SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000



Commission
File Number

Registrant;
State of Incorporation;
Address; and Telephone Number


I.R.S. Employer
Identification Number

1-267

ALLEGHENY ENERGY, INC.
(A Maryland Corporation)
10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400

13-5531602

   
   
   
   

1-5164

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

13-5229392

   
   
   
   

1-3376-2

THE POTOMAC EDISON COMPANY
(A Maryland and Virginia
Corporation)

10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400

13-5323955

   
   
   
   

1-255-2

WEST PENN POWER COMPANY
(A Pennsylvania Corporation)
800 Cabin Hill Drive
Greensburg, Pennsylvania 15601
Telephone (724) 837-3000

13-5480882

   
   
   
   

0-14688

ALLEGHENY GENERATING COMPANY
(A Virginia Corporation)
10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400

13-3079675

   
   
   

ALLEGHENY GENERATING COMPANY MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM WITH REDUCED DISCLOSURE FORMAT.

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. [X]


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


Registrant


Title of each class

Name of which exchange
on which registered

Allegheny Energy, Inc.

Common Stock,
$1.25 par value

New York Stock Exchange
Chicago Stock Exchange
Pacific Stock Exchange
Amsterdam Stock Exchange

     

Monongahela Power Company

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



American Stock Exchange
American Stock Exchange

     
 

8% Quarterly Income
Debt Securities,
Junior Subordinated
Deferrable Interest
Debentures,
Series A



New York Stock Exchange

     

The Potomac Edison Company

8% Quarterly Income
Debt Securities,
Junior Subordinated
Deferrable Interest
Debentures,
Series A



New York Stock Exchange

     

West Penn Power Company

8% Quarterly Income
Debt Securities,
Junior Subordinated
Deferrable Interest
Debentures,
Series A



New York 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 stock (common stock) held by nonaffiliates of the registrants at March 1, 2001


Number of shares of common stock of the registrants outstanding at March 1, 2001

     

Allegheny Energy, Inc.

$5,228,055,247

110,436,317
($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)

     

West Penn Power Company

None. (a)

24,361,586

     

Allegheny Generating Company

None. (b)

1,000
($1.00 par value)

(a) All such common stock is held by Allegheny Energy, Inc., the parent company.
(b) All such common stock is held by its parents, Monongahela Power Company and Allegheny
Energy Supply Company, LLC.


CONTENTS

PART I:

 

Page

     

ITEM 1.

Business

1

 

Factors That May Affect Future Results

4

 

Electric Energy Competition

4

 

Activities at the Federal Level

5

 

Activities at the State Level

5

 

Allegheny's Competitive Actions

9

 

Telecommunications

12

 

Sales

14

 

Regulated Electric Sales

14

 

Unregulated Sales

17

 

Regulated Gas Sales

17

 

Regulatory Framework Affecting Power Sales

17

 

Electric Facilities

19

 

Allegheny Map

23

 

Research and Development

25

 

Capital Requirements and Financing

26

 

Financing Programs

30

 

Fuel Supply

33

 

Rate Matters

36

 

Environmental Matters

41

 

Air Standards

41

 

Water Standards

44

 

Hazardous and Solid Wastes

46

 

Toxic Release Inventory (TRI)

47

 

Global Climate Change

48

 

Regulation

49

     

ITEM 2.

Properties

50

     

ITEM 3.

Legal Proceedings

50

     

ITEM 4.

Submission of Matters to a Vote of Security Holders

53

     

PART II:

   
     

ITEM 5.

Market for the Registrants' Common Equity and Related
Shareholder Matters


60

     

ITEM 6.

Selected Financial Data

61

     

ITEM 7.

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


62

     

ITEM 7A

Quantitative and Qualitative Disclosure About Market Risk

62

     

PART III:

   
     

ITEM 8.

Financial Statements and Supplementary Data

64

     

ITEM 9.

Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure


71

     

ITEM 10.

Directors and Executive Officers of the Registrants

71

     

ITEM 11.

Executive Compensation

73

     

ITEM 12.

Security Ownership of Certain Beneficial Owners and Management

80

     

ITEM 13.

Certain Relationships and Related Transactions

81

     

PART IV:

   
     

ITEM 14.

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

81

1

 

THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY ENERGY, INC., MONONGAHELA POWER COMPANY, THE POTOMAC EDISON COMPANY, WEST PENN POWER COMPANY, AND ALLEGHENY GENERATING COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.

 

PART I

ITEM 1. BUSINESS

 

     Allegheny Energy, Inc. (AE), incorporated in Maryland in 1925, is a diversified utility holding company, which owns, directly and indirectly, various regulated and non-regulated subsidiaries (collectively and generically, Allegheny). For the fiscal year ended December 31, 2000, AE had total revenues of $4,012 million, earnings before interest, income taxes, depreciation and amortization of $969 million, and operating income of $536 million.

 

    AE conducts its business through its direct and indirect wholly-owned subsidiaries. Monongahela Power Company (Monongahela), The Potomac Edison Company (Potomac Edison) and West Penn Power Company (West Penn) are electric distribution (or delivery) companies (the Distribution Companies). Allegheny Energy Supply Company, LLC (Allegheny Energy Supply) is an unregulated electric supply company that is expanding its electric generation fleet. Allegheny Ventures, Inc. (Allegheny Ventures) is an unregulated company that develops and operates telecommunications and energy-related businesses through its subsidiaries. Allegheny Generating Company (AGC) is an indirect subsidiary whose only asset is an undivided interest in a pumped-storage hydro-electric station. AE also owns exempt wholesale generation (EWG) subsidiaries. The properties of Allegheny Energy Supply are located in Maryland, Pennsylvania and West Virginia. The properties of the Distribution Companies and AGC are located in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia; are interconnected; and are located along transmission facilities owned in whole or part by the Distribution Companies, which are interconnected with all neighboring utility systems. The Distribution Companies are doing business under the trade name Allegheny Power.

 

     Monongahela, incorporated in Ohio in 1924, operates its electric distribution system in northern West Virginia and an adjacent portion of Ohio. It owns generating capacity in West Virginia and Pennsylvania. In all jurisdictions, Monongahela is doing business under the trade name Allegheny Power. Including the assets of West Virginia Power, which was acquired by Monongahela in 1999, Monongahela serves about 358,000 electric customers and 24,000 natural gas customers in a service area of about 13,000 square miles with a population of about 815,000. The seven largest communities served have populations ranging from 10,900 to 33,900. This service area has navigable waterways and substantial deposits of bituminous coal, glass sand, natural gas, rock salt, and other natural resources. Its service area's principal industries produce coal, chemicals, iron and steel, fabricated products, wood products, and glass. There are two municipal electric distribution systems and two rural electric cooperative associations in its electric service territory. Except for one of the cooperatives, in 2000 they

2

purchased all of their power from Monongahela.
 

     In August 2000, Monongahela acquired all of the outstanding stock of Mountaineer Gas Company (Mountaineer), a natural gas distribution company incorporated in West Virginia. Mountaineer serves approximately 205,000 retail natural gas customers in West Virginia. Mountaineer owns approximately 4,000 miles of natural gas distribution pipelines. During 2000, Mountaineer sold or transported 57 billion cubic feet (Bcf) of gas. The Mountaineer acquisition also included the acquisition of Mountaineer's unregulated subsidiary, Mountaineer Gas Services (MGS). MGS operates natural gas producing properties, gas gathering facilities, and intra-state transmission pipelines and is engaged in the sale and marketing of natural gas in the Appalachian basin. MGS owns more than 375 natural gas wells and has a net revenue interest in about 100 wells of which it is not the operator.

 

     Potomac Edison, incorporated in Maryland in 1923 and in Virginia in 1974, operates its electric distribution system in portions of Maryland, Virginia, and West Virginia. In all jurisdictions, Potomac Edison is doing business under the trade name Allegheny Power. Potomac Edison serves about 402,000 electric customers in a service area of about 7,300 square miles with a population of about 782,000. In August 2000, Potomac Edison transferred its generation assets and its interest in AGC to Allegheny Energy Supply pursuant to state legislation and regulatory proceedings. See the discussion of the transfer below under Allegheny Energy Supply, and in ITEM 1. RATE MATTERS. The six largest communities served have populations ranging from 11,900 to 40,100. Potomac Edison's service area's principal industries produce aluminum, cement, fabricated products, rubber products, sand, stone, and gravel. There are four municipal electric distribution systems in its service area, all of which purchased power from Potomac Edison in 2000, and six rural electric cooperatives, one of which purchased power from Potomac Edison in 2000.

 

     West Penn, incorporated in Pennsylvania in 1916, operates its electric distribution system in southwestern and north and south-central Pennsylvania. West Penn is doing business under the trade name Allegheny Power. West Penn serves about 681,000 electric customers in a service area of about 9,900 square miles with a population of about 1,399,000. In November 1999, West Penn transferred its generation assets and its interest in AGC to Allegheny Energy Supply pursuant to state legislation and regulatory proceedings. The 10 largest communities served by West Penn have populations ranging from 11,200 to 38,900. West Penn's service area has navigable waterways and substantial deposits of bituminous coal, limestone, and other natural resources. Its service area's principal industries produce steel, coal, fabricated products, and glass.

 

     Allegheny Energy Supply, incorporated in Delaware in 1999, owns and operates and has contract access to generating capacity in Maryland, Pennsylvania and West Virginia. Allegheny Energy Supply also owns an undivided interest in AGC. On August 1, 2000, Potomac Edison transferred approximately 2,100 MW of its Maryland, Pennsylvania and West Virginia generation assets to Allegheny Energy Supply, as well as its ownership interest in AGC. Certain of Potomac Edison's small hydroelectric facilities

3

located in Virginia will be transferred to a subsidiary of AE Supply in 2001. The transfer of Potomac Edison's generation assets reflects the initiation of a customer choice program in Maryland and a pending customer choice program in Virginia. Assets were leased back to Potomac Edison in amounts sufficient to satisfy customers in West Virginia not yet able to shop for alternative suppliers. The lease will remain in place until customers have an opportunity to choose. AYP Energy, Inc., a wholly-owned subsidiary of Allegheny Ventures, transferred its unregulated generation asset to Allegheny Energy Supply in 1999. In November 1999, West Penn also transferred its generating assets to Allegheny Energy Supply, including its ownership interest in AGC. Until January 2, 2000, West Penn continued to supply electricity to one-third of its retail load that was not able to choose its generating supplier. Allegheny Energy Supply leased back to West Penn an amount of generating assets sufficient for West Penn to satisfy that load. Allegheny Energy Supply sells retail electric energy throughout Pennsylvania and Maryland (excluding by temporary regulatory proscription those customers with locations wholly inside West Penn's and Potomac Edison's service area) and in other states throughout the region that have customer choice, and wholesale electric energy anywhere.
 

     AGC, organized in 1981 under the laws of Virginia, is jointly owned as follows: Monongahela, 27% and Allegheny Energy Supply, 73%. AGC has no employees, and its only asset is a 40% undivided interest in the Bath County (Virginia) pumped-storage hydroelectric station, which was placed in commercial operation in December 1985, and its connecting transmission facilities. AGC's 840-megawatt (MW) share of capacity of the station is sold to its two parents. The remaining 60% interest in the Bath County Station is owned by Virginia Electric and Power Company (Virginia Power).

 

    Allegheny Ventures, incorporated in Delaware in 1994, is a wholly-owned non-regulated subsidiary of AE. Allegheny Ventures has three wholly-owned subsidiaries--AYP Energy, Inc. (AYP Energy), Allegheny Communications Connect, Inc. (ACC), and Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions), all Delaware corporations. Allegheny Ventures recently filed with the Securities and Exchange Commission (SEC) to purchase Leasing Technologies International, Inc., a privately held leasing and financing company which provides financial services to entities engaged in telecommunications, software, internet, and other technologies. On February 13, 2001, Allegheny Ventures acquired a 10% equity interest in Utility Associates, Inc., a software development company that creates integrated mobile computing solutions for the utility industry. Allegheny Ventures is also part owner of APS Cogenex, a limited liability company formed with EUA Cogenex. APS Cogenex ceased its marketing activities in 1996 and is concluding existing projects. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Significant Events in 2000, 1999, and 1998 for a further description of Allegheny Ventures and its subsidiaries' activities.)

 

     Allegheny Energy Service Corporation (AESC), a wholly-owned subsidiary of AE, was incorporated in Maryland in 1963. AE, Allegheny Energy Supply, the Distribution Companies, AGC, Allegheny Ventures and their subsidiaries have no employees. Their officers and non-officers are employed by AESC. AESC's employees provide all necessary services to AE, Allegheny Energy

4

Supply, the Distribution Companies, AGC, Allegheny Ventures and their subsidiaries. Those companies reimburse AESC for services provided by AESC's employees. On December 31, 2000, AESC had approximately 5,600 employees.

Factors That May Affect Future Results

 

     In addition to the historical information contained herein, this report contains a number of "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. These include statements with respect to deregulation activities and movements toward competition in states served by the Distribution Companies, capital expenditures, earnings on assets, resolution and impact of litigation, regulatory matters, liquidity and capital resources, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

 

     Factors that could cause actual results to differ materially include, among other matters, electric utility restructuring, including ongoing state and federal activities; developments in the legislative, regulatory, and competitive environments in which Allegheny operates, including regulatory proceedings affecting rates charged by AE's subsidiaries; environmental, legislative, and regulatory changes; future economic conditions; earnings retention and dividend payout policies; Allegheny's ability to compete in unregulated energy markets; and other circumstances that could affect anticipated revenues and costs such as significant volatility in the market price of wholesale power and fuel for electric generation, unscheduled maintenance or repair requirements, weather, and compliance with laws and regulations. In addition, factors include significant volatility in the California energy market with respect to electricity and natural gas prices.

