrial and wholesale natural gas customers in West Virginia and owns approximately 4,878 miles of natural gas distribution pipelines. During 2004, Monongahela sold or transported 62.1 Bcf of natural gas. Monongahela’s electric and natural gas service area covers approximately 14,000 square miles with a population of approximately 1,224,000. Monongahela’s Delivery and Services segment had operating revenues of $669.0 million in 2004. In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia, including Mountaineer, subject to certain conditions. The sale is expected to be completed in mid- to late-2005. Monongahela also has generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” 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 442,000 electric customers in a service area of about 7,300 square miles with a population of approximately 987,000. Potomac Edison’s 2004 total operating revenues were $924.4 million. One customer, Eastalco Aluminum Company, accounted for 12.9% and 10.5% of Potomac Edison’s 2004 and 2003 operating revenues, respectively.

 

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    West Penn was incorporated in Pennsylvania in 1916. It operates an electric T&D system in southwestern, north and south-central Pennsylvania. West Penn serves approximately 698,000 customers in a service area of about 9,900 square miles with a population of approximately 1,508,000. West Penn’s 2004 total operating revenues were $1,165.9 million.

 

The Distribution Companies assess delivery charges when other power suppliers transmit power along the Distribution Companies’ transmission grids. In April 2002, the Distribution Companies transferred operational control over their transmission systems to PJM. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.

 

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

 

During 2004, the Delivery and Services segment had operating revenues of $2,764.1 million and net income of $103.3 million. At December 31, 2004, the Delivery and Services segment held $4.4 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “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 and a registered holding company under PUHCA. AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities, although it no longer engages in speculative trading. As of December 31, 2004. AE Supply owned or contractually controlled 8,728 MW of generation capacity. AE Supply markets the Generation and Marketing segment’s electric generation capacity to various customers and markets. Currently, the majority of the Generation and Marketing segment’s normal operating capacity is committed to supplying the PLR and other obligations of the Distribution Companies. AE Supply’s 2004 total operating revenues were $1,270.3 million.

 

    Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment. As of December 31, 2004, Monongahela owned or contractually controlled 2,123 MWs of generation capacity. Monongahela’s Generation and Marketing segment had operating revenues of $312.8 million in 2004.

 

    AGC was incorporated in Virginia in 1981. AGC is owned approximately 77% by AE Supply and approximately 23% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric station and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 985 MW share of generation capacity from the Bath County generation station to AE Supply and Monongahela. AGC’s 2004 total operating revenues were $69.2 million.

 

AE Supply is obligated under long-term contracts to provide the Distribution Companies with the power that they need to meet a majority of their PLR obligations. The Generation and Marketing segment sells power into PJM and purchases power from PJM to meet its obligations to the Distribution Companies under these contracts. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.

 

Although most of the Generation and Marketing segment’s generation capacity participates in the PJM system, it owns generation capacity outside of PJM, including AGC’s interest in the Bath County generation station and generation facilities in Gleason, Tennessee and Wheatland, Indiana. The Gleason and Wheatland generation facilities have been classified as held for sale, and their results have been presented as discontinued operations in the accompanying Consolidated Statements of Operations.

 

2


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During 2004, the Generation and Marketing segment had operating revenues of $1,538.7 million and a net loss of $413.9 million. At December 31, 2004, the Generation and Marketing segment held $4.4 billion of identifiable assets. See “Managements Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “Business Segments,” to the Consolidated Financial Statements.

 

Intersegment Services

 

AESC was incorporated in Maryland in 1963 as a service company for AE. AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures and their respective subsidiaries have no employees. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had approximately 5,100 employees as of December 31, 2004.

 

The PJM Market and the Distribution Companies’ PLR Obligations

 

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.

 

The Distribution Companies have PLR obligations to their customers in Pennsylvania, Maryland, Virginia and Ohio. AE Supply has long-term contracts with the Distribution Companies under which AE Supply provides the Distribution Companies with the majority of the power necessary to meet their PLR obligations. A majority of Allegheny’s generation assets participate in the PJM system, and most of the power that the Generation and Marketing segment generates is sold into PJM. Allegheny expects to sell power in excess of the Distribution Companies’ PLR obligations at market prices. Prevailing market prices are generally higher than the capped rates currently applicable to these PLR obligations.

 

For a more detailed discussion, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview.”

 

Challenges and Response

 

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

 

Beginning in 2002, difficult market conditions, changes in the regulatory environment and Allegheny’s worsening credit profile placed Allegheny in a weakened financial position, which continued during 2003 and into 2004. Beginning in 2003, Allegheny’s new senior management implemented recovery plans and new long-term strategies.

 

3


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Allegheny’s long-term strategy is to focus on its core generation and T&D businesses. Allegheny’s management believes that this emphasis will enable Allegheny to take advantage of its regional presence, operational expertise and knowledge of its markets. Specific goals for enhancing long-term value include:

 

    Restoring Financial Strength.  Beginning in 2003, Allegheny significantly improved its liquidity and overall financial strength. Allegheny’s management believes that it can continue this trend by:

 

    Focusing on the Core Business.  Allegheny has reoriented its business to focus on its core businesses and assets. In 2003, Allegheny exited its speculative trading activities in the Western U. S. and other energy markets. In addition, Allegheny has sold or is seeking to sell non-core assets.

 

    Substantially Reducing and Proactively Managing Debt.  Between December 1, 2003 and January 31, 2005, Allegheny repaid approximately $1.2 billion of debt. Allegheny’s goal is to reduce its debt by an additional $300 million by the end of 2005. Allegheny intends to continue its debt reduction efforts by applying some of its cash flow from operations and the proceeds from asset sales to the repayment of debt. The extent to which Allegheny utilizes these alternatives will depend upon the terms that are available to it and their impact on its financial condition, long-term value and overall strategy.

 

    Improving Liquidity.  Allegheny is improving its liquidity through prudent cash management, opportunistic sales of non-core assets, cutting costs and expenses, extending debt maturities and obtaining a revolving credit facility. For example, in December 2004, AE Supply completed the sale of its 672 MW natural gas-fired Lincoln Generating Facility, located in Manhattan, Illinois and an accompanying tolling agreement for $175.0 million in cash, subject to certain post-closing adjustments. Also in December 2004, AE sold a portion of its interest in OVEC for $102 million in cash, $96 million of which was received at the closing of the transaction and the remaining $6 million of which is expected to be paid after March 13, 2006, upon the satisfaction of certain conditions. The proceeds of these transactions were used to repay debt. AE and AE Supply also completed refinancings in 2004 that extended the maturities and lowered the interest rates of much of their debt and established a revolving credit facility for AE.

 

    Maximizing Operational Efficiency.  Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation plants. In addition, Allegheny is seeking to optimize operations and maintenance costs for its generation facilities and T&D assets and related corporate functions, to reduce costs and to pursue other productivity improvements necessary to build a high-performance organization.

 

    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-based rates for AE Supply and its subsidiaries.

 

    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.

 

    Rebuilding the Management Team.  Allegheny rebuilt its management team in 2003 and 2004.

 

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Where You Can Find More Information

 

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

 

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

 

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

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

 

    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;

 

    regulatory matters; and

 

    accounting issues.

 

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

 

Factors that could cause actual results to differ materially include, among others, the following:

 

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

 

    general economic and business conditions;

 

    changes in access to capital markets;

 

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

 

    environmental regulations;

 

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

 

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

 

    changes in the weather and other natural phenomena;

 

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

 

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

 

    the loss of any significant customers or suppliers;

 

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

 

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

 

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

 

    the continuing effects of global instability, terrorism and war.

 

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Table of Contents

RISK FACTORS

 

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

 

Risks Relating to Regulation

 

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

 

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

 

Allegheny is also subject to regulation by the SEC under PUHCA, which imposes a number of restrictions on the operations of registered utility holding companies and their subsidiaries. These restrictions include a requirement that, subject to a number of exceptions, the SEC approve in advance securities issuances, financings, acquisitions and dispositions of utility assets, or of securities of utility companies, and acquisitions by utility companies of other businesses. With limited exceptions, PUHCA requires that transactions between affiliated companies in a registered holding company system be performed at cost.

 

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

 

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

 

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

 

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

 

Applicable standards under the EPA’s NSR initiatives remain in flux. Under the Clean Air Act, modification of Allegheny’s generation facilities in a manner that causes increased emissions could subject Allegheny’s

 

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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.

 

On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue from the Attorneys General of Connecticut, New Jersey and New York and the Pennsylvania Department of Environmental Protection (“PADEP”) alleging that they made major modifications to some of their coal-fired generation facilities in West Virginia and Pennsylvania in violation of the Prevention of Significant Deterioration provisions of the Clean Air Act. 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.

 

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 on January 6, 2005. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired power plants in West Virginia and Pennsylvania are in compliance with the Clean Air Act. The Attorneys General have filed a motion to dismiss the declaratory judgment action. If the action is dismissed based upon their motion, the Attorneys General may file an enforcement action against Allegheny in federal court in Pennsylvania. It is also possible that the EPA and other state authorities may join in the current declaratory judgment action or, if it is dismissed, a new action filed by the Attorneys General.

 

In December 2004, Pennsylvania adopted Renewable Portfolio Standard legislation. The new legislation requires that, by 2020, 18% of the energy used in Pennsylvania be derived from renewable and alternative sources. The new legislation includes a five-year exemption from this requirement for companies, such as the Distribution Companies, that are operating within transition periods under the current regulations governing the transition to market competition in Pennsylvania. The full requirement will apply to those companies when the applicable transition periods end. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative energy sources are not reasonably available. Similar legislation has been adopted in Maryland. The Maryland law goes into effect on the later of the termination of the applicable transition period or July 1, 2006. See “Regulatory Framework Affecting Allegheny” below.

 

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 or subjected to additional costs.

 

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

 

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

 

Allegheny’s operations are subject to evolving regulatory policies, including initiatives regarding deregulation of the production and sale of electricity and the restructuring of transmission regulation. State or federal regulators may also take regulatory action as a result of the power outages that affected the Northeast and Midwest United States and Canada in August 2003. Any new requirements arising from these actions could lead to increased operating expenses and capital expenditures, the amount of which cannot be predicted at this time.

 

The continuation of below-market retail rate caps beyond the original scheduled end of transition periods could have adverse consequences for Allegheny. In the absence of a long-term power supply contract with a power generator, the Distribution Companies must purchase their power requirements at negotiated or market prices, whether from AE Supply or an alternative supplier. If retail rates are capped below the prices at which the Distribution Companies can obtain power, the power will be sold at a loss. Legislators, regulators and consumer and other groups have sought to extend retail rate regulation in the states in which the Distribution Companies do

 

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business through a variety of mechanisms, including through the extension of the current rate cap regimes, which are set below current market prices. Allegheny cannot predict to what extent these efforts will be successful. See “Regulatory Framework Affecting Allegheny” below.

 

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

 

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

 

Risks Related to Allegheny’s Substantial Debt

 

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

 

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

 

    borrow funds;

 

    incur liens and guarantee debt;

 

    enter into a merger or other change of control transaction;

 

    make investments;

 

    prepay debt;

 

    amend contracts; 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 substantial debt could adversely affect its ability to operate successfully and meet contractual obligations.

 

Allegheny is substantially leveraged. One of its principal challenges is to manage its debt while continuing the long-term process of reducing the amount of its debt. At December 31, 2004, Allegheny had $5.0 billion of debt on a consolidated basis (including discontinued operations). Approximately $700 million of that amount represented AE’s obligations, $2.8 billion represented debt of AE Supply and AGC and the remainder constituted debt of one or more of the Distribution Companies.

 

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

 

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

 

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

 

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

 

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

 

    limit Allegheny’s ability to borrow additional funds; and

 

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

 

Allegheny may be unable to engage in desired financing transactions.

 

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

 

    its equity ratios, which are below the minimum levels required under its PUHCA financing authorizations;

 

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

 

    its overall financial condition and results of its operations; and

 

    volatility in the capital markets.

 

Allegheny currently anticipates that, in order to repay the principal of its outstanding debt, it may undertake one or more financing alternatives, such as refinancing or restructuring its debt, selling assets, reducing or delaying capital investments or raising additional capital. Allegheny can make 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.

 

Allegheny’s credit ratings and trading market liquidity may make it difficult for it to hedge its physical power supply commitments and resource requirements.

 

While Allegheny has made significant progress retiring unnecessary positions in the Western U.S. and other energy markets, its current credit ratings, together with a lack of market liquidity have made it difficult for it to retire a small number of remaining energy market positions. Market liquidity has significantly declined over the past three years. Absent a return to more liquid levels combined with an improvement in Allegheny’s credit ratings, it may not be possible for Allegheny to retire these remaining positions.

 

Allegheny’s credit position has also made it difficult for it to hedge its power supply obligations and fuel requirements. In the absence of effective hedges for these purposes, Allegheny must satisfy power shortfalls in the spot markets, which are volatile and can be more costly 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 the future market prices and demand for electricity and other energy-related commodities. Even when Allegheny’s policies and procedures are followed and decisions are made based on these models, its financial position and results of operations may be adversely affected if the judgments and assumptions underlying those models prove to be inaccurate.

 

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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 many 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 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.

 

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

 

Electrical power generation is generally a seasonal business, and weather patterns can have a material impact on Allegheny’s operating performance. 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, which could require it to purchase power at a time when the market price for power is very 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.

 

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 reserves or 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 reserves or insurance 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.

 

The terms of AE Supply’s power sale agreements with the Distribution Companies could require AE Supply to sell power below its costs or prevailing market prices or require the Distribution Companies to purchase power at a price above which they can sell power.