 

Electric Energy Competition

 

     The electricity supply segment of the electric utility industry in the United States continues to become more competitive. The Energy Policy Act of 1992 began the process of deregulating the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over utilities' transmission systems. Since 1992, the wholesale electricity market has become increasingly competitive. In addition, more states have taken active steps toward allowing retail customers the right to choose their electricity supplier. Allegheny has been an advocate of federal legislation to create competition in the retail electricity markets to avoid regional dislocations and ensure level playing fields.

 

     In the absence of federal legislation, state-by-state implementation continues. All of the states the Distribution Companies serve are at various stages of implementation of programs allowing customers to choose their electric generation service supplier. Pennsylvania and Maryland are the furthest along with competitive retail programs fully in place. Ohio began offering retail choice to its residents on January 1, 2001. Virginia passed legislation in 1999 to implement some level of retail choice by 2002. In March 2000, the West Virginia Legislature approved a plan to implement

5

customer choice, with implementation delayed pending future legislative authorization of implementation and enactment of certain tax and other changes. Those changes will be studied by the West Virginia legislature in 2001. The future of competitive choice in West Virginia is therefore uncertain.

Activities at the Federal Level

 

     Allegheny continues to seek enactment of federal legislation to bring choice to all retail electric customers, deregulate the generation and sale of electricity on a national level, and create a more liquid, free market for electric power. Fully meeting challenges in the emerging competitive environment will be difficult for Allegheny unless certain outmoded and anti-competitive laws, specifically the Public Utility Holding Company Act of 1935 (PUHCA) and Section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA) regarding mandatory power purchase provisions, are repealed or significantly revised. Allegheny continues to advocate the repeal of PUHCA and PURPA on the grounds that they are obsolete and anti-competitive, and that PURPA results in utility customers paying above-market prices for power. In the 106th Congress, a number of electric utility restructuring bills were considered, many of which addressed PUHCA repeal and PURPA reform, among other issues. A stand-alone reliability bill was not taken up in the House after passage in the Senate. A comprehensive restructuring bill died in the House Commerce Committee upon adjournment late in 2000. It is uncertain whether legislation addressing electric utility restructuring will be forthcoming in the 107th Congress.

Activities at the State Level

 

Maryland

 

     On April 8, 1999, Maryland Governor Glendening signed legislation that brought competition to Maryland's electric supply market.

 

     On December 23, 1999, the Maryland Public Service Commission (Maryland PSC) issued an Order approving a consensus settlement agreement in Potomac Edison's Maryland restructuring case. On March 15, 2000 the Maryland PSC issued a Supplemental Order elaborating on the basis for approval of the settlement agreement. The settlement agreement, which provided that all of Potomac Edison's retail customers would have generation supply choice effective July 1, 2000, included a decision that dollar for dollar recovery of the AES Warrior Run purchased power costs was due Potomac Edison and that generation assets could be transferred to an affiliate at book value. Potomac Edison transferred its Maryland generation assets at book value to Allegheny Energy Supply on August 1, 2000. The transmission and distribution assets remain with Potomac Edison and under regulated ratemaking. Potomac Edison has responsibility as the electricity provider of last resort (for those customers of Potomac Edison who choose not to select an alternate supplier or whose alternate supplier does not deliver). Pursuant to contracts, Allegheny Energy Supply supplies Potomac Edison with power during the Maryland transition period. Under these contracts, Allegheny Energy Supply provides Potomac Edison with the amount of electricity, up to its retail load, that it may demand. These contracts (and those that Allegheny

6

Energy Supply has with West Penn) represent a significant portion of the normal operating capacity of Allegheny Energy Supply's generating assets that were previously owned by West Penn and Potomac Edison.
 

     Allegheny Energy Supply will market the deregulated generation to the retail and wholesale markets, with the restriction that it may not market to retail customers within Potomac Edison's Maryland territory for various time frames, some of which terminate at the end of 2003. On April 5, 2000, the Maryland PSC granted Allegheny Energy Supply a license to operate as a provider of electric generation supply and services in Maryland.

 

     On July 1, 2000, the Maryland PSC issued a restrictive order imposing standards of conduct for transactions between Maryland utilities and their affiliates. Among other things, the order: restricts sharing of employees between utilities and affiliates; announces the Maryland PSC's intent to impose a royalty fee to compensate the utility for the use by an affiliate of the utility's name and/or logo and for other "intangible or unquantified benefits"; and requires asymmetric pricing for asset transfers between utilities and their affiliates. Asymmetric pricing requires that transfers of assets from the regulated utility to an affiliate be recorded at the greater of book cost or market value while transfers of assets from the affiliate to the regulated utility be recorded at the lesser of book cost or market. This order did not apply to the transfer of Potomac Edison's generation assets to Allegheny Energy Supply. Asymetric pricing also does not apply to the generation supply contract between Potomac Edison and Allegheny Energy Supply.

 

     Potomac Edison, along with substantially all of Maryland's gas and electric utilities, filed a Circuit Court petition for judicial review and a motion for stay of the restrictive order. In November 2000, the Circuit Court granted a partial stay of the Maryland PSC's code of conduct/affiliated transactions order on the issues of employee sharing, royalties for the use of the name and logo and for certain intangibles, and on the requirement to use a disclaimer on advertising for non-core services. The trial in this case was held on January 25, 2001. The petitioners are awaiting the Judge's order.

Ohio

 

     The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. All of the state's customers became able to choose their electricity supplier on January 1, 2001, starting a five-year transition to market rates. Two utilities, including Monongahela, have a shorter transition period for larger customers. Ohio's residential customers were guaranteed a 5% reduction in the generation portion of rates by the legislation. The determination of stranded cost recovery was left to the Ohio Public Utilities Commission (Ohio PUC).

 

     Monongahela reached a stipulated agreement with major parties on a transition plan to bring electric choice to its 29,000 Ohio customers. The stipulation was approved by the Ohio PUC on October 5, 2000. The restructuring plan allows Monongahela to transfer its Ohio generating assets to Allegheny Energy Supply at net book value on or after January 1, 2001.

7

Monongahela has responsibility as the electricity provider of last resort (for those customers of Monongahela who choose not to select an alternate supplier or whose alternate supplier does not deliver). Pursuant to contracts, Allegheny Energy Supply will supply Monongahela with power during the Ohio transition period. Under this contract, Allegheny Energy Supply will provide Monongahela with the amount of electricity, up to its retail load, that it may demand. This contract (and those that Allegheny Energy Supply has with Potomac Edison and West Penn) represent a significant portion of the normal operating capacity of Allegheny Energy Supply's generating assets that were previously owned by West Penn and Potomac Edison. The Ohio assets have not yet been transferred; however, Monongahela expects to transfer these assets in April, 2001.
 

     On November 7, 2000, the Ohio PUC granted Allegheny Energy Supply a certificate as a Competitive Retail Electric Service Provider in Ohio.

Pennsylvania

 

     The Customer Choice Act in Pennsylvania provides for customer choice of electric supplier and deregulation of generation in a competitive electric supply market. As of January 2, 2000, all electricity customers in Pennsylvania had the right to choose their electric suppliers. Over 100 electric suppliers have been licensed to sell to retail customers in Pennsylvania. Pursuant to the Customer Choice Act, in November 1999, West Penn transferred its generation assets to Allegheny Energy Supply. The transmission and distribution assets remain with West Penn and under regulated ratemaking.

 

     West Penn has responsibility as the electricity provider of last resort (for those customers of West Penn who choose not to select an alternate supplier or whose alternate supplier does not deliver). Pursuant to contracts, Allegheny Energy Supply supplies West Penn with power during the Pennsylvania transition period. Under this contract, Allegheny Energy Supply provides West Penn with the amount of electricity, up to its retail load, that it may demand. These contracts (and those that Allegheny Energy Supply has with Potomac Edison) represent a significant portion of the normal operating capacity of Allegheny Energy Supply's generating assets that were previously owned by West Penn and Potomac Edison.

Virginia

 

     The Virginia Electric Utility Restructuring Act (the Act) was enacted in March 1999, and provides for a transition to customer choice of electric suppliers for Virginia customers beginning January 1, 2002. All Virginia customers will have choice by January 1, 2004. The Act provides for rate caps from January 1, 2001 to July 1, 2007, with recovery of stranded costs and transition costs during the rate cap period through capped rates and a wires charge mechanism. Supply of electric energy is deregulated effective January 1, 2002, except as otherwise provided in the Act. The Act requires functional separation of generation, retail transmission, and distribution by January 1, 2002. The Act also requires the joining or establishment of a regional transmission entity by January 1, 2002 to which management and control of the transmission system shall be transferred.

8

 

     On July 11, 2000 the Virginia State Corporation Commission (Virginia SCC) issued an Order approving Potomac Edison's Phase I separation plan and permitting the transfer of Potomac Edison's generation assets to Allegheny Energy Supply. Potomac Edison transferred its generation assets to Allegheny Energy Supply on August 1, 2000. Potomac Edison will transfer four small Virginia hydroelectric facilities to a subsidiary of Allegheny Energy Supply in 2001. Consistent with Virginia SCC regulations, Potomac Edison filed Phase II of its functional separation plan on December 19, 2000.

 

     The Virginia SCC adopted regulations governing the transfer of ownership or control of transmission facilities to a Regional Transmission Organization. On October 16, 2000, Potomac Edison filed with the Virginia SCC a copy of the October 16 FERC Order 2000 RTO Compliance Filing regarding the PJM West proposal, which would become operational as required by FERC Order 2000 (currently December 15, 2001). See ITEM 1. REGULATORY FRAMEWORK AFFECTING ELECTRIC POWER SALES for more information regarding PJM West.

 

     On September 22, 2000, the Virginia SCC granted a competitive service provider license to Allegheny Energy Supply. The license permits Allegheny Energy Supply to provide competitive electric supply service to all classes of retail customers in conjunction with the ongoing retail access pilot programs of Dominion Virginia Power and American Electric Power-Va.

West Virginia

 

     In March 1998, the West Virginia Legislature passed legislation that directed the West Virginia Public Service Commission (West Virginia PSC) to develop a restructuring plan which would meet the dictates and goals of the legislation. In January 2000, the West Virginia PSC submitted a restructuring plan to the legislature for approval. The plan would have opened full retail competition on January 1, 2001. On March 11, 2000, the West Virginia Legislature approved the West Virginia PSC's plan, but assigned the tax issues surrounding the plan to Committees. The Committees were asked to recommend the necessary tax changes and return to the Legislature in 2001 for approval of those changes and authority to implement the plan. The commencement of competition is contingent upon the legislature approving and implementing the necessary tax changes. The West Virginia PSC is currently in the process of developing the rules under which competition will occur. Allegheny considers it is highly unlikely that the West Virginia legislature will pass, during its 2001 session, the necessary tax law changes related to the deregulation of the wholesale power market in West Virginia. If legislative action is not taken, Monongahela will explore other ways to effect the transfer of its generating assets to Allegheny Energy Supply. Monongahela has filed a petition seeking the West Virginia PSC's approval of its transfer of generating assets to Allegheny Energy Supply. However, the West Virginia PSC has not yet acted on this petition, and Monongahela cannot be sure whether it will be permitted to transfer its generation assets, or when permission might be granted. If the transfer is permitted, Monongahela cannot predict the conditions that may be imposed on Allegheny Energy Supply in connection with the transfer, such as provider-of-last-resort contract obligations, transfer costs or transition periods that may make the transfer uneconomical.

9

 

     On June 23, 2000 the West Virginia PSC approved Potomac Edison's request to transfer Potomac Edison's generating assets to Allegheny Energy Supply on or after July 1, 2000. On August 1, 2000, Potomac Edison transferred its West Virginia assets to Allegheny Energy Supply. Assets are being leased back to Potomac Edison in amounts sufficient to satisfy customers not yet able to shop for alternate suppliers in West Virginia. In accordance with the restructuring agreement, Potomac Edison and Monongahela implemented a commercial and industrial rate reduction program on July 1, 2000. A stipulated agreement reached on September 14, 2000 on the unbundled tariffs filed by Monongahela and Potomac Edison is awaiting a final order from the West Virginia PSC.

 

     The West Virginia PSC has convened a Gas Codes of Conduct Working Group to establish safeguards with respect to the transactions and interactions between gas utilities, their affiliates and competitive gas suppliers; to avoid potential market-power abuses; to eliminate cross-subsidization between regulated and unregulated activities; and to promote effective competition in the natural gas market within West Virginia.

 

Allegheny's Competitive Actions

 

     Over the past several years the Allegheny companies have taken action to deal with deregulation and better position themselves to participate in the new competitive generation supply markets.

 

Allegheny Energy Supply

 

     Allegheny Energy Supply was formed in 1999 to consolidate AE's deregulated generating assets into a single company that is not subject to state regulation of sales prices. As of December 31, 2000, Allegheny Energy Supply owned 6,273 MW of generating assets.

 

     Allegheny Energy Supply is an unregulated energy company that markets competitive wholesale and retail electricity. Allegheny Energy Supply intends to become a national energy merchant company with an additional 4,131 MW of announced additions of generating capacity either through acquisitions or construction of facilities in Arizona, Illinois, Indiana, Tennessee, and Pennsylvania.

 

     Pursuant to contracts, Allegheny Energy Supply supplies West Penn and Potomac Edison with power during the Pennsylvania and Maryland transition periods. Under these contracts, Allegheny Energy Supply provides these regulated electricity distribution affiliates with the amount of electricity, up to their retail load, that they may demand. These contracts represent a significant portion of the normal operating capacity of Allegheny Energy Supply's generating assets that were previously owned by West Penn and Potomac Edison. Allegheny Energy Supply will enter into similar contracts with Monongahela.