 

In connection with regulations governing the transition to market competition, the Distribution Companies are required to provide electricity at capped rates to retail customers who do not choose an alternate electricity generation supplier or who return to utility service from alternate suppliers. The Distribution Companies satisfy the majority of these obligations by purchasing power from AE Supply under long-term agreements. Those agreements provide for the supply of a significant portion of the Distribution Companies’ energy needs at the

 

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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 with the Distribution Companies.

 

These power supply agreements present risks for both AE Supply and the Distribution Companies. At times, AE Supply may not earn as much as it otherwise could by selling power priced at capped rates to the Distribution Companies instead of into competitive wholesale markets. In addition, AE Supply’s obligations under these power supply agreements could exceed its available generation capacity, which may require AE Supply to buy power at prices that are higher than the sale prices in the power supply agreements. Changes in customer switching behavior could also alter AE Supply’s obligations under these agreements. Conversely, the Distribution Companies’ capped rates may be below current wholesale market prices through the applicable transition periods. As a consequence, the Distribution Companies 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.

 

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 make 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. In addition, the suppliers under these agreements may not be required to supply coal to Allegheny under certain circumstances, such as in the event of a natural disaster. If Allegheny is unable to obtain its coal requirements under these contracts, it may be required to purchase coal at higher prices, which could have a material adverse effect on its financial condition, cash flow and results of operations.

 

Allegheny estimates that it may purchase sulfur dioxide (“SO2”) emission allowances for up to 50,000 tons for 2005 and an average of approximately 100,000 tons per year for 2006 through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced, and the type of fuel used, by its generation facilities. Fluctuations in the availability or cost of emission allowances could have a material adverse effect on Allegheny’s results of operations, cash flows and financial condition.

 

Allegheny is currently involved in significant litigation that, if not decided favorably to Allegheny, could materially adversely affect its results of operations, cash flows and financial condition.

 

Allegheny is currently involved in a number of lawsuits, including lawsuits relating to breach of contract and its involvement in the energy trading business. 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 results of operations, cash flows and financial condition. See “Legal Proceedings.”

 

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

 

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

 

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Allegheny may be required to make significant contributions to satisfy underfunded pension liabilities.

 

Allegheny’s underfunded pension liabilities have increased in recent periods due to declining interest rates and financial market performance and because of the implementation of early retirement initiatives to reduce headcount. Allegheny made a total contribution to pension plans during 2004 of $27.7 million, including $0.3 million to the SERP. Minimum required funding contributions are anticipated to increase beyond 2004. However, these anticipated mandatory contributions will change in the future if Allegheny’s assumptions regarding prevailing interest rates change, if actual investments under-perform or out-perform expectations or if actuarial assumptions or asset valuation methods change.

 

Allegheny also contributed $28.1 million to its postretirement benefits other than pensions in 2004. These costs may increase in 2005.

 

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

 

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

 

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

 

The energy sector has been the subject of highly-publicized allegations of misconduct. Negative publicity of this nature may make legislatures, regulatory authorities and tribunals less likely to view energy companies favorably, which could cause them to make decisions or take actions that are adverse to Allegheny. Power outages, such as those that affected the Northeast and Midwest United States and Canada in August 2003, could exacerbate negative sentiment regarding the energy industry.

 

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

 

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

 

    a recession or an economic slowdown;

 

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

 

    significant increases in the prices for oil or other fuel;

 

    a terrorist attack or threatened attacks;

 

    a significant transmission failure; or

 

    changes in technology.

 

Risks Relating to Internal Controls and Procedures and Operational Enhancements

 

Allegheny’s internal controls and procedures have been substantially deficient, and it continues to expend significant resources to improve internal controls and procedures.

 

In August 2002, Allegheny’s independent registered public accounting firm, PricewaterhouseCoopers LLP (“PwC”), advised Allegheny that it considered AE’s and its subsidiaries’ internal controls to have material

 

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weaknesses. The term “material weakness” refers to an organization’s internal control deficiency in which the design or operation of a component of internal control does not reduce to a relatively low level the risk that a material misstatement may be contained in the organization’s financial statements. In March 2004, PwC advised AE’s Audit Committee that although management had made significant progress in addressing the specific control weaknesses previously identified, not all of these deficiencies had been remedied and certain internal control weaknesses remained. In September 2004, PwC advised AE’s Audit Committee that certain material weaknesses remained and required remediation. As of December 31, 2004, these material weaknesses have been remediated, although some deficiencies remain. Allegheny intends to expend additional resources to further improve its internal controls.

 

Refocusing its business subjects Allegheny to risks and uncertainties.

 

Since late 2002, Allegheny has been reassessing the business environment, its position within the energy industry and its relative strengths and weaknesses. As a result of this reassessment, 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 reduced the size of its workforce and made substantial changes to senior management. Additional changes to Allegheny’s business will be considered as management seeks to strengthen financial and operational performance. These changes may be disruptive to Allegheny’s established organizational culture and systems. In addition, consideration and planning of strategic changes diverts management attention and other resources from day to day operations.

 

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

 

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

 

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

 

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

 

Allegheny has undertaken and expects to continue to undertake cost-savings initiatives. However, Allegheny can make no assurance that it will realize on-going 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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ALLEGHENY’S SALES AND REVENUES

 

The Generation and Marketing Segment’s Sales and Revenues

 

The Generation and Marketing segment had operating revenues of $1,538.7 million and $956.2 million in 2004 and 2003, respectively. For more information regarding the Generation and Marketing segment’s operating revenues, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “Business Segments,” to the Consolidated Financial Statements.

 

The Delivery and Services Segment’s Sales and Revenues

 

The Delivery and Services segment had operating revenues of $2,764.1 million and $2,705.8 million in 2004 and 2003, respectively. These revenues included revenue from electric sales, regulated natural gas sales and unregulated services. The following tables describe the segment’s kWh sales and revenues from electric sales:

 

kWh sales (in millions):


   2004

   2003

   % Change

 

Retail:

                    

Residential

     16,047      15,633    2.6  

Commercial

     10,514      10,171    3.4  

Industrial

     20,539      20,117    2.1  

Streetlighting

     102      102    —    
    

  

      

Subtotal retail

     47,202      46,023    2.6  

Transmission and bulk power

     4,119      5,683    (27.5 )

Wholesale and other

     20      491    (95.9 )
    

  

      

Total

     51,341      52,197    (1.6 )
    

  

      

Revenues (in millions):


   2004

   2003

   % Change

 

Retail:

                    

Residential

   $ 1,109.2    $ 1,078.4    2.9  

Commercial

     615.7      599.0    2.8  

Industrial

     831.7      813.3    2.3  

Streetlighting

     15.0      14.8    1.4  
    

  

      

Subtotal retail

   $ 2,571.6    $ 2,505.5    2.6  

Transmission and bulk power

     127.1      121.8    4.4  

Wholesale and other

     0.7      13.8    (94.9 )

Unregulated services

     40.0      42.6    (6.1 )

Other affiliated and nonaffiliated energy services

     24.7      22.1    11.8  
    

  

      

Total

   $ 2,764.1    $ 2,705.8    2.2  
    

  

      

 

Intersegment Eliminations

 

(in millions):


   2004

    2003

    % Change

Revenues

   $ (1,546.7 )   $ (1,479.7 )   4.5

 

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Revenues from natural gas sales have been reclassified to discontinued operations. These revenues included:

 

     2004

   2003

   % Change

 

Natural gas—Bcf sales:

                    

Residential

     17.6      19.1    (7.9 )

Commercial

     9.4      10.1    (6.9 )

Industrial

     0.2      0.4    (50.0 )

Wholesale

     0.4      0.7    (42.9 )

Transportation and other

     34.5      33.7    2.4  
    

  

      

Total regulated natural gas—Bcf sales

     62.1      64.0    (3.0 )
    

  

      

Natural gas revenues (in millions):

                    

Residential

   $ 194.2    $ 169.0    14.9  

Commercial

     96.4      81.7    18.0  

Industrial

     2.0      3.3    (39.4 )

Wholesale

     3.3      4.6    (28.3 )

Transportation and other

     10.5      10.2    2.9  
    

  

      

Total regulated natural gas revenues

   $ 306.4    $ 268.8    14.0  
    

  

      

 

For more information regarding the Delivery and Services segment’s revenues, see “Management’s Discussion and Analysis of Financial Condition and Operating Results” and Note 12, “Business Segments,” to the Consolidated Financial Statements.

 

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CAPITAL EXPENDITURES

 

The table below shows total capital expenditures for Allegheny in 2004 and estimated capital expenditures for 2005 and 2006, as well as the environmental control expenditures that are included in these capital expenditures or estimated capital expenditures.

 

     2004

   2005

   2006

(In millions)


   (Actual)    (Estimated)

Generation and Marketing:

                    

AE Supply

                    

Total

   $ 82.8    $ 79.5    $ 139.1

Environmental

     21.8      39.9      102.1

Monongahela

                    

Total

     15.1      24.4      34.0

Environmental

     5.4      12.2      27.2

AGC

                    

Total

     9.1      11.7      10.0

Environmental

              
    

  

  

Total Generation and Marketing capital expenditures

   $ 107.0    $ 115.6    $ 183.1
    

  

  

Delivery and Services:

                    

Potomac Edison

                    

Total

   $ 68.2    $ 72.4    $ 75.8

Environmental

     0.6          

West Penn

                    

Total

     51.4      60.0      72.0

Environmental

     0.2          

Monongahela

                    

Total

     39.6      42.2      46.6

Environmental

     0.3          

Allegheny Ventures

                    

Total

     1.3      1.0      1.0

Environmental

              
    

  

  

Total Delivery and Services capital expenditures

   $ 160.5    $ 175.6    $ 195.4
    

  

  

Total capital expenditures

   $ 267.5    $ 291.2    $ 378.5
    

  

  

 

The Delivery and Services segment’s capital expenditures of $160.5 million for 2004 are shown net of $10.8 million in proceeds from the sale of land by WVP.

 

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

 

AE Supply ceased construction of, or planning for, several generation projects in 2002 in response to market conditions, including overcapacity and lower wholesale power prices, and to conserve liquidity. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 7, “Asset Impairments,” to the Consolidated Financial Statements for information regarding charges for discontinued generation projects.

 

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ELECTRIC FACILITIES

 

All of Allegheny’s owned or controlled generation capacity is part of the Generation and Marketing segment and is owned or controlled by AE, AE Supply, Monongahela or AGC. In addition, the Distribution Companies are obligated to purchase 479 MW of power through state utility commission-approved arrangements pursuant to PURPA. This PURPA capacity is part of the Delivery and Services segment. See “PURPA Capacity” below.

 

Allegheny’s owned and controlled capacity as of December 31, 2004 was 10,851 MW, of which 7,819 MW (72.1%) were coal-fired, 1,907 MW (17.6%) were natural gas-fired, 1,043 MW (9.6%) were pumped-storage and hydroelectric and 82 MW (0.7%) were oil-fired. These amounts include capacity to which AE Supply is entitled in conjunction with AE’s sale of a portion of its interest in OVEC.

 

AE holds a 3.5% equity stake in, and is a sponsoring company of, OVEC. Currently, AE Supply and Monongahela are entitled to 9% (203 MW) and 3.5% (78 MW), respectively, of OVEC capacity. OVEC supplies power to its sponsoring companies under an intercompany power agreement that expires on March 12, 2006. In December 2004, AE sold a 9% equity interest in OVEC to Buckeye Power Generating, LLC (“Buckeye”). In addition, AE Supply assigned to Buckeye all of its rights and obligations under a new OVEC intercompany power agreement effective on March 13, 2006. AE Supply retained its rights under the current agreement to 9% of the power from the OVEC electric generation facilities through March 12, 2006.

 

In December 2004, AE Supply sold its subsidiary, Allegheny Energy Supply Lincoln Generating Facility, LLC (“Lincoln”). Lincoln’s assets included the 672 MW natural gas-fired Lincoln Generating Facility located in Manhattan, Illinois. AE Supply is also currently seeking to sell its Gleason Generating Facility in Gleason, Tennessee and its Wheatland Generating Facility in Wheatland, Indiana.

 

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The following table shows the nominal maximum operational generation capacity owned or controlled by Allegheny, as of December 31, 2004. This generation is included in the Generation and Marketing segment.

 

Nominal Maximum Operational Generation Capacity (MW)

 

     Units

  

Project

Total


   Regulated

   Unregulated

  

Service

Commencement

Dates (a)


Stations


         Monongahela

   AE Supply and Other

  

Coal-Fired (Steam):

                        

Harrison (Haywood, WV)

   3    1,961    417    1,544    1972-74

Hatfield’s Ferry (Masontown, PA)

   3    1,710    400    1,310    1969-71

Pleasants (Willow Island, WV)

   2    1,300    277    1,023    1979-80

Fort Martin (Maidsville, WV)

   2    1,107    212    895    1967-68

Armstrong (Adrian, PA)

   2    356         356    1958-59

Albright (Albright, WV)

   3    292    184    108    1952-54

Mitchell (Courtney, PA)

   1    288         288    1963

Ohio Valley Electric Corp. (Chelsea, OH) (Madison, IN) (b)

   11    280    78    202     

Willow Island (Willow Island, WV)

   2    243    207    36    1949-60

Rivesville (Rivesville, WV)

   2    142    121    21    1943-51

R. Paul Smith (Williamsport, MD)

   2    116         116    1947-58

Hunlock (Hunlock Creek, PA) (c)

   1    24         24    1957

Pumped-Storage and Hydro:

                        

Bath County (Warm Springs, VA) (d)

   6    985    227    758    1985; 2001

Lake Lynn (Lake Lynn, PA) (e)

   4    52         52    1926

Green Valley Hydro (f)

   21    6         6    Various

Gas-Fired:

                        

AE Nos. 3, 4 & 5 (Springdale, PA)

   3    540         540    2003

Gleason (Gleason, TN)

   3    526         526    2001

Wheatland (Wheatland, IN)

   4    512         512    2001

AE Nos. 1 & 2 (Springdale, PA)

   2    88         88    1999

AE Nos. 8 & 9 (Gans, PA)

   2    88         88    2000

AE Nos. 12 & 13 (Chambersburg, PA)

   2    88         88    2001

Buchanan (Oakwood, VA) (g)

   2    43         43    2002

Hunlock CT (b) (Hunlock Creek, PA)

   1    22         22    2000

Oil-Fired (Steam):

                        

Mitchell (Courtney, PA)

   1    82         82    1949
    
  
  
  
    

Total Capacity

   85    10,851    2,123    8,728     
    
  
  
  
    

(a)   When more than one year is listed as a commencement date for a particular station, the dates refer to the years in which operations commenced for the different units at that station.
(b)   This figure represents capacity entitlement through AE’s ownership of OVEC shares. In December 2004, AE sold a 9% equity interest in OVEC. However, AE Supply will retain its right to 9% of the power from OVEC electric generation facilities through March 12, 2006. AE holds a 3.5% equity interest in OVEC, which entitles Monongahela to 3.5% of the power from OVEC generation facilities.
(c)   This figure represents capacity entitlement of Allegheny Energy Supply Hunlock Creek, LLC (“Hunlock”) through its 50% ownership in Hunlock Creek Energy Ventures, LLC (“Hunlock Creek”). Hunlock’s entitlement to Hunlock Creek output at maximum generation capacity is indicated on the table for the steam and natural gas-fired facilities. This output is sold exclusively to AE Supply.
(d)   This figure represents capacity entitlement through ownership of AGC.
(e)   AE Supply has a license for Lake Lynn through 2024.
(f)   Green Valley Hydro’s license for hydroelectric facilities Dam No. 4 and Dam No. 5, located in West Virginia and Maryland will expire November 30, 2024. Potomac Edison has licenses through 2024 for the Shenandoah, Warren, Luray and Newport projects located in Virginia.

 

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

 

Significant 2004 Outages

 

On November 3, 2003, a fire occurred in Unit No. 2 at the Hatfield’s Ferry generation station located near Masontown, Pennsylvania. Hatfield’s Ferry Unit No. 2 is a 570 MW coal-fired generation unit owned by AE Supply and Monongahela. As a result of the fire, the unit’s generator, turbine and certain associated equipment sustained significant damage. On February 9, 2004, a generator failure occurred in Unit No. 1 at the Pleasants generation station located in Willow Island, West Virginia. Pleasants Unit No. 1 is a 650 MW coal-fired generation unit owned by AE Supply and Monongahela. As a result of the generator failure, the unit’s generator and associated equipment sustained damage. Both units returned to service in June 2004.

 

As a result of these outages, Allegheny had less power to sell into the PJM market, and its operating results were adversely affected. The estimated lost revenues (net of fuel cost savings) associated with the Hatfield’s Ferry and Pleasants outages were approximately $58 million and $35 million, respectively, for 2004. Allegheny continues to pursue additional insurance recoveries in connection with these outages.

 

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. See “Regulatory Framework Affecting Allegheny—Federal Regulation and Rate Matters—PURPA” below.

 

       

Allegheny Company

Purchaser


   

PURPA Stations


 

Project

Total


  Monongahela

 

Potomac

Edison


 

West

Penn


 

AE

Supply

And

Other


 

PURPA

Contract

Termination

Date


Coal-Fired: Steam

                       

AES Warrior Run (Cumberland, MD) (a)

  180       180           02/10/2030

AES Beaver Valley (Monaca, PA)

  125           125       12/31/2016

Grant Town (Grant Town, WV)

  80   80               05/28/2028

West Virginia University (Morgantown, WV)

  50   50               04/17/2027

Hydro:

                       

Hannibal Lock and Dam (New Martinsville, WV)

  31   31               06/01/2034

Allegheny Lock and Dam 6 (Freeport, PA)

  7           7       06/30/2034

Allegheny Lock and Dam 5 (Freeport, PA)

  6           6       09/30/2034
   
 
 
 
 
   

Total PURPA Capacity

  479   161   180   138   0    
   
 
 
 
       

(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.

 

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LOGO

 

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The following table sets forth the existing miles of tower and pole T&D lines and the number of substations of the Distribution Companies and AGC as of December 31, 2004:

 

     Underground

  

Above-

Ground


  

Total

Miles


  

Total Miles

Consisting of

500-Kilovolt

(kV) Lines


  

Number of

Transmission and

Distribution
Substations


Monongahela

   665    23,172    23,837    246    261

Potomac Edison

   4,415    17,644    22,059    178    291

West Penn

   2,505    24,021    26,526    276    615

AGC (a)

   0    87    87    87    1
    
  
  
  
  

Total

   7,585    64,924    72,509    787    1,168
    
  
  
  
  

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

 

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

 

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FUEL, POWER AND RESOURCE SUPPLY

 

Generation and Marketing Segment

 

Coal Supply

 

Allegheny purchased 16.9 million tons of coal in 2004 at an average price of $30.53 per ton delivered. Allegheny purchased this coal primarily from mines in Pennsylvania, West Virginia and Ohio. However, Allegheny considers sources of coal supply from other viable regions. During 2004, Allegheny conducted test burns of Powder River Basin coal from Wyoming at several generation facilities.

 

Historically, Allegheny has purchased coal from a limited number of suppliers. Of Allegheny’s coal purchases in 2004, 76% came from subsidiaries of two companies, the larger of which represented 58% of the total tons purchased. As of February 17, 2005, Allegheny had contracts in place for the delivery of approximately 17 million tons of coal in 2005 at an average price of $34.70 per ton delivered. This represents approximately 95% of estimated coal to be consumed in 2005. Due to various industry factors, including increased mining costs, rail transportation constraints and operational difficulties, some coal suppliers are under increased financial pressure, which has had, and may continue to have, negative effects on coal supplier performance.

 

As existing long-term contracts expire, Allegheny plans to enter into multi-year contracts to secure a reliable coal supply. These new arrangements are expected to be at higher prices than the expiring contracts.

 

Allegheny owns undeveloped coal reserves estimated to contain in excess of 120 million tons of higher sulfur coal recoverable by deep mining. Allegheny is evaluating a number of alternatives related to these undeveloped reserves.

 

Natural Gas Supply

 

AE Supply purchases natural gas services to supply its natural gas-fired facilities. In 2004, AE Supply purchased its natural gas requirements principally in the spot market. In addition, one of AE Supply’s subsidiaries has a month-to-month natural gas agreement in place with a supplier. The natural gas provided under this agreement is used at the Buchanan 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 Oakford, Pennsylvania 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 FERC. This agreement provides for transportation of 90,000 decatherms of natural gas per day through December 31, 2012 from Greene County, Pennsylvania to the Hatfield’s Ferry generation station in Masontown, Pennsylvania. This transportation agreement was purchased for anticipated natural gas reburn opportunities at Hatfield’s Ferry. Natural gas reburn reduces NOx emissions at a generation station by using natural gas instead of coal for a portion of the generation station’s anticipated fuel requirements. This process is used at Hatfield’s Ferry when the price of natural gas makes reburn economic relative to other NOx emission management activities.

 

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

 

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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 the La Paz combined-cycle generation facility in Arizona. This project has been cancelled. In August 2003, AE Supply obtained a permanent release of approximately 85% of its capacity obligation under this contract. In November 2004, AE Supply entered into a release for the balance of this capacity.

 

Kern River Transportation Contract.    AE Supply has a long-term agreement with Kern River Gas Transmission Company for the transportation of natural gas under a tariff approved by FERC. This agreement provides for the transportation of 45,122 decatherms of natural gas per day through April 30, 2018 from Opal, Wyoming to Nevada and 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 June 2004, AE Supply entered into a long-term capacity release for the full contract volume through October 2007. AE Supply recorded charges of $15.5 million related to this release in 2004.

 

The Delivery and Services Segment

 

Electric Power

 

Allegheny reorganized its corporate structure in response to electric utility deregulation within its service area between 1999 and 2001. The Distribution Companies, with the exception of Monongahela and its West Virginia generation assets, do not produce their own power. Monongahela transferred a portion of its generation assets relative to its Ohio and FERC generation assets, including a portion of its ownership interest in AGC, to AE Supply in 2001. Potomac Edison transferred substantially all of its generation assets to AE Supply in 2000. West Penn transferred all of its generation assets to AE Supply in 1999.

 

The Distribution Companies are obligated to provide electricity at capped rates to customers who do not retain an alternate electricity generation supplier during the applicable deregulation transition period. The transition periods vary across Allegheny’s service area.

 

    Monongahela. In Ohio, the transition period for residential and small business customers ends on December 31, 2005. See “Regulatory Framework Affecting Allegheny—State Legislation and Regulatory Developments,” below for information regarding the termination of the transition periods for commercial and industrial customers in Ohio.

 

    Potomac Edison. In Maryland, the transition period for residential customers ends on December 31, 2008. The transition period for commercial and industrial customers ended December 31, 2004. In Virginia, the transition period ends on December 31, 2010.

 

    West Penn. In Pennsylvania, the transition period terminates at the end of 2008 for all customers, pending resolution of a Joint Petition for Settlement filed by West Penn and other interested parties in September 2004, which seeks to extend the transition period and increase applicable rate caps.

 

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

 

AE Supply is contractually obligated to provide power to the Distribution Companies during the relevant state deregulation transition periods under the terms of power supply agreements with the Distribution Companies. AE Supply also sells power to Potomac Edison to serve customers in Potomac Edison’s West Virginia service territory. Sales under AE Supply’s power sales agreements with West Penn, Monongahela (with respect to its Ohio customers) and Potomac Edison currently consume a majority of the normal operating capacity of AE Supply’s generation assets. 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.

 

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The Distribution Companies purchase a majority of the power required to satisfy their respective PLR obligations from AE Supply. The purchases are made under the terms of power sales agreements with AE Supply, which will terminate as set forth in the chart below. When the power sales agreements with AE Supply terminate, the Distribution Companies 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 PLR obligations of the Distribution Companies following the termination of these agreements have not been determined and are subject to active legislative and regulatory actions in Pennsylvania and Virginia. In Maryland, a final state commission order that prescribes a wholesale bidding process to procure market-based full requirements service for end use customers was issued on September 30, 2003. The bid solicitation process began on October 1, 2003. By January 28, 2005, the Distribution Companies had completed two full bid solicitations, securing PLR service for eligible Maryland commercial and industrial customers through May 31, 2006.

 

In Ohio, the market development period for medium to large commercial and industrial customers and streetlighting terminated on December 31, 2003. PUCO authorized Monongahela to issue a request for proposals for wholesale power to supply approximately 130 MW of market-based retail rate service to these customers, effective January 1, 2004. AE Supply won the competitive bid process to serve the load, subject to approval of its bid by PUCO. In October 2003, PUCO denied approval of the wholesale bid and new retail rates and continued the fixed rates for these customer classes until December 31, 2005. See “Regulatory Framework Affecting Allegheny—State Legislation, Rate Matters and Regulatory Developments,” below for a more detailed discussion of legal and regulatory actions relating to this matter.

 

A portion of the Distribution Companies’ PLR obligations is satisfied by PURPA contract purchases. Most of the rest of the power necessary to meet the PLR obligations of the Distribution Companies and Potomac Edison’s regulated service obligations in West Virginia is purchased from AE Supply. The table below shows the percentage of power for each jurisdictional set of customers that was purchased by the Distribution Companies from AE Supply in 2004:

 

Distribution

Company


   State

  

Percentage of Total

2004 Power Purchases

for PLR Obligations

from AE Supply by

Jurisdiction (%)


  

Termination Date of

Power Sale Agreement

with AE Supply


Monongahela

   Ohio    91    December 31, 2005(a)

Potomac Edison

   Maryland    100    December 31, 2008(b)

Potomac Edison

   West Virginia    N/A    December 31, 2017(c)

Potomac Edison

   Virginia    99    June 30, 2007

West Penn

   Pennsylvania    95    December 31, 2008

(a)   The transition period for most commercial and industrial customers ended on December 31, 2003. This load is no longer served under the power sales agreement.
(b)   The transition period for commercial and industrial customers ended on December 31, 2004. This load is no longer served under the power sales agreement.
(c)   Potomac Edison’s current power sales agreement with AE Supply for West Virginia expires on December 31, 2010. However, Potomac Edison and AE Supply have agreed to a new contract that expires on December 31, 2017. The effectiveness of that contract is subject to West Virginia PSC and FERC approval.

 

Natural Gas Supply

 

In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia, including Mountaineer, for $141 million in cash and the assumption of approximately $87 million of long-term debt, subject to certain closing adjustments. The sale is subject to regulatory approval and is expected

 

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to be completed in mid- to late-2005. These natural gas operations are shown as discontinued operations in the accompanying financial statements.

 

Monongahela’s regulated natural gas sales operations are carried out through Mountaineer and its Monongahela divisions. West Virginia is in the path of major natural gas supply routes from the Gulf of Mexico to the Northeast, and Monongahela has direct access to the Columbia Gas Transmission Corporation (“Columbia Gas”) and the Tennessee Gas Pipeline interstate pipeline systems. Monongahela’s principal natural gas requirements are supplied from wells located in Appalachia and the Gulf of Mexico producing basins. Monongahela’s ownership of MGS provides direct access to less than 5% of Monongahela’s total annual natural gas needs. A small part of MGS’ output is sold to third parties. Approximately 75% to 85% of Monongahela’s natural gas supply requirements are purchased on a forward basis up to 18 months in advance. The remainder, including MGS production, is purchased on a one-year or more forward basis primarily at index-based prices.

 

As a result of Allegheny’s past liquidity issues, coupled with natural gas price increases, Monongahela was required to prepay for some of its future natural gas purchases during 2004. Monongahela believes that it will have access to sufficient natural gas supplies to meet its anticipated requirements.