 

     In January 2001, Allegheny Energy Supply announced the signing of a definitive agreement to acquire Energy Trading Business, Merrill Lynch's

10

energy commodity marketing and trading unit. The acquisition was completed on March 16, 2001. Allegheny Energy Supply paid Merrill Lynch $490 million and agreed to pay two percent equity interest in Allegheny Energy Supply. Under the agreement, Merrill Lynch will refrain from competing with Allegheny Energy Supply for thirty months.
 

     The Energy Trading Business is intended to help Allegheny Energy Supply become a major merchant in the national energy marketplace by combining its structured transactions, trading skills and market presence with Allegheny Energy Supply's low-cost generating fleet. The acquisition also includes support infrastructure necessary to conduct business immediately upon completion of the transaction. In addition, the purchase is expected to facilitate Allegheny Energy Supply's risk management efforts. (See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.)

 

     The acquisition of Energy Trading Business also includes long-term contractual rights for 1,000 MW of natural gas-fired generating capacity in Southern California for a seventeen-year period. In addition, the acquisition includes various contracts (hedges) for the sale of portions of this power and for the purchase of natural gas for the generating units.

     On March 21, 2001, Allegheny Energy Supply entered into a $4.5 billion power sales agreement with the California Department of Water Resources (CDWR) to sell power to the CDWR for a ten-year period. The contract sales volumes increase from 150 MW to 1,000 MW over the life of the contract.

     Starting in 2000, the energy market in California has been very volatile with respect to electricity and natural gas prices. Allegheny Energy Supply seeks to mitigate risks associated with the California market volatility by hedging its long or short positions, e.g. the CDWR contract discussed above. (See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK for a discussion of Allegheny's corporate energy risk control policy.)

 

     In January 2001, AE announced that Allegheny Energy Supply plans to construct a 630-MW natural gas-fired merchant generating facility in St. Joseph County, Indiana, approximately 10 miles west of South Bend. Construction on the facility will begin in 2002 and will be completed in two stages. Two 44-MW simple-cycle combustion turbines will be constructed first in 2003, followed by the addition of 542 MW of combined-cycle capacity in 2005. When completed, the facility will allow Allegheny Energy Supply to sell additional generation into the East Central Area Reliability Region (ECAR), as well as give Allegheny Energy Supply greater access to other mid-west markets.

 

     AE and PPL Global, Inc., a subsidiary of PPL Corporation, executed an asset purchase and sale agreement in May 2000 for the purchase of Potomac Electric Power Company's (PEPCO) 9.72-percent share in the 1,711-MW Conemaugh generating station. In January 2001, each company acquired 83 MW at a cost of approximately $78 million. AE financed its share through the issuance of debt. AE anticipates the transfer of these generating assets to a subsidiary of Allegheny Energy Supply in 2001. The purchase will allow Allegheny Energy Supply to have a presence in the Pennsylvania-New Jersey-Maryland Interconnection, LLC (PJM) power market.

11

 

     In November 2000, AE announced the signing of a definitive agreement with Enron North America, a wholly-owned subsidiary of Enron Corporation, under which AE will purchase three natural gas-fired merchant generating facilities in the Midwest for approximately $1.0 billion. The purchase includes the following generating assets, all of which have been in service since June 2000: the Gleason plant (546 MW) in Gleason, Tennessee; the Wheatland plant (508 MW) in Wheatland, Indiana; and the Lincoln Energy Center plant (656 MW) in Manhattan, Illinois. AE anticipates the transfer of these generating assets to subsidiaries of Allegheny Energy Supply in 2001. These assets will provide Allegheny Energy Supply with additional natural gas-fired generating capacity within ECAR, the Mid-America Interconnected Network and the Southeastern Electric Reliability Council. The purchase is scheduled to close by May 31, 2001. AE anticipates the transfer of these generating assets to subsidiaries of Allegheny Energy Supply in 2001. These assets will provide Allegheny Energy Supply with additional natural gas-fired generating capacity within ECAR, the Mid-America Interconnected Network and the Southeastern Electric Reliability Council.

     In October 2000, AE announced that Allegheny Energy Supply plans to construct a 1,080-MW natural gas-fired merchant generating facility in La Paz County, Arizona, approximately 75 miles west of Phoenix. Construction is expected to begin on the combined-cycle facility in 2002. When completed in 2005, the facility will allow Allegheny Energy Supply to sell generation into Arizona and other states served by the Western System Power Pool, including all or parts of California, western Canada, Colorado, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming.

 

     In September 2000, AE announced that its subsidiary Allegheny Energy Supply Hunlock Creek, LLC, along with partner UGI Development, a subsidiary of UGI Corporation (UGI), will market electricity output from facilities at UGI's Hunlock Creek generating station near Wilkes-Barre, Pennsylvania. In addition to sharing 48 MW of existing coal-fired generation at Hunlock Creek, Allegheny Energy Supply Hunlock Creek, LLC installed a 44-MW natural gas-fired combustion turbine on property owned by UGI in the fourth quarter of 2000. UGI Development and Allegheny Energy Supply Hunlock Creek, LLC will jointly share in the combined output of the coal-fired and combustion turbine generating units. Allegheny Energy Supply Hunlock Creek, LLC, was responsible for construction of the Hunlock Creek combustion turbine, while UGI will operate the facilities. Allegheny Energy Supply Hunlock Creek, LLC is a subsidiary of AE, until approvals are obtained to transfer the subsidiary to Allegheny Energy Supply. Allegheny Energy Supply anticipates the transfer to be completed in 2001. The venture will give Allegheny Energy Supply access to 46 MW of generating capacity to sell into the PJM market.

 

     In January 2000, AE also announced that Allegheny Energy Supply will begin construction on a 540-MW combined-cycle generating plant at Springdale, Pennsylvania. The new facility will include two gas-fired combustion turbines and a steam turbine. The combined-cycle facility is expected to be operational and providing power for sale into competitive markets in 2003.

 

     In 1999, Allegheny Energy Unit No. 1 and Unit No. 2, LLC, a subsidiary of AE, completed construction of and placed into operation two 44-MW, simple-

12

cycle gas combustion turbines at Springdale, Pennsylvania. AE's goal is to transfer the subsidiary to Allegheny Energy Supply. Allegheny Energy Supply anticipates the transfer will be completed in 2001.
 

     Also, Allegheny Energy Supply plans to install two 44-MW simple-cycle combustion turbines in Pennsylvania during 2001.

 

     AE has petitioned the Securities and Exchange Commission (SEC) for approval to transfer 217-MW of exempt wholesale generating (EWG) facilities owned by its subsidiaries to Allegheny Energy Supply. SEC approval is required for Allegheny Energy Supply to own EWG facilities. SEC approval of the transfer is expected in 2001.


Allegheny Ventures

 

     Allegheny Ventures (formerly known as AYP Capital, Inc.) was formed in 1994 to engage in unregulated activities. In 1996, Allegheny Ventures formed two nonutility subsidiaries: AYP Energy and ACC. In 1997, Allegheny Ventures formed Allegheny Energy Solutions.

 

Telecommunications

 

     In March 2000, ACC, along with five other energy and telecommunications companies, formed a new, super-regional player in the telecommunications market, AFN Communications, formerly America's Fiber Network. ACC received an interest in AFN Communications by contributing a portion of its fiber optic network to this new venture.

 

     AFN Communications has an initial fiber footprint of 7,700 route miles and 140,000 fiber miles spanning 13 states and Washington, D.C. AFN reaches about 35 percent of the national wholesale communications capacity market, linking small and rural communities to major metropolitan areas. It provides high-capacity telecommunications transport services to internet service providers, competitive local exchange providers, long-distance providers, and wireless communications companies. AFN Communications plans to expand its reach by adding new partners and their fiber assets and offering advanced network services. Other founding partners include AEP Fiber Venture, LLC, a subsidiary of American Electric Power; GPU Telcom Services, Inc., a subsidiary of GPU, Inc.; Fiber Venture Equity, Inc., a subsidiary of FirstEnergy Corporation; CFW Network, Inc.; and R&B Network, Inc.

 

     ACC continues to expand its own fiber optic network. In 1999, there were 600 route miles in the growing network. It was expanded to more than 1,300 route miles in 2000. With much growth potential in this market, ACC plans to build nearly 1,400 additional route miles in 2001. ACC also provides value-added services to customers of the network, including advanced around-the-clock network monitoring through its alliance with and 5 percent ownership interest in Genosys Technology Management, Inc., an emerging network operation center services provider.

 

     In April 2000, ACC signed an eight-year agreement with BroadbandNow to offer high-speed internet access and multimedia content to consumers in small

13

and mid-sized markets in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia. By providing these advanced data services in these underserved markets, ACC is helping to bridge the "digital divide."
 

     ACC also is part of a consortium, led by Adelphia Business Solutions, which was selected by the Commonwealth of Pennsylvania to build an advanced information technology infrastructure and to provide state government with state-of-the-art voice, video, internet, and data telecommunications services. As part of this project, ACC is conducting wireless internet pilot programs in three Pennsylvania markets.

 

     In September 2000, ACC purchased a 40 percent membership interest in Odyssey Communications, LLC, a Pennsylvania limited liability corporation that is in the business of constructing fiber optic cable.

 

     In 1997, ACC, formed a limited liability company, Allegheny Hyperion Telecommunications, L.L.C with Hyperion Communications of Pennsylvania, Inc. (now Adelphia Business Solutions). During 2000, Adelphia Business Solutions exchanged ACC's 50 percent ownership in Allegheny Hyperion Telecommunications, L.L.C. for 330,000 shares of Adelphia Business Solutions' Class A Common Stock.

 

Investments and Other Activities

 

     In 2000, Allegheny Energy Solutions announced the formation of a strategic alliance with Capstone Turbine Corporation (Capstone). Capstone manufactures commercial, ultra-low emission microturbine power systems. The alliance has positioned Allegheny Energy Solutions as a local and national solutions provider for distributed generation services. On December 7, 2000, Allegheny Energy Solutions added Siemens Solar Industries, L.P. to its portfolio of suppliers for distributed generation products. Through its agreement with Siemens Solar Industries, Allegheny Energy Solutions will provide its customers with a comprehensive offering of solar electric solutions.

   Allegheny Ventures recently filed with the SEC to purchase Leasing Technologies International, Inc., a privately held leasing and financing company which provides financial services to entities engaged in telecommunications, software, internet, and other technologies. On February 13, 2001, Allegheny Ventures acquired a 10% equity interest in Utility Associates, Inc., a software development company that creates integrated mobile computing solutions for the utility industry. Allegheny Ventures is also a founding member and owner of Enporion, Inc., a global procurement exchange for the energy industry. Enporion simplifies the buying process through supply chain improvement.

     During 2000, Allegheny Ventures did not make any new investments in funds that were established in 1995. Allegheny Ventures previously invested in EnviroTech Investment Fund I, L.P. (EnviroTech), a limited partnership formed to invest in emerging electrotechnologies that promote the efficient use of electricity and improve the environment. Allegheny Ventures committed to invest up to $5 million in EnviroTech over 10 years, beginning in 1995. Allegheny Ventures also participates in the Latin American Energy and

14

Electricity Fund I, L.P. (FONDELEC), a limited partnership formed to invest in and develop electric energy opportunities in Latin America. Allegheny Ventures committed to invest up to $5 million in FONDELEC over eight years, beginning in 1995. Through FONDELEC, Allegheny Ventures has invested in electric distribution companies in Peru, Brazil and Argentina. Both EnviroTech and FONDELEC may offer Allegheny Ventures opportunities to identify investments in which Allegheny Ventures may invest in excess of its capital commitment in each limited partnership.
 

     Allegheny Ventures is also involved in marketing and developing the unused real estate holdings of the Distribution Companies.

 

Distribution Companies

 

     On August 18, 2000, Monongahela acquired Mountaineer, a natural gas distribution company serving southern West Virginia and the northern and eastern panhandles of West Virginia, from Eastern Systems Corporation, a subsidiary of Energy Corporation of America. Mountaineer serves approximately 205,000 retail natural gas customers in West Virginia. Mountaineer owns approximately 4,000 miles of natural gas distribution pipelines. The acquisition also included the acquisition of Mountaineer's unregulated subsidiary, Mountaineer Gas Services (MGS).

 

     MGS operates natural gas producing properties, gas gathering facilities, and intra-state transmission pipelines and is engaged in the sale and marketing of natural gas in the Appalachian basin. MGS owns more than 375 natural gas wells located throughout West Virginia and surrounding production areas and has active leaseholds that cover more than 86,000 acres. MGS also has a net revenue interest in about 100 wells of which it is not the operator.

 

     In December 1999, Monongahela purchased from UtiliCorp United Inc. the assets of West Virginia Power, an electric and natural gas distribution company located in southern West Virginia. The acquisition of West Virginia Power added approximately 26,000 electric distribution customers and 24,000 natural gas customers to Monongahela's existing business in West Virginia.

15

SALES

Regulated Electric Sales

 

2000

1999

Increase/
(Decrease)

Regulated Utility Customers

     

Kilowatt-hour Sales

     

Residential

14,062

13,562

3.7%

Commercial

9,510

8,955

6.2%

Industrial

20,320

19,846

2.4%

Wholesale

1,531

1,478

3.6%

Total Regulated Utility Customers

Kilowatt-hour Sales

45,423

43,841

3.6%

       

Regulated Revenue (Millions)

     

Residential

$967.2

$930.3

4.0%

Commercial

529.2

500.3

5.8%

Industrial

751.2

720.5

4.3%

Wholesale

55.8

42.4

31.6%

Total Regulated Revenue

$2,303.4

$2,193.5

5.0%


     In 2000, consolidated regulated kilowatt-hour (kWh) sales delivered to customers of retail and wholesale power increased 3.6% from those of 1999 as a result of increases of 3.7%, 6.2%, 2.4% and 3.6% in residential, commercial, industrial and wholesale sales, respectively. Consolidated regulated revenues increased 5.0% due to increases of 4.0%, 5.8%, 4.3%, and 31.6% in residential, commercial, industrial and wholesale sales, respectively. (See ITEM 1. RATE MATTERS and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)

 

     Allegheny's all-time Control Area Peak Load was 7,791 MW on January 27, 2000. (Control Area Load refers to the electricity sales to customers within the Distribution Companies' delivery territory without regard to electric generation supplier. The Control Area Load includes Regulated Load.) The Regulated Peak Load in 2000 was 7,455 MW on December 22, 2000. This value is subject to a final reconciliation process. However, the final value is not expected to vary significantly from 7,455 MW. (Regulated Load refers to the electricity sales to customers of Allegheny Power (the Distribution Companies) who have not selected an alternate generation supplier. It does not include sales by Allegheny Energy Supply to nonaffiliated customers within the Allegheny Power service territory.)