 

Natural Gas Transportation and Storage Capacity

 

Natural gas purchased from producers or suppliers in the Gulf Coast producing basin/region is transported through the interstate pipeline systems of Columbia Gas and Columbia Gulf Transmission Company (“Columbia Gulf”) to Monongahela’s local distribution facilities in West Virginia.

 

To ensure continuous, uninterrupted service to its customers, Mountaineer has long-term transportation and storage service agreements with Columbia Gas and Columbia Gulf. These contracts cover a wide range of transportation services and volumes. Under both Mountaineer’s and WVP’s Purchased Gas Adjustment clauses, purchased gas costs including transportation and storage services, if prudently incurred, are recovered from the respective companies’ customers.

 

Typically, large commercial and industrial end-users of natural gas use natural gas sales and/or transportation contracts for load management purposes. Under these contracts, users purchase and/or transport natural gas with the understanding that they may be forced to shut down their use of natural gas or switch to alternate sources of energy during periods of high demand for natural gas. In addition, during times of extraordinary supply problems, curtailments of deliveries to some classes of customers (typically large industrial customers) with interstate transportation contracts may be necessary, but only in accordance with guidelines established by appropriate federal and state regulatory agencies.

 

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REGULATORY FRAMEWORK AFFECTING ALLEGHENY

 

The interstate transmission services and wholesale power sales of the Distribution Companies and AE Supply are regulated by FERC under the Federal Power Act (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.

 

AE and all of its subsidiaries are also subject to the broad jurisdiction of the SEC under PUHCA. In addition, Allegheny’s communications subsidiary, ACC, is subject, to a limited extent, to the jurisdiction of the Federal Communications Commission and state communications regulatory commissions. Allegheny is subject to numerous other local, state and federal laws, regulations and rules.

 

Federal Regulation and Rate Matters

 

FERC, Competition and RTOs

 

FERC is an independent agency within the U.S. Department of Energy that regulates the transmission and wholesale of electricity under the authority of the FPA. Under the FPA, FERC regulates the rates, terms and conditions of wholesale power sales and transmission services offered by public utilities.

 

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

 

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 to offer non-discriminatory, open-access transmission services. In addition, FERC 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 utilities from giving their power marketing businesses preferential access to transmission system information. FERC also has taken steps to encourage utilities to participate in RTOs, such as PJM, by transferring control over their transmission assets to RTOs.

 

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

 

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

 

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In April 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 million in revenues that would otherwise not be collectible once they joined PJM. In 2004, 2003 and 2002, the Distribution Companies recovered approximately $35 million, $27 million and $23 million of these surcharges, respectively. FERC also allowed the Distribution Companies to collect a surcharge to recover the costs associated with Allegheny’s integration into PJM, which expired at the end of 2004. Accordingly, the Distribution Companies have fully recovered all of these surcharges as of December 31, 2004.

 

The Distribution Companies also may be impacted by recent FERC actions with respect to the transmission rate design within PJM. Beginning in November 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 the region. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others and ordered the continuation of the existing rate design and the implementation of a transition charge for this region through March 31, 2006. FERC also authorized three transmission owners to submit filings that would enable them to assess additional transition charges against the Distribution Companies and other utilities in PJM. Allegheny estimates that these additional charges, if accepted by FERC, will result in net transmission charges to the Distribution Companies of approximately $0.5 million for the four-month period ended March 31, 2005 and approximately $8.9 million for the twelve-month period ended March 31, 2006. In February 2005, FERC accepted these transition charges, effective December 1, 2004, subject to an evidentiary hearing regarding the data and methodology used to determine the charges and proposed adjustments. The order expected to be issued by FERC 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 surcharges imposed on the transition charges previously billed to the Distribution Companies.

 

Substantially all of Allegheny’s generation assets and power supply obligations are located within the PJM market. Any 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 proposed revisions to PJM’s tariff concerning the auction of financial transmission rights and the allocation mechanism for the auction revenues; changes in transmission congestion patterns due to the proposed implementation of PJM’s regional transmission expansion planning protocol or other required transmission system upgrades; the effects throughout the system of new members joining PJM and new generation retirement rules and reliability pricing issues.

 

By September 30, 2005, AE Supply, the Distribution Companies and other Allegheny entities that had market-based rate authority granted by FERC are required to file a triennial analysis of market power with FERC. This filing is required as a condition to continuing to sell electric energy at wholesale and market rates.

 

PUHCA

 

Any entity that owns, controls or has the power to vote 10% or more of the outstanding voting securities of an “electric utility company,” or a holding company for an electric utility company, is subject to SEC regulation under PUHCA.

 

PUHCA imposes financial and operational conditions and restrictions on many aspects of a registered holding company system’s business. PUHCA restricts a registered holding company system from expanding into other businesses by prohibiting it from engaging in activities that are not functionally related to its core business. PUHCA also requires registered holding company systems to confine themselves to a single integrated public utility system. Most important in light of Allegheny’s past liquidity issues, PUHCA requires pre-approval from

 

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the SEC for, among other things, the issuance of debt or equity securities and for the sale or acquisition of utility assets. The SEC, in certain matters, also requires state approvals as a condition to authorizations, even though such approvals might not be required under applicable state laws. Thus, the PUHCA approval process introduces significant lead times into routine transactions under normal circumstances.

 

Additionally, under PUHCA, the SEC has imposed a common equity to total capitalization ratio on the utilities that it regulates, thus imposing additional operating constraints not imposed on other utilities. Allegheny’s current common equity ratio is below the level required under its current financing authorizations, which has required it to obtain additional authorizations.

 

Many of Allegheny’s competitors are not regulated under PUHCA and, therefore, do not face these constraints.

 

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 that satisfy the eligibility requirements for PURPA benefits established by FERC. State public service commissions or legislatures establish the rates paid for electric energy purchased from these qualifying facilities.

 

The Distribution Companies have committed to purchase 479 MW of qualifying PURPA capacity. In 2004, payments for PURPA capacity and energy pursuant to these contracts totaled approximately $197.8 million. The average cost to the Distribution Companies of these power purchases was 5.2 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 Legislation, Rate Matters and Regulatory Developments

 

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’s T&D assets are subject to traditional regulated utility ratemaking (i.e., cost-based rates). As part of West Penn’s restructuring settlement, West Penn is subject to rate caps on its T&D rates through December 31, 2005 and on its generation rates through December 31, 2008. West Penn is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver.

 

West Penn has long-term power sales agreements with AE Supply to provide West Penn with the amount of electricity necessary to meet the majority of its PLR retail obligations (and certain wholesale contracts) during the Pennsylvania transition period. As directed by the Customer Choice Act, the Pennsylvania PUC has issued draft PLR service rules addressing the utilities’ obligation to serve customers at the end of their respective transition periods.

 

In November 2003, West Penn requested approval to issue additional transition bonds up to amounts originally authorized to securitize the portion of West Penn’s stranded costs that are not recoverable on a timely basis due to operation of the generation rate cap. In September 2004, West Penn, the Pennsylvania Office of Consumer Advocate, the Office of Small Business Advocate and The West Penn Power Industrial Intervenors

 

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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. If the joint petition is approved, West Penn will be allowed to securitize up to $115 million of additional transition costs (including the deferred portion of the competitive transition charge (“CTC”) from 1999 through 2004) through the issuance of transition bonds. Under the proposed settlement, distribution rate caps will be extended from 2005 to 2007, and generation rate caps will be extended from 2008 to 2010, with additional generation rate increases occurring in 2007, 2009 and 2010. These increases will gradually move generation rates closer to market-based rates.

 

In August 2004, West Penn filed its annual CTC reconciliation for the twelve months ended July 31, 2004. The reconciliation showed a twelve-month underrecovery of $13.2 million, for a cumulative underrecovery of approximately $78.3 million. In October 2004, West Penn filed a Petition for Continued Deferral of CTC Underrecovery as Regulatory Asset. The Pennsylvania PUC approved the reconciliation and granted authorization to record the 2004 cumulative underrecovery as a regulatory asset, for full and complete recovery, with an annual interest rate of 11%.

 

Recently enacted legislation requires the implementation of an alternative energy portfolio standard in Pennsylvania which 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 a five-year 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 to investigate implementation and enforcement of the legislation.

 

West Virginia

 

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

 

In July 2003, Potomac Edison, Monongahela and certain other interested parties filed a stipulation with the West Virginia PSC on issues related to their generation asset transfers, including the amount transferred to AE Supply representing Ohio’s allocated share of Monongahela’s generation. The West Virginia PSC has not yet approved the stipulation and the parties to the agreement have initiated discussions to consider modifications to the agreement.

 

On September 27, 2004, Monongahela, Mountaineer and Mountaineer Gas Holding Limited Partnership (“Mountaineer Holdings”) filed a joint petition with the West Virginia PSC for approval to transfer the stock of Mountaineer and certain other natural gas distribution assets owned by Monongahela to Mountaineer Holdings, the prospective buyer of Monongahela’s West Virginia natural gas business. In a separate petition also filed on September 27, 2004, Mountaineer filed to increase its distribution rates by approximately $23 million, or 9.6%, annually. Mountaineer Holdings’ obligation to complete this transaction is conditioned on approval of a rate increase that is not materially different from the increase requested. The West Virginia PSC issued an order suspending the rates until September 8, 2005 and directing the administrative law judge to render a decision in this matter no later than July 11, 2005.

 

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Monongahela’s natural gas distribution business is divided into two components for purposes of its Purchased Gas Adjustments (“PGA”): West Virginia Power Gas Services (“WVPGS”) and Mountaineer. WVPGS and Mountaineer file with the West Virginia PSC to adjust their PGA every year. The PGA mechanism compares the revenue received for recovery of projected gas expenses to the actual gas expenses incurred by WVPGS or Mountaineer and defers any difference as a regulatory asset or liability to be collected or returned, respectively, to customers in the next proceeding. The PGA generally has no effect on earnings. An annual PGA period normally begins with service provided on and after November 1 and concludes on October 31 of the following year.

 

On October 7, 2004, an administrative law judge for the West Virginia PSC approved an interim PGA increase, effective on November 1, 2004, of $4.1 million, or 12.5%, for WVPGS and $26.4 million, or 9.7%, for Mountaineer. In January 2005, the West Virginia PSC issued a second interim decision, which became final in February 2005, approving final PGA rates that were higher than the prior year’s rates, but lower than the first approved interim rates, effective February 1, 2005. These rates resulted in an increase over the prior year of $3.9 million, or 11.8%, for WVPGS and $25.0 million, or 9.2%, for Mountaineer. The estimated annual total revenue increases reflect the companies’ agreement to defer half of the under-recovered balances as of June 30, 2004. Approximately $1 million for WVPGS and $7 million for Mountaineer will be deferred until the next PGA proceeding. Carrying charges will accumulate on these deferred amounts at Allegheny’s cost of debt calculated for a one-year period, which will also be recovered in the next PGA proceeding.

 

Maryland

 

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

 

The Maryland transition period lasted through December 31, 2004 for commercial and industrial customers and extends through December 31, 2008 for residential customers. Potomac Edison has long-term power sales agreements with AE Supply to provide the amount of electricity necessary to meet the majority of Potomac Edison’s PLR retail obligations (and certain wholesale contracts) during the Maryland transition period. Potomac Edison will procure the wholesale electric supply services necessary to serve its PLR obligations after the expiration of the transition period and before the expiration of its PLR obligations through a 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 January 2005, a previously approved increase in Potomac Edison’s distribution rates went into effect.

 

In 2000, the Maryland PSC issued an order imposing standards of conduct between Maryland utilities and their affiliates. In 2005, the Maryland PSC is expected to issue final regulations to provide standards governing a utility’s conduct with its affiliates in Maryland.

 

Recently enacted legislation requires the implementation of a renewable energy portfolio standard in Maryland. Beginning upon the later of the expiration of the transition period for any particular customer class served by a supplier or January 1, 2006, retail electricity suppliers in Maryland will have to obtain certain percentages of their energy supplies from renewable energy resources. The law provides that if renewable resources are too expensive, or are unavailable in quantities sufficient to meet the standard in any given year, suppliers can opt instead 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.

 

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Virginia

 

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

 

Potomac Edison has long-term power sales agreements with AE Supply to provide Potomac Edison with the amount of electricity necessary to meet the majority of its PLR retail obligations (and a wholesale contract) through June 30, 2007. After that, Potomac Edison will purchase its PLR requirements from the wholesale market and recover certain costs from customers through a purchased power adjustment clause.

 

On October 8, 2004, the Virginia SCC approved Potomac Edison’s application to transfer control of its transmission facilities to PJM subject to the requirement that both Potomac Edison and PJM submit annual reports to the Virginia SCC beginning October 1, 2005.

 

Ohio

 

The Ohio General Assembly adopted legislation in 1999 to restructure its electric utility industry, provide retail electric customers the right to choose their electricity generation supplier and begin a transition to market rates. The 1999 legislation granted Ohio’s residential customers a 5% reduction in the generation portion of their rates until December 31, 2005, which is when the transition period ends. Pursuant to a settlement, Monongahela’s transition period for large industrial, commercial and street lighting customers was scheduled to end on December 31, 2003, but, as discussed below, has been extended by PUCO until December 31, 2005. Under the regulatory transition plan, Monongahela transferred its Ohio generation assets to AE Supply in June 2001. Monongahela retained its T&D assets. Monongahela’s T&D rates are capped through the end of the transition period for all customers and, thereafter, are subject to traditional regulated utility ratemaking (i.e., cost-based rates). Monongahela is the PLR for customers who do not choose an alternate supplier or whose alternate supplier does not deliver.