 

     Consolidated regulated electric operating revenues for 2000 were derived as follows: Pennsylvania, 40.2%; West Virginia, 31.4%; Maryland, 20.4%; Virginia, 5.6%; and Ohio, 2.4% (residential, 38.2%; commercial, 20.8%; industrial, 29.7%; bulk power transactions, 8.3%; and other, 3.0%).

 

     During 2000, Monongahela's kWh sales to retail customers increased 7.4%. Residential, commercial, and industrial sales increased 9.2%, 13.6% and 4.2%, respectively. Revenues from residential, commercial, and industrial customers increased 9.6%, 11.0%, and 1.3%, respectively. Electric revenues from

16

residential, commercial, and industrial customers increased primarily due to growth in the number of customers, resulting from the acquisition of West Virginia Power and its 26,000 electric service customers, from Utilicorp United, Inc. in late December 1999. Residential revenues also increased due to customer usage, primarily because of weather conditions in late 2000. Revenues from bulk power transactions and sales to affiliates increased 12.6% as utility operations now sell bulk power to its affiliated unregulated operations allowing for a more efficient dispatch of power. Monongahela's revenues represented 26.5% of Allegheny's total regulated sales revenues to customers. Monongahela's all-time Control Area Peak Load of 1,916 MW occurred on June 14, 2000.
 

     Monongahela's electric operating revenues were derived as follows: West Virginia, 91.2%, and Ohio, 8.8% (residential, 31.9%; commercial, 19.9%; industrial, 30.4%; bulk power transactions, 2.0%; and other, 15.8%).

 

     During 2000, Potomac Edison's kWh sales to retail customers increased 3.4%. Residential, commercial, and industrial sales increased 4.5%, 4.6% and 2.1%, respectively. Revenues from residential increased .5% while commercial and industrial sales decreased 2.8% and 2.3%, respectively. The increase in residential revenues was due primarily to growth in the number of residential customers and colder than normal weather conditions in late 2000. Despite the ability of Maryland customers to shop for another energy supplier since July 1, 2000, at December 2000, no residential customers have elected to choose another energy supplier. The decreases in revenues for commercial and industrial customers were due primarily to a decrease in the fuel portion of customer bills, a decrease in surcharge revenues applicable to recovery of costs related to purchased power from the AES Warrior Run cogeneration project, a decrease in Virginia base rates, and, to a lesser extent, Maryland deregulation, which gave Maryland customers of Potomac Edison the ability to choose another energy supplier effective July 1, 2000. Revenues from bulk power transactions and sales to affiliates increased 155.4%. Potomac Edison's revenues represented 31.3% of Allegheny's total regulated sales revenues to customers. Potomac Edison's all-time Control Area Peak Load of 2,656 MW occurred on January 27, 2000. The Regulated Peak Load in 2000 was 2,656 MW on January 27, 2000.

 

     Potomac Edison's electric operating revenues were derived as follows: Maryland, 63.9%; West Virginia 18.6%, and Virginia, 17.5%; (residential, 40.1%; commercial, 19.8%; industrial, 25.1%; bulk power transactions, 5.6%; and other, 9.4%). Revenues from one industrial customer, the Eastalco aluminum reduction plant near Frederick, Maryland, amounted to $63.1 million (7.6% of total electric operating revenues). Minimum annual charges to Eastalco under an electric service agreement, which continues through April 1, 2003, with automatic extensions thereafter unless terminated on notice by either party, were $14.4 million in 2000.

     Prior to transferring its electric generation to Allegheny Energy Supply, West Penn, through its Energy Supply Division, participated in unregulated markets as a supplier of electricity. After the transfer of West Penn's generating assets, West Penn no longer participated as a supplier of

17

electricity to unregulated markets. The 1999 regulated kWh sales and regulated revenues included West Penn's unregulated activity.

     During 2000, West Penn's regulated kWh sales and deliveries to retail customers decreased 3.4%. Residential, commercial and industrial sales deliveries decreased 2.7%, 3.4% and 4.0%, respectively. Regulated revenues from residential, commercial and industrial customers decreased 3.2%, 4.1% and 10.1%.

     Adjusting for West Penn's 1999 unregulated activity, West Penn's 2000 regulated kWh sales and deliveries to retail customers increased 1.5%. Residential, commercial and industrial sales deliveries increased .4%, 3.4% and 1.4%, respectively. Regulated revenues from residential, commercial and industrial customers increased 3.8%, 9.6% and 11.3%, respectively. The increases in revenues for residential, commercial and industrial customers were due primarily to growth in the number of customers and increased customer usage, partially due to weather conditions in late 2000. Also, even though Pennsylvania deregulation gave all of West Penn's regulated customers the ability to choose another energy supplier in 2000 (as opposed to two-thirds of West Penn's regulated customers in 1999), electric energy supplied to West Penn customers by alternative energy suppliers declined in 2000 from 11% of total mWh sales to 7% of total mWh sales. Revenues from bulk power transactions and sales to affiliates decreased 88.4%. West Penn's regulated revenues represented 42.2% of Allegheny's total regulated sales to customers. West Penn's all-time Control Area Peak Load of 3,328 MW occurred on July 6, 1999. The Control Area Peak Load in 2000 was 3,311 MW on June 26, 2000. The Regulated Peak Load in 2000 was 3,112 MW on December 22, 2000.

 

     West Penn's regulated electric operating revenues were derived as follows: Pennsylvania, 100% (residential, 38.6%; commercial, 21.1%; industrial, 30.9%; bulk power transactions, 2.4%; and other, 7.0%).

 

     In 2000, the Distribution Companies provided approximately 0.8 billion kWh of energy to nonaffiliated companies and marketers from generation facilities operated by the Distribution Companies. Revenues from those sales of generation from the Distribution Companies were approximately $135.8 million.

 

     The Distribution Companies transmitted approximately 10.9 billion kWh to others located outside their service territories under various forms of transmission service agreements. Revenues from those sales were about $73.2 million.

18

 

Unregulated Electric Sales

 

2000

1999

Increase /
(Decrease)

Kilowatt-hour Sales*

     

Unregulated Generation

41,707

15,854

163.1%

Total Kilowatt-hour Sales

41,707

15,854

163.1%

       

Unregulated Revenue (Millions)*

     

Unregulated Generation

$2,281.6

$879.4

159.4%

Other

22.6

8.9

153.9%

Total Revenue

$2,304.2

$888.3

159.4%

*Unregulated generation sales include amounts for recording Allegheny Energy Supply's energy trading contracts at their fair value as of the balance sheet date.

Unregulated sales revenues, including energy sales to affiliates in total, were $2,304.2 million, of which approximately $799.2 million were the result of energy sales to affiliates. Excluding the effect of affiliated sales, unregulated revenues represented 37.5% of Allegheny's total operating revenues in 2000.



Regulated Gas Sales

In 2000, the consolidated regulated million cubic feet (Mcf) of gas delivered to retail and wholesale power customers was 14,873,642 as a result of the acquisition of West Virginia Power and Mountaineer. Residential, commercial, industrial and wholesale sales were 58.0%, 8.8%, 31.8% and 1.4% of the total Mcf regulated sales, respectively. Consolidated regulated gas revenues for 2000 were $81.8 million. Residential, commercial, industrial and wholesale gas sales represented 62.8%, 9.0%, 26.2% and 2.0% of the total regulated gas revenues.


Regulatory Framework Affecting Electric Power Sales

 

     The Energy Policy Act of 1992 (EPACT) initiated the restructuring of the electric utility industry by permitting competition in the wholesale generation market. In order to facilitate the efficient use of generation facilities, on April 24, 1996, the FERC issued Orders 888 and 889. On March 4, 1997, the FERC issued Orders 888A and 889A reaffirming and clarifying the legal and policy determinations as originally adopted in the previous orders. The FERC also issued Orders 888B and 889B on November 25, 1997 in which the FERC presented explanations and minor revisions to specific sections of the orders.

 

     The FERC orders require all transmission providers to offer service to entities selling generation services in a manner that is comparable to their own use of the transmission system. The orders required each transmission provider to file standardized open access transmission service tariffs; therefore, the Distribution Companies have on file a pro forma open access tariff under which they sell transmission services to all eligible customers. Monongahela and Allegheny Energy Supply also arrange for transmission services for their own sales pursuant to the rates, terms, and conditions of the open access tariff. The Distribution Companies' open access tariff was accepted for filing by the FERC on November 25, 1998.

19

 

     To meet the objective of providing comparable or nondiscriminatory transmission services, the FERC orders further require that utilities functionally unbundle transmission operations and reliability functions from wholesale merchant functions within the utility. Accordingly, Allegheny formed discrete business units, including a delivery business unit (inclusive of transmission) and a supply business unit. The delivery business unit includes several sub-units, including the System Planning and Operations group, which provides transmission system operations and reliability functions. Each business unit has its own management, objectives, and facilities. The Distribution Companies conduct their business in a manner that is consistent with FERC's Standards of Conduct.

 

     The FERC established its jurisdiction over unbundled retail, as well as wholesale transmission services, in Order 888. Although states retain the authority to determine if retail wheeling should be adopted, retail transmission service under the jurisdiction of the FERC is available once these historically franchised customers have access to alternate generation sources. As the states in their service territory enacted retail choice, the Distribution Companies revised their Open Access Tariff to authorize sale of open access transmission services to unbundled retail customers.

 

     The Distribution Companies also have on file with the FERC a Standard Generation Service Rate Schedule for the sale of wholesale power at cost-based rates. In October 1997, the Distribution Companies submitted a new wholesale tariff to the FERC, asking for authority to sell power at market-based rates. The Distribution Companies began selling power at market-based rates upon acceptance of the filing by the FERC in August 1998. Separately, a market-based rate tariff for Allegheny Energy Supply was filed and became effective August 15, 1999. Allegheny Energy Supply started serving customers under that tariff on November 19, 1999.

 

     On December 20, 1999, the FERC issued Order No. 2000, which requires each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce to make certain filings with respect to forming and participating in a regional transmission organization (RTO). FERC stated in that order that transmission owners are expected to join RTOs on a voluntary basis and that RTOs will be operational by December 15, 2001. The Distribution Companies and other transmission-owning entities were required to file with the FERC their plans for joining an RTO by October 16, 2000. On October 5, 2000, the Distribution Companies and PJM Interconnection, LLC (PJM) announced that they had signed a Memorandum of Agreement to develop a new affiliation - PJM West. The affiliation was outlined in a compliance filing submitted to FERC on October 16, 2000, and the process progressed with the fling of an associated series of agreements, tariffs, and rate schedules on March 15, 2001. The Distribution Companies anticipate that PJM West will be implemented by December 15, 2001. As an Independent System Operator, PMJ will functionally operate the transmission assets of the distribution companies within the framework of PJM and PJM West. Although PJM is an Independent System Operator (ISO), the Distribution Companies will not join PJM, but will pursue the development of an independent transmission company, working within the PJM framework. The Distribution Companies will lead the new PJM West

20

initiative, which will afford transmission service to all market participants while simultaneously expanding the PJM market. PJM West is expected to provide benefits to the Distribution Companies and Allegheny Energy Supply.
 

     Under PURPA, certain municipalities, businesses and private developers have installed generating facilities at various locations in or near the Distribution Companies' service areas, and sell electric capacity and energy to the Distribution Companies at rates consistent with PURPA and ordered by appropriate state commissions. The Distribution Companies are committed to purchasing 479 MW of on-line PURPA capacity. This total includes 180 MW from the AES Warrior Run project, which came on-line in February 2000. Payments for PURPA capacity and energy in 2000 totaled approximately $204 million, before amortization of West Penn's adverse power purchase commitment, resulting in an average cost to the Distribution Companies of 5.5 cents/kWh.

ELECTRIC FACILITIES

 

     The following table shows Allegheny's operational generating capacity as of December 31, 2000, based on the maximum operating capacity of each unit. Monongahela's owned capacity totaled 2,113 MW, of which 1,886 MW (90%) are coal-fired and 227 MW (10%) are pumped-storage. The term "pumped-storage" refers to the Bath County station, which stores energy for use principally during peak load hours by pumping water from a lower to an upper reservoir, using the most economic available electricity, generally during off-peak hours. During the generating cycle, power is produced by water falling from the upper to the lower reservoir through turbine generators.

 

     Allegheny Energy Supply's owned or contracted capacity as of December 31, 2000, totaled 6,273 MW of which 5,360 MW (85.4%) are coal-fired, 154 MW (2.5%) are oil-fired, 613 MW (9.8%) are pumped-storage, 88 MW (1.4%) are gas fired, and 58 MW (.9%) are hydroelectric.

 

     Allegheny Energy Unit No. 1 and Unit No. 2, LLC owns 88 MW of gas-fired capacity. It sells its output to Allegheny Energy Supply, and the transfer of ownership of these units to Allegheny Energy Supply is expected in 2001.

21

ALLEGHENY STATIONS

Maximum Generating Capacity (Megawatts) (a)

     

Regulated

Unregulated

 
           

Hunlock

   

Dates When

   

Station

Monongahela

Potomac

West Penn

Energy

AE Supply

AE Unit

Service

Station

Units

Total

 

Edison

 

Ventures

 

Nos. 1 & 2

Commenced(c)

Coal-Fired (Steam):

                 

Albright

3

292

216

     

76

 

1952-4

Armstrong

2

356

       

356

 

1958-9

Fort Martin

2

1,107

249

     

858

 

1967-8

Harrison

3

1,950

488

     

1,462

 

1972-4

Hatfield's Ferry

3

1,710

470

     

1,240

 

1969-71

Hunlock (d)

1

24

     

24

   

2000

Mitchell

1

288

       

288

 

1963(i)

Pleasants

2

1,285

321

     

964

 

1979-80

Rivesville

2

142

142

         

1944-51

R. Paul Smith

2

116

       

116

 

1949-60

Willow Island

2

243

243

           

Gas-Fired

                 

AE Nos. 1 & 2(b)

2

88

         

88

1999

AE Nos. 8 & 9

2

88

       

88

 

2000

Hunlock CT (d)

1

22

     

22

   

2000

Oil-Fired Steam

                 

Mitchell

2

154

       

154

 

1948-49

Pumped-Storage and Hydro

                 

Bath County(e)

6

840

227(e)

     

613(e)

 

1985

Lake Lynn (f)

4

52

       

52

 

1926

Potomac Edison

21

6

 

3

   

3

 

Various

Total Allegheny-Owned Capacity

61

8,763

2,356

3

0

46

6,270

88

 

22

 

PURPA GENERATION

Maximum Generating Capacity (Megawatts) (g)

           

Hunlock

   

Dates When

   

Project

Monongahela

Potomac

West Penn

Energy

AE Supply

AE Unit

Service

   

Total

 

Edison

 

Ventures

 

Nos. 1 & 2

Commenced(c)

Project

                 
                   

Coal-Fired: Steam

                 

AES Beaver Valley

 

125

   

125

     

1987

Grant Town

 

80

80

         

1993

West Virginia University

 

50

50

         

1992

AES Warrior Run

 

180

 

180(h)

         

Hydro:

                 

Allegheny Lock and Dam 5

 

6

   

6

     

1988

Allegheny Lock and Dam 6

 

7

   

7

     

1989

Hannibal Lock and Dam

 

31

31

         

1988

Total Other Capacity

 

479

161

180

138

       

Total Allegheny-owned and PURPA Committed Generating Capacity (a)

 

9,242

2,517

183

138

46

6,270

88

 

 

23

(a) Accredited capacity.

(b) Allegheny Energy Unit No. 1 and Unit No. 2, LLC owns 100% of Units No. 1 and No. 2, recently constructed at Springdale, PA. Output from these units is sold exclusively to Allegheny Energy Supply, and transfer of ownership of these units to Allegheny Energy Supply is expected in 2001.

(c) Where more than one year is listed as a commencement date for a particular source, the dates refer to the years in which operations commenced for the different units at that source. The Hunlock coal unit date refers to the year in which part ownership was acquired by AE.

(d) AE's ownership interest in Hunlock Creek Energy Ventures results in the production of energy in shared amounts from the two units managed by that venture. Allegheny Energy Hunlock Creek, LLC's access to output at maximum generating capacity is as indicated on the table for the steam and gas-fired facilities. Allegheny Energy Supply Hunlock Creek, LLC's output is sold exclusively to Allegheny Energy Supply.

(e) Capacity entitlement through ownership of AGC, 27% and 73% by Monongahela and Allegheny Energy Supply, respectively.

(f) Allegheny Energy Supply has a 30-year license for Lake Lynn, effective December 1994. Potomac Edison's license for hydroelectric facilities Dam No. 4 and Dam No. 5 will expire in 2003. Potomac Edison has received 30-year licenses, effective January 1994, for the Shenandoah, Warren, Luray, and Newport projects. The FERC accepted Potomac Edison's surrender of the license for the Harper's Ferry Dam No. 3 and issued an order effective October 1994.

(g) Generating capacity available through state utility commission-approved arrangements pursuant to PURPA.

(h) The 180-MW AES Warrior Run project commenced commercial operation on February 10, 2000. Potomac Edison, as required under the terms of a Maryland Restructuring Settlement, began to offer the 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 settlement. Revenue received from the sale will reduce the AES Warrior Run Surcharge paid by Maryland customers.

(i) On December 31, 1994, 82 MW, and on July 1, 1998, 50 MW of the total MW at Mitchell Power Station were reactivated.

24


ALLEGHENY MAP

 

     The Allegheny Map (Map), which has been filed with the SEC on Form SE, provides a broad illustration of the names and approximate locations of Allegheny's major generation and transmission facilities, both existing and under construction, in a five state region which includes portions of Maryland, Ohio, Pennsylvania, Virginia, and West Virginia. Additionally, Extra High Voltage substations are displayed. By use of shading, the map also provides a general representation of the service areas of Monongahela (both gas and electric, including Mountaineer) (portions of West Virginia and Ohio), Potomac Edison (portions of Maryland, Virginia, and West Virginia), and West Penn (portions of Pennsylvania).

 

     Power Stations shown on the map which appear within the Monongahela service area are Willow Island, Pleasants, Harrison, Rivesville, Albright, and Fort Martin. The single power station appearing within the Potomac Edison service area is R. Paul Smith. The Bath County Power Station appears on the map just south of the westernmost portion of Potomac Edison's service area formed by the borders of Virginia and West Virginia. Power stations appearing within the West Penn service area are Armstrong, Mitchell, Hatfield's Ferry, Gans, Allegheny Energy Unit No. 1 and Unit No. 2 and Lake Lynn. The Hunlock Creek Energy Ventures and Allegheny Energy Supply Conemaugh, LLC generating facilities are not depicted.

 

     The map also depicts transmission facilities, that are (i) owned solely by the Distribution Companies; (ii) owned by the Distribution Companies in conjunction with other utilities; or (iii) owned solely by other utilities. The transmission facilities portrayed range in voltage from 138 kV to 765 kV. Additionally, interconnections with other utilities are displayed.

25

 

     The following table sets forth the existing miles of tower and pole transmission and distribution lines and the number of substations of the Distribution Companies and AGC as of December 31, 2000:

Miles of Above-Ground Transmission and

Distribution Lines (a) and Number of Substations

 

Total Miles

Portion of Total Miles Representing 500-Kilovolt (kV) Lines

     

Monongahela

21,140

283

Potomac Edison

18,316

202

West Penn

24,223

273

AGC(b)

85

85

Total

63,764

843

(a) The Distribution Companies also have a total of 6,444 miles of underground distribution lines.
(b) Total Bath County transmission lines, of which AGC owns an undivided 40% interest and Virginia Power owns the remainder.

     The Distribution Companies' transmission network has 12 extra-high-voltage (EHV - 345kV and above) and 31 lower-voltage interconnections with neighboring utility systems. The interregional EHV transmission system, which includes the Distribution Companies' network, continued in 2000 to operate near reliability limits during periods of heavy power flows that in the past have had a predominantly west-to-east orientation. In early 1997, North American Electric Reliability Council undertook the development of a national transmission security process. The Distribution Companies serve as one of 22 regional Security Coordinators. This security process includes a Transmission Loading Relief (TLR) procedure that identifies actual flow path consequences of all power transactions, and can be used to reduce loading on the congested facilities. The new security process has provided a better exchange of operation planning information. It also has allowed more accurate evaluation of the transmission system and conditions in the Midwest that occasionally caused the predominant west-to-east power flow pattern across the Distribution Companies' network to reverse. The TLR procedure has been effective in addressing congestion caused by parallel path flows. Careful use of TLR, mainly by others, has resulted in fewer constraints on the Distribution Companies' transmission facilities. If TLR had not been available, many of those transmission congestion events would have required action in the form of transmission service curtailments.

 

     Wholesale generators and other wholesale customers may now seek from owners of bulk power transmission facilities a commitment to supply transmission services. (See discussion under ITEM 1. SALES. Regulatory Framework Affecting Power Sales). Such demand on the Distribution Companies' transmission facilities may add to heavy power flows on the Distribution Companies' facilities and may eventually require construction of additional transmission facilities.

26

 

     The Distribution Companies have, since the early 1980s, provided managed contractual access to their transmission facilities under various tariffs. For new agreements starting in 1996, managed access is also governed by the provisions of the Distribution Companies' Open Access Transmission Tariff mandated by and filed with the FERC.

 

RESEARCH AND DEVELOPMENT

 

     The Distribution Companies and Allegheny Energy Supply spent $6.4 million and $7.0 million, in 2000 and 1999, respectively, for research programs. Of these amounts, $5.2 million and $5.5 million were for Electric Power Research Institute (EPRI) dues in 2000 and 1999, respectively. EPRI is an industry-sponsored research and development institution. The Distribution Companies and Allegheny Energy Supply plan to spend approximately $6.6 million for research in 2001, with EPRI dues representing $5.1 million of that total.

 

     In addition to EPRI support, in-house research conducted by Allegheny concentrates on technology-based issues that are important developments for each of Allegheny's businesses. These technology drivers include products and services for environmental control, generating unit performance, future generation technologies, use of coal combustion by-products, transmission system performance, customer-related research, clean power technology which includes both power quality technology and distributed generation technology for customers, delivery systems equipment and sustainable energy technologies.

 

     Research is also being directed to help address major issues for Allegheny and the entire electric industry. These include electric and magnetic field (EMF) assessment of employee exposure within the work environment, Global Warming from Green House Gases (GHG) emissions, waste disposal and discharges to land, water and air resources, renewable resources, fuel cells, new combustion turbines, cogeneration technologies, transmission loading mitigation using Flexible AC Transmission System (FACTS) devices and new product development ventures.

 

     The use of biomass for cofiring and gasification are being developed with two Allegheny stations directly firing sawdust. The use of biomass lowers production cost, and results in lower emissions of nitrogen oxides (NOx), sulfur oxides, particulate matter (PM), and carbon dioxide. It also reduces operation, maintenance and compliance costs.

 

     A new communication technology patented by employees of AESC and employees of Shenandoah Electronics Intelligence, Inc., is expected to be purchased and marketed. This technology is designed to read meters and provide control to customer premises using our distribution feeder lines and using digital and power electronic technology. The baud rate is low but very acceptable for metering and control services.

27



CAPITAL REQUIREMENTS AND FINANCING

 

Construction Expenditures

 

Allegheny Energy Supply and AGC

 

     Construction expenditures of Allegheny Energy Supply were $176.1 million and $50.8 million for 2000 and 1999, respectively. Total capital expenditures in 2000, including construction expenditures, for all generating assets operated or to be acquired by Allegheny Energy Supply (excluding generating assets currently owned by Monongahela) were $182.0 million and, for 2001 and 2002, are estimated at $1,947.4 million and $313.6 million, respectively. The 2001 and 2002 estimated expenditures include $148 million and $169 million, respectively, for environmental control technology. Outages for construction, CAAA compliance and other environmental work are and will continue to be, coordinated with other planned outages, where possible. Future construction expenditures will reflect additions of generating capacity to sell into deregulated markets. Allegheny Energy Supply could potentially face significant mandated increases in capital expenditures and operating costs related to environmental issues. Allegheny Energy Supply also has additional capital requirements for debt maturities.

 

     Construction expenditures by AGC in 2000 amounted to $1.0 million and for 2001 and 2002 are expected to be $.8 million, and $.2 million, respectively.

 
 

Distribution Companies

 

     Construction expenditures by the Distribution Companies in 2000 amounted to $207.6 million. Construction expenditures for 2001 and 2002 are expected to aggregate $233.3 million and $214.3 million, respectively. The 2001 and 2002 estimated regulated expenditures include $33.5 million and $41.7 million, respectively, to cover the costs of compliance with the Clean Air Act Amendments of 1990 (CAAA). Expenditures to cover the costs of compliance with the CAAA and other environmental requirements have been and are likely to continue to be significant. Additionally, new environmental initiatives may substantially increase regulated construction requirements as early as 2001.

 

      Regulated generation-related expenditures by Monongahela for 2000, 2001, and 2002 include $43.8 million, $40.8 million, and $55.7 million, respectively, for construction of environmental control technology. Outages for construction, CAAA compliance and other environmental work is, and will continue to be, coordinated with other planned outages, where possible.

 

     Allegheny continues to study ways to reduce and meet existing regulated customer generation service demand and future increases in that demand, including new and efficient electric technologies; construction of various types and sizes of generating units that may be dedicated to regulated service (if any); increasing the efficiency and availability of Allegheny's regulated service generating facilities (if any); reducing internal

28

electrical use and transmission and distribution losses; and acquisition of energy and capacity from third-party suppliers whenever market prices are favorable versus native production or demand exceeds native production capability. The advent of retail choice of generation service supplier has introduced the potential for significant volatility within Allegheny's regulated generation service load growth profile. Since customers with choice can be expected to attempt to arbitrage any differentials between generation market prices and those set by regulators, the Distribution Companies' obligation to meet such load growth will increasingly become an exercise in trying to predict both the variable of general economic conditions in their service territories, as well as relative competitiveness of their regulated generation service pricing, versus the inherently more flexible pricing of unregulated generation suppliers. Potomac Edison and West Penn have contracts with Allegheny Energy Supply to supply them with power during the Pennsylvania and Maryland transition periods. Under these contracts, Allegheny Energy Supply provides these regulated electricity distribution affiliates with the amount of electricity, up to their retail load, that they may demand. These contracts represent a significant portion of the normal operating capacity of Allegheny Energy Supply's generating assets that were previously owned by West Penn and Potomac Edison.
 