 

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

 

In February 2004, Monongahela filed for an injunction in federal court seeking to recover, in retail rates, its costs of purchasing power in the wholesale market. In May 2004, the court partially granted Monongahela’s request, ruling that the Ohio legislation adopted in 1999 to restructure the electric utility industry was unconstitutional to the extent it did not permit Monongahela to make a claim with PUCO that its rates are confiscatory. Monongahela requested reconsideration of the court’s order, which the court partially granted by retaining jurisdiction over this matter. PUCO initiated a proceeding in compliance with the federal court’s directive. In June 2004, Monongahela filed its application for rate relief, which PUCO denied in December 2004

 

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with respect to certain large industrial and commercial customers and street lighting customers. Monongahela requested rehearing of PUCO’s ruling on January 7, 2005, which was denied. Monongahela appealed this ruling on February 25, 2005. On January 12, 2005, Monongahela renewed its request for a preliminary injunction against PUCO in federal court. If these challenges are not successful, Monongahela’s current rates for these customer classes will be fixed through December 31, 2005.

 

Since January 2004, Monongahela has been purchasing power at PJM market prices for these customers and anticipates that the price for that power will continue to be higher than the current retail generation rates it charges customers. Monongahela has expensed $12.0 million of costs in excess of its rates for 2004, pending the final outcome of Monongahela’s legal challenges.

 

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EMPLOYEES

 

All of the registrants’ officers and employees are employed by AESC, except for certain employees who are directly employed by Mountaineer effective January 1, 2005. As of December 31, 2004, AESC employed approximately 5,100 employees. Of these employees, approximately 30% are subject to collective bargaining arrangements. Approximately 77% of the unionized employees are at the Distribution Companies and approximately 23% are at AE’s other subsidiaries. Approximately 1,080 employees are represented by System Local 102 of the Utility Workers Union of America (the “UWUA”), and 105 employees are represented by other locals of the UWUA. Approximately 160 employees are represented by locals of the Paper, Allied-Industrial, Chemical, and Energy Workers International Union. Approximately 185 employees are represented by locals of the International Brotherhood of Electrical Workers (the “IBEW”). The collective bargaining arrangements with certain locals of the IBEW expired and have been extended while the parties negotiate a new contract. Other collective bargaining arrangements expire at various dates through the last quarter of 2007. Each of the registrants believes that current relations between it and its unionized and non-unionized employees are satisfactory.

 

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ENVIRONMENTAL MATTERS

 

The operations of Allegheny’s owned facilities, including its generation stations, are subject to regulation by various federal, state and local authorities as to air and water quality, hazardous and solid waste disposal and other environmental matters.

 

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, will require modification, supplementation or replacement of equipment at existing stations at substantial additional cost.

 

Air Standards

 

Allegheny currently meets applicable standards for particulate matter emissions at its generation stations through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and emission allowances and, at times, through reduction of output. From time to time, minor excursions of stack emission opacity, that are normal to fossil fuel operations, are experienced and are accommodated by the regulatory process.

 

Allegheny meets current emission standards for SO2 by using scrubbers, 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 expensive post-combustion control technologies on many of its generation stations.

 

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. Allegheny continues to study the use of allowances, additional emission controls and low sulfur fuel to meet future SO2 compliance obligations. Allegheny estimates that it may purchase allowances for up to 50,000 tons for 2005 and an average of approximately 100,000 tons per year for 2006 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. Allegheny currently expects that its plan to increase its use of lower sulfur coal and implement other environmental control improvements should reduce allowance purchase requirements over this time period.

 

In 1998, the EPA finalized its Nitrogen Oxide (“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. Compliance with the NOx SIP call was required beginning in May 2004. Pennsylvania and Maryland implemented their respective SIP call rules in May 2003. West Virginia’s SIP call rules were effective as of May 2004.

 

AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. These NOx controls include selective catalytic reduction at the Harrison and Pleasants generation stations and selective noncatalytic reduction at the Hatfield’s Ferry and Fort Martin generation stations, as well as burner modifications at the Mitchell generation station. The NOx compliance plan functions on a system-wide basis, similar to the SO2 compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. AE Supply estimates that its emission control activities, in concert with its inventory of banked allowances, will facilitate its compliance with NOx limits established by the SIP through 2008. Allegheny’s 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.

 

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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 stations, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these generation stations. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the NSR standards of the Clean Air Act, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. AE has provided responsive information to this and a subsequent request. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues.

 

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings in most cases. AE believes that its subsidiaries’ generation facilities have been operated in accordance with the Clean Air Act and the rules implementing it. The experience of other energy companies, however, suggests that, in recent years, the EPA has narrowed its view regarding the scope of the definition of “routine maintenance” under its rules, thereby broadening the range of actions subject to compliance with NSR standards. Section 114 information requests concerning facility modifications are often followed by enforcement actions.

 

If NSR standards are applied to Allegheny’s generation stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. There are two federal district court decisions interpreting the application of NSR standards to utilities, the Ohio Edison decision and the Duke Energy decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy decision supports the industry’s understanding of NSR requirements. The final Routine Maintenance, Repair and Replacement Rule (“RMRR”) released by the EPA is more consistent with the energy industry’s historical compliance approach. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the RMRR, which was scheduled to go into effect on December 26, 2003. The stay delays implementation of the RMRR. At this time, AE and its subsidiaries are not able to determine the effect that these actions may have on them.

 

On February 2, 2004, the EPA informed AE that it intended to provide the New York Attorney General, pursuant to his request, certain records that AE provided to the EPA pursuant to its request under Section 114 of the Clean Air Act. On April 23, 2004, the PADEP notified AE Supply that the PADEP had requested that the EPA provide it with these records.

 

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 PADEP. 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 stations in Pennsylvania and identifies PADEP 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.

 

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 on January 6, 2005. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia are in compliance with the Clean Air Act. The Attorneys General have filed a motion to dismiss the declaratory judgment action. If the action is dismissed based upon their motion, the Attorneys General may file an enforcement action against Allegheny in federal court in Pennsylvania. It is also possible that the EPA and other state authorities may join in the current declaratory judgment action or, if it is dismissed, a new action filed by the Attorneys General.

 

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

 

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

 

Pending Initiatives

 

On March 10, 2004, the EPA issued the Clean Air Interstate Rule (“CAIR”), which imposes additional NOx and SO2 controls over power plant emissions. CAIR requires significant reductions of NOx and SO2 by 2010 (for Phase I) and 2015 (for Phase II) under a cap and trade program similar to the EPA’s acid rain program, and will be implemented through the state SIP program. The effect on Allegheny of these regulations is unknown at this time, but could be substantial.

 

The EPA promulgated revisions to particulate matter and ozone standards in July 1997. Litigation over the revised particulate matter and ozone standards has recently been resolved, and these requirements could impose substantial costs on Allegheny. Allegheny does not anticipate final regulations before 2008. The EPA has also promulgated final regional haze regulations to improve visibility in national parks and wilderness areas, which are currently the subject of litigation. The effect on Allegheny of these regulations is unknown at this time, but could be substantial.

 

On December 15, 2003, the EPA proposed a rule to regulate power plant mercury emissions. The EPA plans to finalize a mercury emissions standard by March 15, 2005. Based on this schedule, it is unlikely that the implementation of mercury controls would be required before 2007 or 2008. The effect on Allegheny of these regulations is unknown at this time, but could be substantial.

 

The Kyoto Protocol went into effect on February 15, 2005. The Kyoto Protocol, which was signed by the Clinton Administration, but not ratified by the U.S. Senate, would require drastic reductions in greenhouse gas emissions in the United States in response to the perceived threat of global warming. If ratified and implemented by the United States, this treaty would likely require extensive mitigation efforts by Allegheny to reduce greenhouse gas emissions at its electric generation facilities and would raise considerable uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities. The Bush Administration has rejected the Kyoto Protocol and has proposed voluntary programs to reduce greenhouse gas intensity over the next decade. Various legislative proposals are under consideration at the federal and state level. The ultimate outcome of the global climate change debate and the Kyoto Protocol, which cannot be predicted at this time, could have a significant effect on Allegheny.

 

The Clear Skies Act of 2005 (the “Clear Skies Bill”) has been introduced in the 109th Congress. The legislation is intended to eliminate Title IV of the Clean Air Act Amendments of 1990 and replace it with provisions designed to take a comprehensive and integrated approach to air emissions regulation. The Clear Skies Bill and alternative legislation have been the focus of Congressional committee action on multi-emission legislation. The Clear Skies Initiative does not include carbon dioxide reductions, but focuses on SO2, NOx and mercury. Hearings on multi-emissions legislation have been held in both the Senate and the House of Representatives, but the bill remains in committee.

 

Water Standards

 

Under the National Pollutant Discharge Elimination System (the “NPDES”), permits for all of Allegheny’s stations and disposal sites are in place, and its facilities are generally in compliance with all permit terms, conditions and effluent limitations. However, as permits are renewed, more stringent permit limitations are often

 

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applied. To date, Allegheny has successfully developed, and scientifically justified to the satisfaction of the regulatory agencies, acceptable regulatory mixing zones or alternate site-specific water quality criteria or has installed passive constructed wetland treatment technology, thus avoiding significant capital costs and potential liabilities of advanced wastewater treatment. However, there is significant activity at the federal level on issues relating to the Clean Water Act (the “CWA”). The results of several pending long-term initiatives could cause Allegheny and its customers to incur material and substantial costs.

 

Rulemakings regarding the Total Maximum Daily Load Program, water quality standards, antidegradation review, human health and aquatic life water quality criteria, mixing zones and a final rulemaking concerning the CWA Section 316(b) Cooling Water Intake Structure are pending. In addition, the EPA is developing new policies concerning protection of endangered species under the CWA and imposition of new CWA requirements to address sediment and biological water quality criteria contamination. The outcome of these rulemakings will fundamentally change the traditional water quality management program from a chemical-specific control of point sources to a comprehensive and integrated watershed management program. This regulatory shift will result in more restrictions on facility discharges, as well as nonpoint source runoff, resulting from land use practices such as agriculture and forestry, and will ultimately address water quality impairment caused by atmospheric deposition.

 

Cooling Water Intake

 

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 is unknown at this time but could be substantial.

 

RESEARCH AND DEVELOPMENT

 

Allegheny spent approximately $7.2 million and $0.6 million for research in 2002 and 2003, respectively. Allegheny’s expenditures for research in 2004 were minimal. In 2004, Allegheny’s research and development activity addressed air emissions issues, and Allegheny expects that its research and development activity in 2005 will continue to address these issues.

 

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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 consisting of approximately $1.04 billion of bank debt restructured in October 2004 (of which $982 million remained outstanding as of December 31, 2004) and $344 million of notes that were restructured in February 2003. Substantially all of Monongahela’s and Potomac Edison’s properties are held subject to the lien of indentures securing their first mortgage bonds. Certain of the properties and other assets owned by AE Supply and Monongahela that were financed by solid waste disposal and pollution control notes are subject to liens securing the obligations under those notes. In many cases, the properties of Monongahela, Potomac Edison and other AE subsidiaries may be subject to certain reservations, minor encumbrances and title defects that do not materially interfere with their use. The indenture under which AGC’s unsecured debentures are issued prohibits AGC, with certain limited exceptions, from incurring or permitting liens to exist on any of its properties or assets unless the debentures are contemporaneously secured equally and ratably with all other debt secured by the lien. Most T&D lines, some substations and switching stations and some ancillary facilities at power stations 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.

 

Allegheny’s principal corporate headquarters are 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.

 

MGS owns more than 300 natural gas wells and has net revenue interests in about 100 additional wells located throughout West Virginia. MGS has active leaseholds that cover more than 86,000 acres. In addition to its production assets, MGS owns approximately 125 miles of high-pressure transmission facilities running from Jackson County, West Virginia, west to Huntington, West Virginia, where it terminates at various delivery locations, and approximately 400 miles of gathering lines located in the same general vicinity.

 

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ITEM 3.    LEGAL PROCEEDINGS

 

Putative Class Actions Under California Statutes

 

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

 

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

 

The District Court separately granted plaintiffs’ motion to remand in the eighth action, Millar, on July 9, 2003. On December 18, 2003, the plaintiffs filed an amended complaint in California state court, solely on behalf of consumers, naming certain additional defendants, including The Goldman Sachs Group, Inc. (“Goldman Sachs”). The case was removed to federal court based on the amended complaint. On January 11, 2005, the federal district court remanded the case back to the state court.

 

Under the terms of the agreement relating to the sale of the CDWR contract, AE Supply and one of its affiliates have agreed to indemnify Goldman Sachs and its affiliate J. Aron & Company, under certain conditions, for any losses arising out of the class action litigation up to the amount of the purchase price. AE Supply issued a guarantee to J. Aron & Company in connection with this indemnification obligation.

 

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

 

Nevada Power Contracts

 

On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with FERC against AE Supply seeking FERC action 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, and did not render a decision on 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”). On December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. The Ninth Circuit heard oral argument in these cases on December 8, 2004. The NPC Petitions were consolidated in the Ninth Circuit. AE Supply intends to vigorously defend against these actions but cannot predict their outcomes.

 

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Sierra/Nevada

 

On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted claims against AE and AE Supply for: (1) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (2) conspiracy and (3) 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. AE Supply intends to vigorously defend against this action but cannot predict its outcome.

 

Litigation Involving Merrill Lynch

 

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

 

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

 

On May 29, 2003, the U.S. District Court for the Southern District of New York denied AE’s motion to stay Merrill Lynch’s action and ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York state court, as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply dismissed the New York state action and filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the U.S. District Court for the Southern District of New York. The counterclaims, as amended, allege 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 seek damages in excess of $605 million, among other relief.

 

On November 24, 2003, the court dismissed AE and AE Supply’s counterclaim for rescission and struck their demand for a jury trial. AE and AE Supply’s counterclaims for fraudulent inducement, breach of contract, negligent misrepresentation and breach of fiduciary duty and their request for punitive damages with respect to certain counterclaims remain in place.