     Current forecasts, which assume normal weather conditions, project winter and summer peaks within the Distribution Companies' control area to grow at an average rate of 0.9% and 1.0% per year, respectively, during the period 2001-2011. However, default service peak loads, which are the Distribution Companies' control area loads reduced to account for customers who choose alternate generation suppliers, are presently expected to decline at an annual rate of -0.3% and -0.6%, respectively. The level of competition actually realized for existing loads from the aforementioned unregulated suppliers could obviously have a substantial effect on those default service projections and the degree to which they fail to track with the control area load. It is anticipated that Allegheny's existing resources that are still state regulated, and existing or purchased power of various types, will be sufficient to serve the Distribution Companies' default service loads over the next few years.

 

     Construction of new transmission and distribution (T&D) assets is expected to continue at its historic rate, with no major divergent expenditures planned. Additionally, while meeting FERC and certain state regulatory requirements to join a Regional Transmission Organization does reassign the responsibility for planning major transmission systems from the incumbent transmission owner to a new independent authority, the Distribution Companies do not expect their affiliation with and formation of PJM West to result in near-term system expansion. Finally, retail choice will not greatly affect the projected need for new T&D plant since provision of delivery service remains within the authority of each Distribution Company.

 

     In connection with its construction programs, Allegheny must make estimates of the availability and cost of capital as well as the future demands of its customers that are necessarily subject to regional, national and international developments, changing business conditions, and other factors. The construction of facilities and their cost are affected by laws and regulations; lead times in manufacturing; availability of labor,

29

materials and supplies; inflation; interest rates; and licensing, rate, environmental, and other proceedings before regulatory authorities. Decisions regarding construction of facilities must now also take into account retail competition. As a result, future plans of Allegheny are subject to continuing review and substantial change.
 

Allegheny Ventures

 

     Construction expenditures by Allegheny Ventures in 2000 amounted to $13.6 million and for 2001 and 2002 are expected to be $50.7 million, and $15.5 million, respectively.

30

 

 

Construction Expenditures

 

2000

2001

2002

 

Millions of Dollars

 

(Actual)

(Estimated)

Monongahela

     

Generation

$ 36.5

$ 51.6

$ 66.1

Transmission & Distribution

45.7

64.1

55.2

Total*

$ 82.2

$ 115.7

$121.3

       

Potomac Edison

     

Generation

$ 16.8

$ -

$ -

Transmission & Distribution

55.5

49.9

48.5

Total*

$ 72.3

$ 49.9

$ 48.5

       

West Penn

     

Generation

$ -

$ -

$ -

Transmission & Distribution

53.1

51.6

50.2

Total*

$ 53.1

$ 51.6

$ 50.2

       

AESC

$ -

$ 21.9

$ 4.1

       

Total Construction Expenditures,

     

Regulated

$207.6

$ 239.1

$224.1

       

Allegheny Energy Supply*

$176.1

$1,940.9

$303.6

       

AGC

$ 1.0

$ .8

$ .2

       

Allegheny Ventures

$ 13.7

$ 50.7

$ 15.5

       

Other*

$ 4.8

$ -

$ -

   

Total Construction Expenditures

 

Unregulated

$195.6

$1,992.4

$319.3

       

Total Construction Expenditures

$403.2

$2,231.5

$543.4

 

*Includes allowance for funds used during construction (AFUDC), or capitalized interest in the case of the generation business of West Penn and Allegheny Energy Supply, for 1999, 2000, and 2001 of: Monongahela $0.1, $0.1, and $0.1; Potomac Edison $0.6, $0.3, and $0.5; West Penn $0.1, $0.2, and $0.2; and Allegheny Energy Supply $0.0, 22.0, and 54.9.

 

     These capital expenditures include major projects at existing generating stations, upgrading distribution lines and substations, and the strengthening of the transmission and subtransmission systems.

31



Financing Programs

 

Allegheny Energy Supply

 

     To meet cash needs for operating expenses, the payment of interest, retirement of debt, and for Allegheny Energy Supply's acquisition and construction programs, Allegheny Energy Supply has used internally generated funds, member contributions, and external financings, such as debt instruments, installment loans, and lease arrangements. The availability and cost of external financings depend upon the financial condition of Allegheny Energy Supply and market conditions.

 

     Short-term debt increased to $198 million in 2000 and consists of commercial paper borrowings of $166 million and notes payable to AE of $53 million. At December 31, 2000, unused lines of credit with banks were $180 million.

 

     In November 2000, Allegheny Energy Supply consummated an operating lease transaction relating to the construction of a 540-MW combined-cycle generating plant located in Springdale, Pennsylvania. This transaction was structured to finance the construction of the plant with a maximum commitment amount of $318.4 million. Upon completion of the plant, a special purpose entity will lease the plant to Allegheny Energy Supply. Lease payments, to be recorded as rent expense, are estimated at $1.9 million per month, commencing during the second half of 2003 through 2005. Subsequently, Allegheny Energy Supply has the right to negotiate up to two five-year renewal terms or purchase the plant for the lessor's investment, or sell the plant and pay the difference between the proceeds and the lessor's investment up to a maximum recourse amount of approximately $275 million.

 

     The purchase of the Energy Trading Business from Merrill Lynch was financed through a combination of new debt and an agreement to transfer an ownership interest in Allegheny Energy Supply. Allegheny Energy Supply issued $490 million of new debt, including $400 million of 7.80% term notes due March 15, 2011 and $90 million of commercial paper. In addition, subject to regulatory approvals, Allegheny Energy Supply will transfer a 2% ownership interest in Allegheny Energy Supply to Merrill Lynch & Co. Inc., the Energy Trading Business' current parent company. In the event that regulatory approvals to transfer the ownership share are not received, Allegheny Energy Supply will instead pay Merrill Lynch & Co., Inc., a negotiated value in lieu of a two percent equity interest in Allegheny Energy Supply.

     The purchase of three natural gas-fired generating facilities at a cost of approximately $1.0 billion from Enron North America will be financed by the sale of approximately $500 million of common stock by AE and an initial bridge loan for the remaining purchase requirements of approximately $528 million plus transaction costs. The proceeds from the common stock sale will either be transferred to Allegheny Energy Supply as an equity contribution, or will be loaned to Allegheny Energy Supply in return for an interest-bearing note.

32

 

     Allegheny Energy Supply plans to construct a 1,080 MW natural gas-fired generating facility in LaPaz County, Arizona, approximately 75 miles west of Phoenix. Construction is expected to begin on the combined-cycle facility in 2002, to be completed in 2005.

     In January 2001, AE announced that Allegheny Energy Supply plans to construct a 630-MW natural gas-fired merchant generating facility in St. Joseph County, Indiana, approximately 10 miles west of South Bend. Allegheny Energy Supply expects construction on the facility to begin in 2002 and to be completed in two stages. Two 44-MW simple-cycle combustion turbines will be constructed in 2003, followed by the addition of 542 MW of combined-cycle capacity in 2005.

     In January, 2001, AE purchased 83 MW of Potomac Electric Power Company's share in the 1,711-MW Conemaugh generating station in west-central Pennsylvania at a cost of approximately $78 million. AE anticipates that it will transfer these generating assets to a subsidiary of Allegheny Energy Supply in 2001.

     In 1999, Allegheny Energy Unit No. 1 and Unit No. 2, LLC, completed construction of and placed into operation two 44-MW, simple-cycle gas combustion turbines in Springdale, Pennsylvania. AE anticipates that it will transfer the subsidiary to Allegheny Energy Supply during 2001. Allegheny Energy Supply also plans to install two 44-MW simple-cycle combustion turbines in Harrison City, Pennsylvania during 2001.

    Allegheny Energy Supply anticipates meeting its 2001 cash needs through internal cash generation, cash on hand, short-term borrowings as necessary, external financings, lease arrangements, and by issuing debt and equity.

 

Distribution Companies and AGC

 

     The Distribution Companies and AGC have financed their construction programs through internally generated funds, first mortgage bonds, debentures, medium-term notes, subordinated debt and preferred stock issues, pollution control and solid waste disposal notes, installment loans, long-term lease arrangements, equity investments by AE (or, in the case of AGC, by its parent companies), and, where necessary, interim short-term debt. Their future ability to finance their construction programs by these means depends on many factors, including effects of competition and creditworthiness, and adequate revenues to produce satisfactory internally generated funds and return on the common equity portion of the Distribution Companies' capital structures and to support their issuance of senior and other securities.

     On March 1, 2000, $75 million of Potomac Edison's 5-7/8 percent series first mortgage bonds matured; Monongahela's $65 million of 5-5/8 percent series first mortgage bonds matured on April 1, 2000; and, in March, June, September, and December of 2000, West Penn redeemed a total of $46.8 million of class A-1 6.32 percent transition bonds.

     On June 1, 2000, Potomac Edison issued $80 million of floating rate private placement notes, due May 1, 2002, assumable by Allegheny Energy Supply upon its acquisition of Potomac Edison's Maryland generating assets.

33

In August 2000, after the Potomac Edison generating assets were transferred to Allegheny Energy Supply, the notes were remarketed as Allegheny Energy Supply floating rate (three-month London Interbank Offer Rate (LIBOR) plus .80 percent) notes with the same maturity date. No additional proceeds were received.

     On August 18, 2000, Monongahela borrowed $61 million, under a senior secured credit facility, at a rate of 7.18 percent, with a maturity of November 20, 2000. On November 20, 2000, Monongahela paid off the original $61 million borrowing and borrowed $100 million at a rate of 7.21 percent with a maturity of May 21, 2001. The facility will be transferred to Allegheny Energy Supply concurrently with the transfer of Monongahela's West Virginia generating assets to Allegheny Energy Supply.

     As part of the purchase of Mountaineer Gas on August 18, 2000, Monongahela assumed $100 million of existing Mountaineer Gas debt. This debt consists of several senior unsecured notes and a promissory note with fixed interest rates between 7.00 percent and 8.09 percent and maturity dates between April 4, 2009, and October 31, 2019.

     During 2001, Monongahela, Potomac Edison and West Penn anticipate meeting their capital requirements through a combination of internally generated funds, cash on hand, issuance of debt, short-term borrowing and leasing arrangements, as necessary.

 

     The Distribution Companies' and AGC's ratios of earnings to fixed charges for the year ended December 31, 2000 were as follows: Monongahela, 4.04, Potomac Edison, 3.70, West Penn, 3.30 and AGC, 3.18.

 

AE

 

     In August 2000, AE issued $165 million of unsecured notes at an interest rate of 7.75%, due August 1, 2005. In November 2000, AE issued an additional $135 million of unsecured notes at an interest rate of 7.75%, due August 1, 2005.

 

     During 2001, to finance the purchase of additional generating assets, AE plans to issue $500 million of common stock and enter into $550 million of debt, as a short-term bridge borrowing.

 

     Beginning in the third quarter of 1997, AE began buying shares in the open market for its Dividend Reinvestment and Stock Purchase Plan and its Employee Stock Ownership and Savings Plan, and in 1998 AE began buying shares in the open market for the Performance Share Plan. In addition, in 1999, AE began buying shares in the open market for the common stock portion of the Outside Directors' annual retainer.

 

     At December 31, 2000, Allegheny companies had short-term debt of $722 million outstanding. The borrowing positions of the individual companies were: AE $486 million, Monongahela $37 million, Potomac Edison $33 million, and Allegheny Energy Supply $166 million.

 

     Allegheny's consolidated capitalization ratios as of December 31, 2000

34

were: common equity, 39.8%; preferred stock, 1.7%; and long-term debt, 58.5%, including 6.1% of Quarterly Income Debt Securities.
 

     AE has announced that it is considering ways to maximize the value of its generating assets by separating them from the regulated business. This would include converting the unregulated generation subsidiary, Allegheny Energy Supply, into a stock corporation and selling all or a part of its common stock through an initial public offering or combining an initial public offering with a spin-off of the Allegheny Energy Supply stock held by AE to its stockholders. If completed, the initial public offering would reduce AE's share of Supply's earnings. If AE divests its remaining shares of Allegheny Energy Supply through the distribution of these shares to the holders of AE common stock, AE will have no share in Allegheny Energy Supply's earnings and AE's earnings will be primarily dependent upon the earnings of its regulated transmission and distribution business.

     In the event of an initial public offering of and/or spin-off of Allegheny Energy Supply or other similar strategy, AE's board of directors may elect to establish dividend policies for each business unit that would be consistent with its earnings prospects, growth rate, need for capital and other factors that would be different from and likely lower than the current policy for the integrated company.

 

FUEL SUPPLY

 

ELECTRIC GENERATION

 

     In 2000, generating stations owned by Allegheny Energy Supply, Monongahela and Potomac Edison burned approximately 18.5 million tons of local mid to high sulfur coal. Of that amount, 38% was used in stations equipped with scrubbers (7.0 million tons). The use of desulfurization equipment and the cleaning and blending of coal make burning local coal practical. In 2000, almost 100% of the coal received at these stations came from mines in West Virginia, Pennsylvania, Maryland and Ohio. None of the Allegheny companies mine or clean any coal. All raw, clean or washed coal from suppliers is purchased as necessary to meet station requirements.

 

     In 2000, Allegheny Energy Supply, Monongahela and Potomac Edison had long-term arrangements (i.e., terms of 12 months or longer) in place to purchase approximately 16.5 million tons of coal or 90.0% of the coal consumed in 2000. In 2000, Allegheny Energy Supply, Monongahela and Potomac Edison purchased approximately 11 million tons of coal from various local mines owned by subsidiary companies of one company. Long-term arrangements are in effect to provide for up to approximately 18.0 million tons of coal in 2001. Monongahela and Allegheny Energy Supply will depend on short-term arrangements and spot purchases for their remaining requirements. Through the year 2005, the total coal requirements of present Allegheny-operated stations are expected to be met with coal acquired under existing contracts or from known suppliers.

 

     For each of the years 1996 through 1999, the average cost per ton of coal burned was $32.25, $32.66, $32.26 and $30.18, respectively. For the

35

year 2000, the cost per ton decreased to $26.73.
 

     The Distribution Companies own coal reserves estimated to contain about 125 million tons of higher sulfur coal recoverable by deep mining. There are no present plans to mine these reserves and, in view of economic conditions now prevailing in the coal market, the Distribution Companies plan to hold the reserves as a long-term resource.

 

     The addition of natural gas-fired generation, both through acquisitions and construction, will diversify Allegheny Energy Supply's fuel mix from the current predominantly coal-fired generation facilities. This change in fuel mix and diversification is expected to assist Allegheny Energy Supply in reducing business risks.

 

     Long-term arrangements, subject to price change, are in effect and will provide for the lime requirements of scrubbers at Allegheny's scrubbed stations.

 

DISTRIBUTION GAS SUPPLY

 

     On September 30, 1998, Mountaineer entered into a Natural Gas Supply Management Agreement (Supply Agreement) with Coral Energy Resources, L.P. (Coral) an affiliate of Shell Oil Company, pursuant to which Coral became the principal gas supplier for Mountaineer for a three-year period commencing as of November 1, 1998. The term of the Supply Agreement coincides with the three-year West Virginia Rate Moratorium. The Rate Moratorium froze rates (fuel and base) until October 31, 2001. Mountaineer has filed a rate case requesting permission to increase rates beginning November 1, 2001.

 

     The Supply Agreement provides that Coral will be responsible for supplying in excess of 90% of Mountaineer's total annual gas requirements for the three-year term. The balance of Mountaineer's gas supply requirements will be purchased from local producers, including MGS-owned/operated production adding up to approximately 2.7 Bcf/year. Coral supplies the gas at a fixed price per decatherm (Dth) at the city gate up to approximately 24.4 Bcf annually. Any volumes in excess of 24.4 Bcf on an annual basis are priced at the lesser of a specified index or a previously agreed upon maximum cost.

 

     The following table indicates the volume of natural gas purchased and percentage of total volume of natural gas purchased, with respect to Mountaineer's largest suppliers for the year ended June 30, 2000:

 

 

2000

 

Volume
(Mmcf)

% of
Total

MGS-owned/operated production

1,949

8%

Coral Energy Resources, L.P.

22,591

90%

Other Appalachian Basin producers

483

2%

 

     MGS operates natural gas producing properties, gas gathering facilities,

36

and intra-state transmission pipelines and is engaged in the sale and marketing of natural gas in the Appalachian basin. MGS owns more than 375 natural gas wells located throughout West Virginia and surrounding production areas and has active leaseholds that cover more than 86,000 acres. MGS also has a net revenue interest in about 100 wells of which it is not the operator.
 

     The West Virginia PSC regulates MGS sales to Mountaineer, which accounts for the majority of MGS sales. The contract period runs concurrently with the current moratorium. The price for these sales is calculated by adding the Inside FERC's Gas Market Report Columbia Gas-Appalachia Index and the Columbia Gas ITS rate (approximately 18 cents April - October; and 25 cents November - March). MGS production makes up in excess of 90% of the total local production purchased by Mountaineer.

 

     In December 1999, Monongahela purchased the assets of West Virginia Power from UtiliCorp United Inc. The following table sets forth the volume of Monongahela/UtiliCorp United's natural gas purchases and percentage of total volume of natural gas purchased, excluding Mountaineer's own purchases and production, for the years ended June 30:

 

2000

1999

1998

Volume

% of

Volume

% of

Volume

% of

(Mmcf)

Total

(Mmcf)

Total

(Mmcf)

Total

WV Production Contracts

1,894

61.08%

2,044

60.08%

2,479

69.44%

Cabot Oil and Gas Marketing

772

24.90%

722

21.22%

1,061

29.72%

Other Supply Volumes

435

14.02%

636

18.70%

30

0.84%



GAS TRANSPORTATION AND STORAGE CAPACITY

 

     The gas purchased from producer/suppliers in the Gulf Coast region is transported through the interstate pipeline systems of Columbia Gulf Transmission Company (Columbia Gulf) and Columbia Gas Transmission Corporation (Columbia Gas) to Mountaineer's local distribution facilities in West Virginia. During the calendar year 2000, Columbia Gas transported approximately 83% of the gas purchased by Mountaineer in the Appalachian region, with the balance transported by Tennessee Gas Pipeline Company or directly delivered into Mountaineer's gas utility distribution system.

 

     To ensure continuous, uninterrupted service to its customers, Mountaineer has in place long-term transportation and service agreements with Columbia Gas and Columbia Gulf. These contracts cover a wide range of transportation services and volumes, ranging from firm transportation service to no-notice service and storage with such contracts expiring on October 31, 2004. Under the terms of the Supply Agreement, Coral has assumed the management and the financial obligations of virtually all of Mountaineer's total firm transportation and storage contracts. The combination of this Supply Agreement and the Rate Moratorium substantially reduces Mountaineer's

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exposure to gas cost fluctuations.
 

     Typically, the gas industry uses gas sales and/or transportation contracts for load management purposes. Under such contracts, the users purchase and/or transport gas with the understanding that they may be forced to shut down or switch to alternate sources of energy at times when the gas is needed for higher priority customers or interruptible transportation on the transporting pipeline is curtailed. In addition, during times of extraordinary supply problems, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal and state regulatory agencies.

 

     Since July 1999, Mountaineer has served a number of interruptible sales customers who are capable of utilizing alternate fuels an energy source at their respective business facilities. In 2000, Mountaineer did not have to interrupt these customers because of supply or transportation capacity scarcity or curtailments.

 

RATE MATTERS

 

Monongahela

 

     In March 2000, the West Virginia legislature passed House Resolution 27 approving an electric deregulation plan submitted by the WV PSC with certain modifications. Under the resolution, the implementation of the West Virginia deregulation plan cannot occur until the legislature enacts certain tax changes regarding the preservation of tax revenues for state and local government and other changes conforming to the plan and authorizing implementation. The plan provides for all customers to have choice of a generation supplier and allows Monongahela to transfer the West Virginia portion (approximately 2,004 MW) of its generation assets to Allegheny Energy Supply.

 

     On June 23, 2000, the West Virginia PSC approved a Joint Stipulation and Agreement for Settlement, stating agreed-upon rates designed to make the rates of Potomac Edison and Monongahela consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue reduction for Monongahela of approximately $.5 million for 2000, increasing over 8 years to an annual reduction of approximately $6.0 million. Offsetting the decrease in rates, the settlement approved by the West Virginia PSC directs Monongahela to amortize the existing overcollected deferred fuel balance as of June 30, 2000 (a total of approximately $6.0 million) as a reduction of expenses over a four and one-half year period beginning July 1, 2000. Also, on July 1, 2000, Potomac Edison and Monongahela ceased their expanded net energy cost (fuel clause) as part of the settlement.

 

     On June 23, 2000, the West Virginia PSC also issued an order regarding the transfer of the generation assets of Monongahela. In part, the order requires that after implementation of the deregulation plan, Monongahela file a petition seeking a West Virginia PSC finding that the proposed transfer of generation assets complies with the conditions of the deregulation plan.

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The June 23, 2000 order also permits Monongahela to submit a petition to the West Virginia PSC seeking approval to transfer its West Virginia generation assets prior to the implementation of the deregulation plan. A filing before implementation of the deregulation plan is required to include commitments to the consumer and other protections contained in the deregulation plan. On August 15, 2000, with a supplemental filing on October 31, 2000, Monongahela filed a petition seeking West Virginia PSC approval to transfer its West Virginia generating assets to Allegheny Energy Supply contemporaneously with the transfer of its Ohio generation assets. Monongahela cannot predict when the West Virginia PSC will act on its filing since the PSC is waiting for legislative action.
 

     Monongahela expanded its service territory with the acquisition of West Virginia Power in December 1999. Also, Monongahela acquired Mountaineer in August 2000. The acquisition of Mountaineer included Mountaineer Gas Services (MGS), a wholly-owned subsidiary of Mountaineer.

 

     Sales of MGS production (both owned and purchased from third parties) are by and large made to Mountaineer. With regard to MGS-owned production, the rate is regulated by the WV PSC for the period that runs concurrently with the West Virginia current rate moratorium and is indexed at the Inside FERC's Gas Market Report Columbia Gas-Appalachia Index, plus the Columbia Gas ITS rate (approximately 18 cents April - October; and 25 cents November - March). MGS-owned production accounts for in excess of 90% of the system supply purchased by Mountaineer that is not purchased under the Supply Agreement with Coral.

 

     On October 11, 2000, the West Virginia PSC approved an interim increase on the commodity rate for gas customers of Monongahela (formerly West Virginia Power customers) for gas service bills rendered on and after December 1, 2000. On December 11, 2000, the West Virginia PSC approved additional increases for bills rendered on and after January 1, 2001 through November 30, 2001 (total revenue increase for the twelve-month period of $5.1 million or 22.6%). The commodity rate is the portion of the bill that reflects the cost of gas, which increased significantly during 2000. The West Virginia PSC has approved a tiered rate structure with rates established for the winter heating season, effective January 1, 2001 through April 30, 2001 and further increased rates effective May 1, 2001 through November 30, 2001, dependent upon the level of cost recovery after the winter heating season. This approach allows Monongahela full recovery of these costs but eases the increase on the average customer. These increases have no effect on earnings because they were implemented via the Purchased Gas Adjustment mechanism. Under the Purchased Gas Adjustment procedure, differences between revenues received for energy costs and actual energy costs are deferred until the next proceeding when energy rates are adjusted to return or recover previous overrecoveries or underrecoveries, respectively.

 

     On January 4, 2001, Mountaineer filed for a rate increase with the West Virginia PSC in response to significant increases in the market price for natural gas. If natural gas prices remain at levels as of January 2, 2001, the proposed overall rates will increase approximately 39 percent ($67 million) over present rates. Mountaineer anticipates that the West Virginia PSC will postpone the effective date until November 1, 2001 when the current

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rate moratorium ends. The conclusion of the current rate moratorium coincides with the expiration of the Supply Agreement with Coral.
 

      In October 2000, the Ohio PUC approved a settlement that implemented a restructuring plan for Monongahela. This restructuring plan allowed Ohio customers of Monongahela to choose their generation supplier starting January 1, 2001. Also, Monongahela is permitted to transfer the Ohio portion (approximately 352 MW) of its generation assets to Allegheny Energy Supply at net book value on or after January 1, 2001. Monongahela expects to transfer these assets in April, 2001. Additionally, the plan provides for the following: Residential customers will receive a five percent reduction in the generation portion of their electric bills during a five-year market development period beginning on January 1, 2001 and these rates will be frozen for the five years; for commercial and industrial customers, existing generation rates will be frozen at the current rates for the market development period, which began on January 1, 2001 (The market development period is three years for large commercial and industrial customers and five years for small commercial customers); Monongahela may collect from shopping customers a regulatory transition charge of $0.0008 per kilowatt-hour (kWh) for the market development period; Allegheny Energy Supply is permitted to offer competitive generation service throughout Ohio; and, that additional taxes resulting from competition legislation will be deferred for up to two years as a regulatory asset.

 

Potomac Edison

 

     In December 1999, the Maryland PSC approved a settlement agreement which allowed customer choice of generation suppliers effective July 1, 2000, for nearly all Maryland customers of Potomac Edison. In June 2000, the Maryland PSC authorized Potomac Edison to transfer the Maryland portion of its generation assets to Allegheny Energy Supply on or after July 1, 2000. Potomac Edison also obtained the necessary approvals from the Virginia SCC and the WV PSC to transfer the Virginia and West Virginia portions of Potomac Edison's generation assets to Allegheny Energy Supply in conjunction with the transfer of the Maryland portion of those assets. In August 2000, Potomac Edison transferred approximately 2,100 MW of its Maryland, Virginia, and West Virginia generation assets to Allegheny Energy Supply. Certain small hydroelectric facilities located in Virginia are to be transferred to a subsidiary of Allegheny Energy Supply during 2001. On December 14, 2000, the VA SCC approved the transfer of these hydro facilities to Green Valley Hydro, LLC (a subsidiary of Potomac Edison).

 

     On July 11, 2000, the Virginia SCC issued an order approving Potomac Edison's separation plan that provided for the transfer of its Virginia jurisdictional generating assets to Allegheny Energy Supply. In conjunction with the separation plan, the Virginia SCC approved a Memorandum of Understanding (MOU). The MOU provided that, effective with bills rendered on or after August 7, 2000, base rates were reduced by $1 million; Potomac Edison would not file for a base rate increase prior to January 1, 2001; and fuel rates would be rolled into base rates effective with bills rendered on or after August 7, 2000. A fuel rate adjustment credit was also implemented on August 7, 2000, reducing annual fuel revenues by $750,000. Effective August 2001, the fuel rate adjustment credit will drop to $250,000.

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Effective August 2002, the fuel rate adjustment credit will be eliminated. In addition, Potomac Edison has agreed to operate and maintain its distribution system in Virginia at or above historic levels of service quality and reliability, and, during the default service period, to contract for generation service to be provided to customers at rates set in accordance with the Virginia Electric Utility Restructuring Act.
 

     On August 10, 2000, Potomac Edison filed an application with the Virginia SCC to transfer the hydroelectric assets located within the state of Virginia to Green Valley Hydro, LLC (a wholly-owned subsidiary of Potomac Edison). On December 14, 2000, the Virginia SCC approved the transfer. Potomac Edison anticipates the transfer will occur during the second quarter of 2001, after receiving final approval from the SEC. In 2001, Green Valley Hydro, LLC will become a subsidiary of Allegheny Energy Supply.

 

     All Virginia utilities were required to submit a restructuring plan by January 1, 2001, to be effective on January 1, 2002. Accordingly, Potomac Edison filed Phase II of the Functional Separation Plan with the Virginia SCC on December 19, 2000.