 

On February 2, 2005, the parties filed separate motions for summary judgment, which were opposed and have been fully briefed. The trial has been scheduled for May 2005.

 

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The federal government is holding certain assets of Daniel L. Gordon, the former head of energy trading for AE Supply. Both AE and Merrill Lynch have filed petitions with the U.S. District Court for the Southern District of New York claiming rights to the funds. On August 13, 2004, the U.S. Attorney filed a motion to dismiss the petitions filed by AE and Merrill Lynch on the grounds that neither AE nor Merrill Lynch had an interest in the specific property seized by the government at the time Gordon committed his offense. On September 30, 2004, AE filed an opposition to the government’s motion to dismiss.

 

AE and AE Supply intend to vigorously pursue these matters but cannot predict their outcomes.

 

Putative Shareholder, Benefit Plan Class Actions and Derivative Action

 

From October 2002 through December 2002, plaintiffs claiming to represent purchasers of AE’s securities filed 14 putative class action lawsuits against AE and several of its former senior managers in U.S. District Courts for the Southern District of New York and the District of Maryland. The complaints alleged that AE and senior management violated federal securities laws when AE purchased Merrill Lynch’s energy marketing and trading business with the knowledge that the business was built on illegal wash or round-trip trades with Enron, which the complaints alleged artificially inflated trading revenue, volume and growth. The complaints asserted that AE’s fortunes fell when Enron’s collapse exposed what plaintiffs claim were illegal trades in the energy markets. All of the securities cases were transferred to the District of Maryland and consolidated. The plaintiffs filed an amended complaint on May 3, 2004 that alleged that the defendants violated federal securities laws by failing to disclose weaknesses in Merrill Lynch’s energy marketing and trading business, as well as other internal control and accounting deficiencies. The amended complaint seeks unspecified compensatory damages and equitable relief. On July 2, 2004, the defendants moved to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding.

 

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 the Employee Retirement Income Security Act of 1974 (“ERISA”) by: (1) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (2) failing to diversify plan assets; (3) failing to monitor investment alternatives; (4) failing to avoid conflicts of interest and (5) violating fiduciary duties. The ERISA cases were consolidated in the District of Maryland. On April 26, 2004, the plaintiffs in the ERISA cases filed an amended complaint, adding a number of current and former directors of AE as defendants and clarifying the nature of their claims. On June 25, 2004, the defendants filed a motion to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding.

 

In June 2003, a shareholder derivative action was filed against AE’s Board of Directors and several former senior managers in the Supreme Court of the State of New York for the County of New York. The suit alleges that the Board and senior management breached fiduciary duties to AE that have exposed AE to the securities class action lawsuits. The derivative action has been stayed pending the commencement of discovery in the securities cases.

 

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

 

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

 

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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.

 

During the pendency of these actions, Allegheny will continue to receive payments from one of its insurance companies in the amount of $625,000, payable on each of July 1, 2005 and 2006. During 2004 and 2003, Allegheny received insurance proceeds of approximately $960,000 and $1.8 million, respectively, in connection with these cases. 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, 2004, Allegheny had 1,504 open cases remaining. Allegheny intends to vigorously defend against these actions, but cannot predict their outcomes.

 

Suits Related to the Gleason Generating Facility

 

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

 

AE Supply has demanded indemnification from Siemens Westinghouse, the manufacturer of the turbines used in the Gleason Generating Facility, pursuant to the terms of the related equipment purchase agreement. On October 17, 2002, Siemens Westinghouse filed a declaratory judgment action in the Court of Common Pleas of Allegheny County, Pennsylvania, against AE Supply and its subsidiary seeking a declaration that the prior owner released Siemens Westinghouse from this liability through a release executed after AE Supply purchased the Gleason facility. On May 6, 2004, AE Supply filed a motion for summary judgment to dismiss the declaratory judgment action. The motion for summary judgment was granted on September 7, 2004. On October 6, 2004, Siemens Westinghouse appealed the dismissal of the declaratory judgment action. Allegheny intends to vigorously defend against this action but cannot predict its outcome.

 

SEC Matters

 

On October 9, October 25 and November 5, 2002, AE received subpoenas from the SEC. The subpoenas principally concerned: (1) the departure of Daniel L. Gordon; (2) AE’s litigation with Merrill Lynch; (3) AE Supply’s valuation and management of its trading business; (4) AE’s November 4, 2002 press release concerning its financial statements; (5) the departure of AE’s and its subsidiaries’ Controller, Thomas Kloc, in June 2002 and (6) AE’s acquisition of power plants from Enron. AE and AE Supply responded to the subpoenas.

 

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On January 16, 2004, the SEC requested that AE voluntarily produce certain documents in connection with an informal investigation of AE, and the SEC has since requested the voluntary production of additional documents. AE has responded to the SEC’s request for documents. The SEC also has taken testimony from several current and former employees and has expressed an intention to take testimony from several additional current and former employees. AE is cooperating fully with the SEC.

 

EPMI Adversary Proceeding

 

AE Supply and Enron Power Marketing, Inc. (“EPMI”) were involved in an adversary proceeding which EPMI filed on May 9, 2003. Following mediation, a settlement was reached resolving all outstanding issues and a settlement agreement was executed and filed with the Bankruptcy Court for its approval. The terms of the settlement are confidential. The Bankruptcy Court approved the settlement on December 2, 2004 and dismissed EPMI’s complaint with prejudice on December 16, 2004.

 

LTI Arbitration

 

On April 22, 2004, Leasing Technologies International, Inc. and its shareholders (collectively, “LTI”) filed a demand for arbitration against Allegheny Ventures and AE before the American Arbitration Association. In December 2000, Allegheny Ventures entered into an agreement to acquire LTI, an equipment leasing company. Allegheny Ventures terminated the agreement on May 4, 2003. LTI alleges that the termination of the agreement was unjustified and seeks damages in an unspecified amount for breach of the agreement, as well as other consequential damages. On June 11, 2004, AE and Allegheny Ventures filed an answer to LTI’s demand, denying all claims. The arbitration hearing is scheduled to begin on May 16, 2005. Allegheny intends to vigorously defend against the claims in the arbitration, but cannot predict its outcome.

 

Ordinary Course of Business

 

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

 

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

 

No matters were submitted to a vote of security holders of AE, AGC or Potomac Edison during the fourth quarter of 2004. At the annual meeting of Monongahela’s shareholders held on December 7, 2004, votes were taken for the election of directors. The total number of votes cast was 5,891,000, with all votes being cast for the election of Paul J. Evanson, John P. Campbell, Joseph H. Richardson and Jeffrey D. Serkes.

 

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PART II

 

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

 

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

 

AE

 

“AYE” is the trading symbol for AE’s common stock on the New York, Chicago and Pacific Stock Exchanges. As of March 7, 2005, there were 28,360 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:

 

     2004

   2003

     High

   Low

   High

   Low

1st Quarter

   $ 13.85    $ 12.01    $ 10.30    $ 4.82

2nd Quarter

   $ 15.41    $ 13.30    $ 9.69    $ 6.26

3rd Quarter

   $ 16.08    $ 14.21    $ 9.60    $ 7.20

4th Quarter

   $ 20.11    $ 15.80    $ 12.95    $ 9.35

 

AE did not pay any dividends on its common stock during 2003 or 2004. The terms of AE’s credit facilities and the indenture governing its convertible preferred securities do not permit the payment of dividends. AE is also subject to regulatory constraints concerning dividend payments, including under PUHCA.

 

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

 

Monongahela

 

AE owns 100% of the outstanding shares of common stock of Monongahela. Monongahela paid dividends on its common stock of approximately $8.2 million, $5.0 million, $9.0 million and $11.0 million on March 31, 2004, June 30, 2004, September 30, 2004 and December 31, 2004, respectively. Monongahela paid dividends on its common stock of approximately $8.7 million, $7.7 million, $10.2 million and $17.0 million on March 31, 2003, June 30, 2003, September 30, 2003 and December 31, 2003, respectively. Monongahela’s charter limits the payment of dividends on common stock. Monongahela is also subject to regulatory constraints under PUHCA concerning dividend payments on common stock.

 

Potomac Edison

 

AE owns 100% of the outstanding common stock of Potomac Edison. Potomac Edison paid dividends on its common stock of approximately $8.7 million, $8.1 million, $12.1 million and $14.1 million on March 31, 2004, June 30, 2004, September 30, 2004 and December 31, 2004, respectively. Potomac Edison paid dividends on its common stock of approximately $9.0 million, $7.8 million, $5.6 million and $8.1 million on March 31, 2003, June 30, 2003, September 30, 2003 and December 31, 2003, respectively.

 

AGC

 

Monongahela and AE Supply own approximately 23% and 77%, respectively, of the outstanding shares of common stock of AGC. AGC paid dividends on its common stock of approximately $5.5 million and $7.0 million on March 31, 2004 and June 30, 2004, respectively. AGC did not pay any dividends on its common stock for the third and fourth quarters of 2004. AGC paid dividends on its common stock of approximately $3.5 million, $3.5 million, $3.5 million and $2.0 million on March 31, 2003, June 30, 2003, September 30, 2003 and December 31, 2003, respectively.

 

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ITEM 6.    SELECTED FINANCIAL DATA

 

     Page No.

Allegheny Energy, Inc. and Subsidiaries

   47

Monongahela Power Company and Subsidiaries

   48

The Potomac Edison Company and Subsidiaries

   48

Allegheny Generating Company

   49

 

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ITEM 6.    SELECTED FINANCIAL DATA

 

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

 

Year ended December 31, (a)


   2004

    2003

    2002

    2001

    2000

(In millions except per share data)


                            

Operating revenues (b) (c)

   $ 2,756.1     $ 2,182.3     $ 2,743.8     $ 3,165.3     $ 2,547.1

Operating expenses (c)

   $ 2,166.9     $ 2,378.7     $ 3,216.4     $ 2,214.1     $ 1,835.6

Operating income (loss) (c)

   $ 589.2     $ (196.4 )   $ (472.6 )   $ 951.2     $ 711.5

Income (loss) from continuing operations,
net of tax (c)

   $ 129.7     $ (308.9 )   $ (465.8 )   $ 458.1     $ 311.0

(Loss) income from discontinued operations,
net of tax (c)

   $ (440.3 )   $ (25.3 )   $ (36.4 )   $ (9.2 )   $ 2.7

Net (loss) income (c)

   $ (310.6 )   $ (355.0 )   $ (632.7 )   $ 417.8     $ 236.6

Earnings per share:

                                      

Income (loss) from continuing operations,
net of tax

                                      

—basic

   $ 1.00     $ (2.44 )   $ (3.71 )   $ 3.81     $ 2.82

—diluted

   $ 0.99     $ (2.44 )   $ (3.71 )   $ 3.80     $ 2.81

(Loss) income from discontinued operations,
net of tax

                                      

—basic

   $ (3.40 )   $ (0.20 )   $ (0.29 )   $ (0.07 )   $ 0.02

—diluted

   $ (2.82 )   $ (0.20 )   $ (0.29 )   $ (0.07 )   $ 0.02

Net (loss) income

                                      

—basic

   $ (2.40 )   $ (2.80 )   $ (5.04 )   $ 3.48     $ 2.14

—diluted

   $ (1.83 )   $ (2.80 )   $ (5.04 )   $ 3.47     $ 2.14

Dividends declared per share

   $ —       $ —       $ 1.29     $ 1.72     $ 1.72

Short-term debt

   $ —       $ 53.6     $ 1,132.0     $ 1,238.7     $ 722.2

Long-term debt due within one year (c)

     385.1       544.9       257.2       353.1       160.2

Debentures, notes and bonds (d)

     —         —         3,662.2       —         —  
    


 


 


 


 

Total short-term debt (d)

   $ 385.1     $ 598.5     $ 5,051.4     $ 1,591.8     $ 882.4
    


 


 


 


 

Long-term debt and QUIDS (c) (d)

   $ 4,540.8     $ 5,127.4     $ 115.9     $ 3,200.4     $ 2,559.5

Capital leases

     23.8       32.5       39.1       35.3       34.4
    


 


 


 


 

Total long-term obligations (c) (d)

   $ 4,564.6     $ 5,159.9     $ 155.0     $ 3,235.7     $ 2,593.9
    


 


 


 


 

Total assets

   $ 9,045.1     $ 10,171.9     $ 10,973.2     $ 11,032.5     $ 7,697.0
    


 


 


 


 


Notes:

(a)   See Notes 1-11, 14, 27 and 28 to the Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2001, 2002, 2003 and 2004.
(b)   Certain amounts for years prior to 2002 have been reclassified for comparative purposes, including the effects of Emerging Issues Task Force Issue No. 02-3 “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” (“EITF 02-3”) as discussed in Note 5, “Wholesale Energy Activities,” to the Consolidated Financial Statements.
(c)   In 2004, AE and certain of its subsidiaries entered into agreements to sell, or made the decision to sell, certain non-core assets. The results of operations related to these assets have been reclassified to discontinued operations for all prior periods presented. See Note 4, “Assets Held for Sale and Discontinued Operations,” to the Consolidated Financial Statements for additional information.
(d)   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 debt was reclassified as long-term.

 

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MONONGAHELA POWER COMPANY AND SUBSIDIARIES

 

Year ended December 31, (a)


   2004

    2003

   2002

    2001

   2000

(In millions)


                          

Operating revenues (b)

   $ 683.8     $ 718.9    $ 695.5     $ 704.9    $ 722.1

Operating expenses (b)

   $ 637.0     $ 633.8    $ 621.5     $ 561.0    $ 547.9

Operating income (b)

   $ 46.8     $ 85.1    $ 74.0     $ 143.9    $ 174.2

Income from continuing operations, net of tax (b)

   $ 16.4     $ 72.0    $ 32.4     $ 79.3    $ 91.9

(Loss) income from discontinued operations,
net of tax (b)

   $ (13.9 )   $ 9.2    $ 1.3     $ 10.2    $ 2.7

Net income (loss) (b)

   $ 2.5     $ 80.7    $ (81.7 )   $ 89.5    $ 31.5

Short-term debt

   $ —       $ 53.6    $ —       $ 14.3    $ 37.0

Long-term debt due within one year (b)

     —         3.4      65.9       30.4      100.0

Notes and bonds (c)

     —         —        690.1       —        —  
    


 

  


 

  

Total short-term debt (b) (c)

   $ —       $ 57.0    $ 756.0     $ 44.7    $ 137.0
    


 

  


 

  

Long-term debt and QUIDS (b) (c)

   $ 684.0     $ 715.5    $ 28.5     $ 784.3    $ 606.7

Capital leases (b)

     8.7       12.2      14.3       11.6      11.1
    


 

  


 

  

Total long-term obligations (b) (c)

   $ 692.7     $ 727.7    $ 42.8     $ 795.9    $ 617.8
    


 

  


 

  

Total assets

   $ 2,081.4     $ 2,073.1    $ 2,042.2     $ 2,017.2    $ 2,005.7
    


 

  


 

  


Notes:  
(a)   See Notes 1-7, 9, 20 and 21 to Monongahela’s Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2001, 2002, 2003 and 2004.
(b)   In 2004, Monongahela entered into agreements to sell, or made the decision to sell, certain non-core assets. The results of operations related to these assets have been reclassified to discontinued operations for all prior periods presented, as applicable. See Note 4, “Assets Held for Sale and Discontinued Operations,” to Monongahela’s Consolidated Financial Statements for additional information.
(c)   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 debt was reclassified as long-term.

 

THE POTOMAC EDISON COMPANY AND SUBSIDIARIES

 

Year ended December 31, (a)


   2004

   2003

   2002

   2001

   2000

(In millions)


                        

Operating revenues

   $ 924.4    $ 905.2    $ 870.2    $ 864.5    $ 827.8

Operating expenses

   $ 826.0    $ 833.9    $ 789.8    $ 752.3    $ 673.8

Operating income

   $ 98.4    $ 71.3    $ 80.4    $ 112.2    $ 154.0

Net Income

   $ 38.0    $ 40.5    $ 32.7    $ 48.0    $ 84.4

Short-term debt

   $ —      $ —      $ —      $ 24.2    $ 32.9

Long-term debt due within one year

     —        —        —        —        —  

Notes and bonds (b)

     —        —        416.0      —        —  
    

  

  

  

  

Total short-term debt (b)

   $ —      $ —      $ 416.0    $ 24.2    $ 32.9
    

  

  

  

  

Long-term debt and QUIDS (b)

   $ 417.9    $ 416.3    $ —      $ 415.8    $ 410.0

Capital leases

     6.2      8.5      10.3      9.2      9.9
    

  

  

  

  

Total long-term obligations (b)

   $ 424.1    $ 424.8    $ 10.3    $ 425.0    $ 419.9
    

  

  

  

  

Total assets

   $ 1,365.6    $ 1,341.7    $ 1,309.6    $ 1,110.4    $ 1,099.0
    

  

  

  

  


 

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Notes:  
(a)   See Notes 1-8 and 18 to Potomac Edison’s Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2001, 2002, 2003 and 2004.
(b)   Long-term debt at December 31, 2002 of $416.0 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003, the debt was reclassified as long-term.

 

ALLEGHENY GENERATING COMPANY

 

Year ended December 31, (a)


   2004

   2003

   2002

   2001

   2000

(In millions)


                        

Operating revenues

   $ 69.2    $ 70.5    $ 64.1    $ 68.5    $ 70.0

Operating expenses

   $ 26.1    $ 25.4    $ 25.8    $ 25.5    $ 27.6

Operating income

   $ 43.1    $ 45.1    $ 38.3    $ 43.0    $ 42.4

Net income

   $ 27.4    $ 20.8    $ 18.6    $ 20.3    $ 21.9

Short-term debt

   $ —      $ —      $ 55.0    $ —      $ —  

Long-term debt due within one year

     —        —        50.0      —        —  

Debentures (b)

     —        —        99.3      —        —  
    

  

  

  

  

Total short-term debt (b)

   $ —      $ —      $ 204.3    $ —      $ —  
    

  

  

  

  

Long-term debt (b)

   $ 99.4    $ 99.4    $ —      $ 149.2    $ 149.0

Long-term note payable to parent

     15.0      30.0      —        —        —  
    

  

  

  

  

Total long-term obligations (b)

   $ 114.4    $ 129.4    $ —      $ 149.2    $ 149.0
    

  

  

  

  

Total assets

   $ 557.2    $ 562.4    $ 597.6    $ 591.6    $ 602.0
    

  

  

  

  


Notes:  
(a)   See Notes 1-5 and 14 to AGC’s Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2001, 2002, 2003 and 2004.
(b)   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 debt was reclassified 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

   51

Key Indicators and Performance Factors

   54

Primary Factors Affecting Allegheny’s Performance

   56

Operating Statistics

   56

Critical Accounting Estimates

   57

RESULTS OF OPERATIONS:

    

Allegheny Energy, Inc. and Subsidiaries

   60

Monongahela Power Company and Subsidiaries

   76

The Potomac Edison Company and Subsidiaries

   85

Allegheny Generating Company

   89

FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES:

   91

Liquidity and Capital Requirements

   91

2004 Asset Sales

   94

2003 Asset Sales

   95

Anticipated Asset Sales

   95

Terminated Trading Payments

   95

Dividends

   95

Other Matters Concerning Liquidity and Capital Requirements

   95

Cash Flows

   99

Financing

   103

Change in Credit Ratings

   103

Derivative Instruments and Hedging Activities

   105

NEW ACCOUNTING STANDARDS

   106

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK:

    

Allegheny Energy, Inc. and Subsidiaries

   108

Monongahela Power Company and Subsidiaries

   110

The Potomac Edison Company and Subsidiaries

   110

Allegheny Generating Company

   111

 

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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 and natural gas services to customers in Pennsylvania, West Virginia, Maryland, Virginia and Ohio. AE, Allegheny’s parent holding company, was incorporated in Maryland in 1925 and is registered as a holding company under PUHCA. 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 and natural gas 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. The Distribution Companies’ principal businesses are the operation of electric and natural gas public utility systems.

 

    Monongahela conducts an electric T&D business in northern West Virginia and an adjacent portion of Ohio. Monongahela also conducts a natural gas T&D business, primarily through Mountaineer. In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia, subject to certain conditions. The sale is expected to be completed in mid- to late-2005. Monongahela also has generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below.

 

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

 

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

 

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

 

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

 

The Generation and Marketing Segment

 

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

 

    AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities, although it no longer engages in speculative trading activities.

 

    Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment.

 

    AGC was incorporated in Virginia in 1981. AGC is owned approximately 77% by AE Supply and approximately 23% by Monongahela. All of AGC’s revenues are derived from sales of its 985 MW share of generation capacity from the Bath County generation station to AE Supply and Monongahela.

 

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AE Supply is obligated under long-term contracts to provide the Distribution Companies with the power that they need to meet a majority of their PLR obligations. The Generation and Marketing segment sells power into PJM and purchases power from PJM to meet its obligations to the Distribution Companies under these contracts. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.

 

Although most of the Generation and Marketing segment’s generation capacity participates in the PJM system, it owns generation capacity outside of PJM, including AGC’s interest in the Bath County generation station and generation facilities in Gleason, Tennessee and Wheatland, Indiana. The Gleason and Wheatland generation facilities have been classified as held for sale, and their results have been presented as discontinued operations in the accompanying Consolidated Statements of Operations.

 

The Generation and Marketing segment also purchases and sells power in wholesale markets. However, AE Supply exited its speculative trading activities in the Western U.S. trading markets and elsewhere in 2003 and has implemented a strategy to focus on asset based optimization and hedging within its geographic region.

 

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

 

Intersegment Services

 

AESC was incorporated in Maryland in 1963 as a service company for AE. AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures and their respective subsidiaries have no employees. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had approximately 5,100 employees as of December 31, 2004.

 

The PJM Market and the Distribution Companies’ PLR Obligations

 

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, such as PJM.

 

Each of the states in Allegheny’s service territory, other than West Virginia, has, to some extent, deregulated its electric power industry. Pennsylvania, Maryland, Virginia and Ohio have instituted retail customer choice and are transitioning to market-based, rather than cost-based, pricing. 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. See “Business—Regulatory Framework Affecting Allegheny—State Legislation, Rate Matters and Regulatory Developments.”

 

The Distribution Companies have PLR obligations to their customers in Pennsylvania, Maryland, Virginia and Ohio. As “providers of last resort,” the Distribution Companies must supply power to retail customers who have not chosen alternative providers (or have chosen to return to Allegheny service) at rates that are capped at various levels during the applicable transition period. While these capped rates were determined based on the cost of producing power, they are generally lower than recent prevailing market prices for power.

 

In April 2002, the Distribution Companies transferred functional control of their transmission assets to PJM. PJM is the largest wholesale electricity market in the world and acts as an RTO, coordinating the movement of electricity over the transmission grid in all or portions of Delaware, Illinois, Maryland, New Jersey, Pennsylvania, West Virginia, Ohio, Virginia and the District of Columbia. The Distribution Companies have adopted PJM’s transmission pricing methodology, including PJM’s congestion management system.

 

The Distribution Companies have long-term contracts with AE Supply under which AE Supply provides the Distribution Companies with a majority of the power necessary to meet their PLR retail obligations. These

 

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contracts have both fixed-price and market-based pricing components. The amount of power purchased under these contracts subject to the market-based pricing component increases each year through the applicable transition period. Not all of these costs can be passed on to customers.

 

Allegheny has a generation fleet that is anchored by 10 base-load coal-fired units. Most of Allegheny’s generation assets participate in the PJM system. The Generation and Marketing segment sells the power that it generates into PJM and purchases through PJM the power necessary to meet its obligations to the Distribution Companies. Historically, the Distribution Companies’ PLR obligations have absorbed the majority of Allegheny’s generation capacity. The Generation and Marketing segment sells power into PJM at prices determined through a competitive bidding process. The prices that it receives in the PJM market vary depending upon demand and other market conditions. Prices generally are higher at times of peak demand and lower during off-peak periods.

 

PJM directs, or “dispatches,” individual generation stations within its system to produce power. Depending on market conditions, line congestion, plant availability and other factors across the PJM system, an individual generation station within PJM may be available but may not be dispatched, if power is available from another station at a lower cost. Thus, at any given time, the Generation and Marketing segment’s generation facilities may or may not be dispatched, without regard to the PLR or other obligations of the Distribution Companies.

 

Challenges and Response

 

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

 

Beginning in 2002, difficult market conditions, changes in the regulatory environment and Allegheny’s worsening credit profile placed Allegheny in a weakened financial position, which continued during 2003 and into 2004. Beginning in 2003, Allegheny’s new senior management implemented recovery plans and new long-term strategies.

 

Allegheny’s long-term strategy is to focus on its core generation and T&D businesses. Allegheny’s management believes that this emphasis will enable Allegheny to take advantage of its regional presence, operational expertise and market knowledge. Specific goals for enhancing long-term value include:

 

    Restoring Financial Strength.  Beginning in 2003, Allegheny significantly improved its liquidity and overall financial strength. Allegheny’s management believes that it can continue this trend by:

 

    Focusing on the Core Business.  Allegheny has reoriented its business to focus on its core businesses and assets. In 2003, Allegheny exited its speculative trading activities in the Western U. S. and other energy markets. In addition, Allegheny has sold, or is seeking to sell, non-core assets.

 

    Substantially Reducing and Proactively Managing Debt.  Between December 1, 2003 and January 31, 2005, Allegheny repaid approximately $1.2 billion of debt. Allegheny’s goal is to reduce its debt by an additional $300 million by the end of 2005. Allegheny intends to continue its debt reduction efforts by applying some of its cash flow from operations and the proceeds from asset sales to the repayment of debt. The extent to which Allegheny utilizes these alternatives will depend upon the terms that are available to it and their impact on its financial condition, long-term value and overall strategy.

 

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    Improving Liquidity.  Allegheny is improving its liquidity through prudent cash management, opportunistic sales of non-core assets, cutting costs and expenses, extending debt maturities and obtaining a revolving credit facility. For example, in December 2004, AE Supply completed the sale of its Lincoln Generating Facility and an accompanying tolling agreement for $175.0 million in cash, subject to certain post-closing adjustments. Also in December 2004, AE sold a portion of its interest in OVEC for $102 million in cash, $96 million of which was received at the closing of the transaction and the remaining $6 million of which is expected to be paid after March 13, 2006, upon the satisfaction of certain conditions. The proceeds from these transactions were used to repay debt. AE and AE Supply also completed refinancings in 2004 that extended the maturities and lowered the interest rates of much of their debt and established a revolving credit facility for AE. See “Financial Condition, Requirements and Resources—Liquidity and Capital Requirements.”

 

    Maximizing Operational Efficiency.  Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation plants. In addition, Allegheny is seeking to optimize operations and maintenance costs for its generation facilities and T&D assets and related corporate functions, to reduce costs and to pursue other productivity improvements necessary to build a high-performance organization.

 

    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-based rates for AE Supply and its subsidiaries.

 

    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.

 

    Rebuilding the Management Team.  Allegheny rebuilt its management team in 2003 and 2004.

 

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 2004, 2003 and 2002 was as follows:

 

     2004

   2003

   2002

Revenue per MWh sold

   $ 54.48    $ 54.44    $ 54.25

 

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

 

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

 

Heating degree-days (“HDD”) and cooling degree-days (“CDD”).    HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65 degrees Fahrenheit, which is considered normal. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65 degrees Fahrenheit. The regulated utility operations of the Distribution

 

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Companies are weather sensitive. Weather conditions directly influence the customer demand for electricity (or natural gas) delivered by the regulated utility. In addition, regulated utility rates are determined, in part, on the basis of expected normal weather conditions. Accordingly, deviations in weather from normal levels can affect Allegheny’s financial performance. 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. The following table shows actual HDD and CDD for the years indicated:

 

     2004

   2003

   2002

HDD

   5,205    5,622    5,182

CDD

   789    663    1,091

 

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:

 

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

 

Equivalent availability factor (“EAF”).    The EAF is a measure of a generation unit’s availability to generate electricity. 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 psi. This design characteristic enables these units to be larger and more efficient than other generation units. Fort Martin, Harrison, Hatfield’s Ferry and Pleasants are supercritical units. These units generally operate at high capacity for extended periods of time.

 

Station operations and maintenance costs (“Station O&M”).    Station O&M includes base maintenance, operations and special maintenance. Base maintenance and operations costs consist of normal recurring expenses related to the day-to-day on-going operation of the generation station. Special maintenance includes outage, outage related or system projects that relate to all of the generation stations. In addition, special maintenance includes cost of removal and loss from retirement of assets of the unregulated portion of the Generation and Marketing segment.

 

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

 

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

 

     2004

    2003

    2002

 

All Generation Units:

                        

kWhs generated (in millions)

     46,162       48,334       50,879  

EAF

     82.4 %     83.8 %     85.8 %

Station O&M: (in millions)

                        

Base

   $ 195.3     $ 218.5     $ 172.4  

Special

     125.5       85.7       79.4  
    


 


 


Total Station O&M

   $ 320.8     $ 304.2     $ 251.8  
    


 


 


Supercritical Units:

                        

kWhs generated (in millions)

     35,731       35,961       38,211  

EAF

     75.6 %     78.1 %     82.2 %

 

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Contracted coal position.    This measure represents the physical quantity of coal available under firm purchase contracts in force, expressed as a percentage of the estimated quantity of coal that will be consumed in future periods. As of February 17, 2005, Allegheny’s contracted coal positions into 2005, 2006 and 2007 were approximately 95%, 65% and 55%, respectively.

 

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), and

 

    labor costs.

 

Operating Statistics

 

The following table provides kWh sales information for electricity.

 

     2004

   2003

   2002

   2004
% Increase
(Decrease)


    2003
% Increase
(Decrease)


 

Delivery and Services:

                           

KWhs sold (in millions)*

   47,222    46,514    46,785    1.5 %   (0.6 )%

Usage per average number of customers (kWhs):

                           

Residential

   12,038    11,835    11,588    1.7 %   2.1 %

Commercial

   59,757    58,713    58,938    1.8 %   (0.4 )%

Industrial

   759,305    749,959    755,962    1.2 %   (0.8 )%

HDD

   5,205    5,622    5,182    (7.4 )%   8.5 %

CDD

   789    663    1,091    19.0 %   (39.2 )%

*   includes retail and wholesale and other

 

Generation and Marketing:

                           

KWhs generated (in millions)

   46,162    48,334    50,879    (4.5) %   (5.0) %

 

The following table provides cubic feet sales information, excluding transportation and wholesale for the natural gas operations, which are reflected in discontinued operations at December 31, 2004.

 

     2004

   2003

   2002

  

2004

% Increase

(Decrease)


   

2003

% Increase

(Decrease)


 

Delivery and Services:

                           

Natural gas sales (Bcf)

   27.2    29.6    26.8    (8.1 )%   10.4 %

 

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Critical Accounting Estimates

 

The following represent the critical accounting estimates for Allegheny and its consolidated subsidiaries, where applicable.

 

Use of Estimates:  The preparation of financial statements in accordance with GAAP requires Allegheny to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the period covered. The estimates that require management’s most difficult, subjective and complex judgments involve the fair value of commodity contracts and derivative instruments, goodwill, unbilled revenues, regulatory assets and liabilities, pension and other postretirement benefit costs, long-lived assets and contingent liabilities. Significant changes in these estimates could have a material effect on Allegheny’s consolidated results of operations, cash flows and financial position.

 

Commodity Contracts:  Allegheny has commodity contracts that are recorded at their fair value. Changes in the fair value of these contracts are recognized in earnings under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133—an amendment of FASB Statement No. 133,” (“SFAS No. 137”), SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities—an amendment of FASB Statement No. 133,” (“SFAS No. 138”) and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” (“SFAS No. 149”) (collectively referred to as “SFAS No. 133”). Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. Management estimates the fair value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options and swaps, using available and estimated market data and pricing models. These estimates may change from time to time.

 

Inputs to the pricing models may include estimated forward natural gas and electricity prices, interest rates, estimates of market volatility for natural gas and electricity prices, the correlation of natural gas and electricity prices and other factors, such as generation unit availability and location, as appropriate. These inputs require significant judgments and assumptions. Allegheny also adjusts the fair value of commodity contracts to reflect uncertainty in prices, operational risks related to generation facilities and risks related to the performance of counterparties. These inputs and adjustments become more challenging, and the models become less precise, the further into the future these estimates are made. Actual effects on Allegheny’s consolidated financial position, cash flows and results of operations may vary significantly from expected results if the judgments and assumptions underlying the inputs to these models are wrong or the models prove to be unreliable.

 

During 2003, Allegheny exited its trading positions in the Western U.S. and other national energy markets. In conjunction with its exit from these positions, Allegheny recognized significant realized and unrealized losses during 2003. As of December 31, 2004, the majority of the fair value included in Allegheny’s trading portfolio was related to interest rate swap agreements and commodity cash flow hedges.

 

Allegheny’s accounting for commodity contracts is discussed in Note 5, “Wholesale Energy Activities,” to the Consolidated Financial Statements. Also, see Note 10, “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):  As of December 31, 2004, Allegheny’s intangible asset for acquired goodwill was $367.3 million related to the acquisition of its energy marketing and trading business from Merrill Lynch in March 2001. Allegheny tests goodwill for impairment at least annually. In 2002, Allegheny recorded a goodwill impairment charge of $130.5 million related to its Delivery and Services segment. The estimation of the fair value of Allegheny’s reporting units (an operating segment or one level below an operating segment) involves the use of present value measurements and cash flow models. This process

 

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involves judgments on a broad range of information, including, but not limited to, market pricing assumptions for future electricity revenues, future generation output and projected operating expenses and capital expenditures. Significant changes in the fair value estimates could have a material effect on Allegheny’s results of operations and financial position.

 

Unbilled Revenues:  Unbilled revenues are primarily associated with the Distribution Companies. Energy sales to individual customers are based on their meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of energy delivered to each customer after the last meter reading is estimated, and the Distribution Companies recognize unbilled revenues related to these amounts. The unbilled revenue estimates are based on daily generation, purchases of electricity and natural gas, estimated customer usage by customer type, weather effects, electric and natural gas line losses and the most recent consumer rates. A significant change in these estimates and assumptions could have a material effect on Allegheny’s consolidated results of operations and financial position.

 

Regulatory Assets and Liabilities:  The Distribution Companies charge cost-based rates that are regulated by various federal and state regulatory agencies. As a result, the Distribution Companies qualify for the application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”), which recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets or liabilities arise as a result of a difference between GAAP, excluding the effects of rate regulation, and the economic effect of decisions by regulatory agencies. Regulatory assets generally represent incurred costs that have been deferred, because they are likely to be recovered through customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for various reasons.

 

The Distribution Companies recognize regulatory assets and liabilities in accordance with the rulings of their federal and state regulators. Future regulatory rulings may affect the carrying value and accounting treatment of Allegheny’s regulatory assets and liabilities at each balance sheet date. Allegheny assesses whether the regulatory assets are likely to be recovered in the future by considering factors such as changes in the regulatory environment, recent rate orders issued by the applicable regulatory agencies and the status of any pending or potential deregulation legislation. Assumptions and judgments used by regulatory authorities continue to have an effect on the recovery of costs, the rate of return on invested capital and the timing and amount of assets to be recovered by rates. A change in these assumptions may have a material effect on Allegheny’s results of operations, cash flows and financial position.

 

Accounting for Pensions and Postretirement Benefits Other Than Pensions:  Allegheny accounts for pensions under SFAS No. 87, “Employers’ Accounting for Pensions,” (“SFAS No. 87”) and other postretirement benefits under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” (“SFAS No. 106”). Under these rules, certain assumptions are made that represent significant estimates. There are many factors and significant assumptions involved in determining Allegheny’s pension and other postretirement benefit obligations (“OPEB”) and costs each period, such as employee demographics (including, among others, age, life expectancies and compensation levels), 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. See Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to the Consolidated Financial Statements for additional information concerning these assumptions. 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.

 

In determining its net periodic cost for pension benefits and for OPEB for 2004, Allegheny utilized a 6.0% discount rate and an expected long-term rate of return on plan assets of 8.5%. The discount rate for 2003 was 6.5%, and the expected long-term rate of return on plan assets for 2003 was 9.0%. The expected long-term rate of return on plan assets and the discount rate used to develop the net periodic benefit costs for 2005 are 8.5% and 5.9%, respectively. See Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to the Consolidated Financial Statements for additional assumptions used in determining net periodic benefit costs for these benefit plans.

 

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In determining its liability, also referred to as the “benefit obligation,” for OPEB at September 30, 2004 (the measurement date), Allegheny utilized a 5.9% discount rate and an expected long-term rate of return on plan assets of 8.5%. The discount rate was 6.0% in 2003. The expected long-term rate of return on plan assets was 8.5% in 2003. See Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to the Consolidated Financial Statements for additional assumptions used in determining the benefit obligations for these benefit plans.

 

In selecting an assumed discount rate, Allegheny reviews various Aa bond yields. Allegheny also performs a yield-curve equivalent rate analysis to derive the discount rate that most accurately matches the observed yields in the market for various maturities of debt to the duration of our liabilities. The 8.5% expected rate of return on plan assets for 2005 is based on projected long-term equity and bond returns and asset allocations. The following table shows the effect that a one percentage point increase or decrease in the 5.9% discount rate and the 8.5% expected rate of return on plan assets for 2005 would have on Allegheny’s pension and other postretirement benefits obligations and costs:

 

(In millions)


   1-Percentage-Point
Increase


   

1-Percentage-Point

Decrease


Change in the discount rate:

              

Pension and OPEB benefit obligation

   $ (148.3 )   $ 181.2

Net periodic pension and OPEB cost

   $ (11.4 )   $ 13.8

Change in expected rate of return on plan assets:

              

Net periodic pension and OPEB cost

   $ (8.8 )   $ 8.8

 

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

 

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

 

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ALLEGHENY ENERGY, INC.—RESULTS OF OPERATIONS

 

Income (Loss) Summary

 

(In millions)


  

Delivery
and

Services


   

Generation

and

Marketing


             

2004


       Eliminations

    Total

 

Operating revenues

   $ 2,764.1     $ 1,538.7     $ (1,546.7 )   $ 2,756.1  

Fuel consumed in electric generation

     —         (614.4 )     —         (614.4 )

Purchased power and transmission

     (1,779.0 )     (86.2 )     1,536.8       (328.4 )

Gain on sale of OVEC power agreement and shares

     —         94.8       —         94.8  

Deferred energy costs, net

     (0.2 )     —         —         (0.2 )

Operations and maintenance

     (404.3 )     (424.1 )     9.9       (818.5 )

Depreciation and amortization

     (148.8 )     (150.6 )     —         (299.4 )

Taxes other than income taxes

     (128.5 )     (72.3 )     —         (200.8 )
    


 


 


 


Operating income

     303.3       285.9       —         589.2  

Other income and (expenses), net

     23.1       1.7       (0.3 )     24.5  

Interest expense and preferred dividends

     (129.2 )     (276.2 )     0.2       (405.2 )
    


 


 


 


Income (loss) 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

     —         0.9       —         0.9  
    


 


 


 


Income (loss) from continuing operations

     117.3       12.5       (0.1 )     129.7  

(Loss) income from discontinued operations, net of tax

     (14.0 )     (426.4 )     0.1       (440.3 )
    


 


 


 


Net income (loss)

   $ 103.3     $ (413.9 )   $ —       $ (310.6 )
    


 


 


 


2003


                        

Operating revenues

   $ 2,705.8     $ 956.2     $ (1,479.7 )   $ 2,182.3  

Fuel consumed in electric generation

     —         (592.0 )     —         (592.0 )

Purchased power and transmission

     (1,709.2 )     (76.1 )     1,472.4       (312.9 )

Deferred energy costs, net

     1.6       —         —         1.6  

Operations and maintenance

     (454.5 )     (538.2 )     7.3       (985.4 )

Depreciation and amortization

     (152.2 )     (134.0 )     —         (286.2 )

Taxes other than income taxes

     (128.1 )     (75.8 )     —         (203.9 )
    


 


 


 


Operating income (loss)

     263.4       (459.9 )     —         (196.5 )

Other income and (expenses), net

     42.1       63.9       —         106.0  

Interest expense and preferred dividends

     (126.8 )     (301.0 )     —         (427.8 )
    


 


 


 


Income (loss) from continuing operations before income taxes and minority interest

     178.7       (697.0 )     —         (518.3 )

Income tax (expense) benefit from continuing operations

     (76.1 )     278.3       —         202.2  

Minority interest in net loss

     —         7.2       —         7.2  
    


 


 


 


Income (loss) from continuing operations

     102.6       (411.5 )     —         (308.9 )

Income (loss) from discontinued operations, net of tax

     9.2       (34.5 )     —         (25.3 )

Cumulative effect of accounting change, net of tax

     (1.2 )     (19.6 )     —         (20.8 )