 

     Potomac Edison decreased the fuel portion of Maryland customers' bills by about $6.4 million annually effective with bills rendered on or after December 7, 1999, based on the outcome of proceedings before the Maryland PSC. A proposed order was issued on February 18, 2000, granting the requested decrease in Potomac Edison's fuel rate, and on March 21, 2000, the proposed order became final. Effective July 1, 2000, coincident with Customer Choice in Maryland, the fuel rates were rolled into base rates.

 

     On March 24, 2000, the Maryland PSC issued an order requiring Potomac Edison to refund the 1999 deferred fuel balance overrecovery of approximately $9.9 million to customers over a period of twelve months beginning April 30, 2000. The refund of the overrecovered balance does not affect Potomac Edison's earnings since the overrecovered amounts had been deferred.

 

     On October 4, 2000, the Maryland PSC approved Potomac Edison's filing which represents the final reconciliation of its deferred fuel balance. Potomac Edison is refunding to customers the $3.2 million overrecovery balance existing in the Maryland deferred fuel account as of September 30, 2000. The deferred fuel credit to customers began in October 2000 and will be effective until the balance falls to zero, which is projected to take twelve months. The refund of the overrecovered balance does not affect Potomac Edison's earnings since the overrecovered amounts had been deferred.

 

     On June 23, 2000, the West Virginia PSC approved a Joint Stipulation and Agreement for Settlement, stating agreed-upon rates designed to make the rates of Potomac Edison and Monongahela consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue increase for Potomac Edison of approximately $.2 million for 2000, increasing over 8 years to an annual increase of approximately $4.3 million. The settlement approved by the West Virginia PSC directs Potomac Edison to amortize the existing overcollected deferred fuel balance as of June 30, 2000 (a total of

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approximately $10.0 million) as a reduction of expenses over a four and one-half year period beginning July 1, 2000. Also, on July 1, 2000, Potomac Edison and Monongahela ceased their expanded net energy cost (fuel clause) as part of the settlement.
 

     On November 29, 2000, the Maryland PSC approved the Power Sales Agreement between Potomac Edison, d/b/a Allegheny Power, and PG&E Energy Trading-Power, L.P. covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2001 through December 31, 2001. The AES Warrior Run cogeneration project was developed under the Public Utility Regulatory Policies Act of 1978 (PURPA) and achieved commercial operation on February 10, 2000. Under the terms of the Maryland deregulation plan approved in 1999, the revenues from the sale of the AES Warrior Run output are used to offset the capacity and energy costs Potomac Edison pays to the AES Warrior Run cogeneration project before determining amounts to be recovered from Maryland customers.

 

     Effective with bills rendered on or after January 8, 2001, there was an increase in Maryland base rates. This increase is a result of the phase-in of the rate increase approved by the Maryland PSC on October 27, 1998. A settlement agreement, which includes recognition and dollar-for-dollar recovery of costs to be incurred from the AES Warrior Run PURPA project, was filed with the Maryland PSC on July 30, 1998 and was approved on October 27, 1998. The Maryland PSC approved rates to each customer class on December 22, 1998. Under the terms of the agreement, Potomac Edison increased its rates about 4% in each of the years 1999 and 2000, and will increase rates by about 4% in 2001 (a $79 million total revenue increase during 1999 through 2001). The increases are designed to recover additional costs of about $131 million, over the period 1999-2001, for capacity purchases from the AES Warrior Run project net of alleged overearnings of $52 million for the same period. The agreement also requires that Potomac Edison share with customers 50 percent of earnings above an 11.4 percent return on equity for 1999 and 2000. As a result, 50 percent of the amount above the threshold earnings amount, or $9.7 million applicable to 1999, is being distributed to customers in the form of an Earnings Sharing Credit effective June 7, 2000 through April 30, 2001. Any sharing of earnings required for 2000 will be reflected as a credit on customers' bills starting in May 2001.

 

West Penn

 

      In November 1998, the Pennsylvania PUC approved a settlement agreement between West Penn and parties to West Penn's restructuring proceeding. Under the terms of the settlement, two-thirds of West Penn's customers were permitted to choose an alternate generation supplier as of January 2, 1999. The remaining one-third of West Penn's customers were permitted to do so starting January 2, 2000. The settlement agreement provided for a rate refund from 1998 revenue (about $25 million) via a 2.5% rate decrease throughout 1999, capped rate provisions and recovery of $670 million of transition costs during the transition period (1999 through 2008). In 1999, West Penn issued $600 million of transition bonds to "securitize" most of the transition costs. As a result of the "securitization" of transition costs, West Penn is authorized by the Pennsylvania PUC to collect an intangible transition charge (ITC) to provide revenues to service the transition bonds

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and the competitive transition charge (CTC) was correspondingly reduced. Actual CTC revenues billed to customers in 2000 and 1999 totaled $7.6 million and $92.7 million, respectively, net of gross receipts tax and a separate agreement with one customer to accelerate the recovery of CTC. Through December 31, 2000, the Company has recorded a regulatory asset of $25.3 million for the difference in the authorized CTC revenues, adjusted for $1 million securitization savings to be shared with customers and the actual transition revenues billed to customers. The Pennsylvania PUC has approved the recovery of this regulatory asset through a true-up mechanism. On December 21, 2000, the Pennsylvania PUC issued an order authorizing West Penn to defer the cumulative underrecovery of the "unsecuritized" transition costs as a regulatory asset for full and complete recovery. The November 1998 settlement also allowed West Penn to transfer its 3,778 MW of generating assets at net book value to Allegheny Energy Supply, which was completed in 1999.
 

AGC

 

     AGC's rates are set by a formula filed with and previously accepted by the FERC. The only component that can change is the return on equity (ROE). Pursuant to a settlement agreement filed with the FERC on April 4, 1996, AGC's ROE was set at 11% for 1996 and will continue at that rate until the time any affected party requests and the Commission grants a change. No party has requested any change.

ENVIRONMENTAL MATTERS

 

     The operations of the Allegheny-owned facilities, including generating stations, are subject to regulation as to air and water quality, hazardous and solid waste disposal, and other environmental matters by various federal, state, and local authorities. The generating units now owned by Allegheny Energy Supply are subject to the same environmental regulations as they were when owned by the Distribution Companies.

 

     The cost of meeting known environmental standards is provided in the "Capital Requirements and Financing" section of this report. Additional legislation or regulatory control requirements have been proposed and, if enacted, will require modifying, supplementing, or replacing equipment at existing stations at substantial additional cost.

Air Standards

 

     Allegheny currently meets applicable standards as to particulate emissions at its power stations through high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, and, at times, reduction of output. From time to time, minor excursions of stack emission opacity, normal to fossil fuel operations, are experienced and are accommodated by the regulatory process.

 

     Allegheny meets current emission standards as to sulfur dioxide (SO2) by the use of scrubbers, the burning of low-sulfur coal, the purchase of cleaned coal to lower the sulfur content, and the blending of low-sulfur with higher sulfur coal.

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     The Clean Air Act Amendments of 1990 (CAAA), among other things, require an annual reduction in total utility emissions within the United States of 10 million tons of SO2 and two million tons of nitrogen oxides (NOx) from 1980 emission levels, to be completed in two phases, Phase I and Phase II. Five coal-fired Allegheny plants were affected in Phase I, and the remaining plants were affected in Phase II. Installation of scrubbers at the Harrison Power Station was the strategy undertaken by Allegheny to meet the required SO2 emission reductions for Phase I (1995-1999). Allegheny estimates that its allowances will allow it to economically comply with Phase II SO2 limits through at least 2005 and beyond. Studies are ongoing to evaluate cost-effective options to comply with Phase II SO2 limits, including those available in connection with the emission allowance trading market. Burner modifications at most of the Allegheny-operated stations satisfy the NOx emission reduction requirements for the acid rain (Title IV) provisions of the CAAA. Additional NOx reductions, which will require some Selective Catalytic Reduction (SCR) or other post-combustion control technologies, are being mandated in Maryland, Pennsylvania, and West Virginia for ozone nonattainment (Title I) reasons. Continuous emission monitoring equipment has been installed on all Phase I and Phase II units.

 

     In an effort to introduce market forces into pollution control, the CAAA created SO2 emission allowances. An allowance is defined as an authorization to emit one ton of SO2 into the atmosphere. Subject to regulatory limitations, allowances may be sold or banked for future use or sale. Allegheny received, through an industry allowance pooling agreement, a total of approximately 554,000 bonus and extension allowances during Phase I. These allowances were in addition to the CAAA Table A allowances that the Allegheny subsidiaries received of approximately 356,000 per year during the Phase I years. Beginning in 2000 for Phase II, Allegheny receives approximately 220,000 allowances per year. As part of its compliance strategy, Allegheny continues to study and, where appropriate, participate in the allowance market, making sales or purchases of allowances or participating in certain derivative or hedging allowance transactions.

 

     Title I of the CAAA established an Ozone Transport Region (OTR) consisting of the District of Columbia, the northern part of Virginia, and 11 northeastern states including Maryland and Pennsylvania. Sources within the OTR were required to reduce NOx emissions, a precursor of ozone, to a level conducive to attainment of the one-hour ozone National Ambient Air Quality Standard (NAAQS). The installation of Reasonably Available Control Technology (RACT) (overfire air equipment and/or low NO x burners) at all Pennsylvania and Maryland stations was completed by 1995. The installation of RACT also satisfied Title IV NOx reduction requirements.

 

     Title I of the CAAA also established an Ozone Transport Commission (OTC), which determined that utilities within the OTR would be required to make additional NO x reductions beyond RACT in order for the OTR to meet the ozone NAAQS. Under terms of a Memorandum of Understanding (MOU) among the OTR states, Allegheny-operated stations located in Maryland and Pennsylvania were required to reduce NOx emissions by approximately 55% from the 1990 baseline emissions, with a compliance date of May 1999. RACT controls installed in Allegheny's Maryland and Pennsylvania generating plants allowed

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Allegheny to meet this compliance goal, and are expected to maintain the 55% reduction requirement through the year 2002. Further reductions of 75% from the 1990 baseline may be required by May 2003 under Phase III of the MOU. However, the MOU Phase III NOx reductions will most likely be superseded by the EPA's NOx State Implementation Plan (SIP) call as discussed below.
 

     In October 1998, the EPA issued a NOx SIP call rule that required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Maryland, Pennsylvania, and West Virginia, beginning May 2003. The EPA's NOx SIP call regulation has been under litigation, but on March 3, 2000 the DC Circuit Court of Appeals issued a decision that upheld the regulation. However, the court did issue a subsequent order on August 30, 2000 that postponed the initial compliance date of the NOx SIP call from May 2003 to May 2004. An appeal of the March 3, 2000 court decision is pending before the U.S. Supreme Court. During 2000, Pennsylvania and Maryland promulgated final rules to implement the EPA's NOx SIP call requirements beginning May 2003. Maryland and Pennsylvania are not expected to delay this implementation date, nor are they legally required to do so. Also in 2000, West Virginia issued a proposed rule to implement the EPA's NOx SIP call requirements beginning May 2005. However, the EPA has indicated they are unlikely to approve the West Virginia rule unless it is revised to conform to the NOx SIP call requirements, including an initial compliance date of May 2004. Allegheny's compliance with such stringent regulations will require the installation of expensive post-combustion control technologies on most of its power stations.

 

     In August 1997, eight northeastern states filed Section 126 petitions with the EPA requesting the immediate imposition of up to an 85% NOx reduction from utilities located in the Midwest and Southeast (West Virginia included). The petitions claim NOx emissions from these upwind sources are preventing their attainment of the ozone standard. In May 1999, the EPA issued a technical approval of the petitions and in December 1999 granted final approval of four of the petitions. The Section 126 petition rulemaking is also under litigation, with a decision expected Spring 2001. Allegheny's compliance plan for the Section 126 petition rulemaking would be the same as the NOx SIP call compliance plan discussed above.

 

     The EPA is required by law to regularly review the NAAQS for criteria pollutants including ozone, particulate, SO2, and NOx. Previous court orders in litigation by the American Lung Association have expedited these reviews. The EPA in 1996 decided not to revise the SO2 and NOx standards. Revisions to PM and ozone standards were promulgated by the EPA in July 1997. However, the revised standards were legally challenged and in May 1999 the DC Circuit Court of Appeals remanded the revised standards back to the EPA for further consideration. That ruling is currently under appeal before the U.S. Supreme Court with a decision expected Spring 2001. Also, in May 1999, the EPA promulgated final regional haze regulations to improve visibility in Class I federal areas (national parks and wilderness areas). The EPA regional haze regulation is also under litigation. If eventually upheld in court, subsequent state regulations could require additional reduction of SO2 and/or NOx emissions from Allegheny facilities. The effect on Allegheny of revision to any of these standards or regulations is unknown at this time, but could be substantial.

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     In 1989, the West Virginia Air Pollution Control Commission approved the construction of a third-party cogeneration facility in the vicinity of Rivesville, West Virginia. Emissions impact modeling for that facility raised concerns about the compliance of Monongahela's Rivesville Station with ambient standards for SO2. Pursuant to a consent order, Monongahela agreed to collect on-site meteorological data and conduct additional dispersion modeling in order to demonstrate compliance. The modeling study and a compliance strategy recommending construction of a new "good engineering practices" (GEP) stack were submitted to the West Virginia Department of Environmental Protection (WVDEP) in June 1993. Costs associated with the GEP stack are approximately $25 million. Monongahela is awaiting action by the WVDEP.

 

     Under an EPA-approved consent order with Pennsylvania, West Penn completed construction of a GEP stack at the Armstrong Power Station in 1982 at a cost of more than $13 million with the expectation that the EPA's reclassification of Armstrong County to "attainment status" under NAAQS for SO2 would follow. As a result of the 1985 revision of its stack height rules, the EPA refused to reclassify the area to attainment status. Subsequently, West Penn filed an appeal with the U.S. Court of Appeals for the Third Circuit for review of that decision as well as a petition for reconsideration with the EPA. In 1988, the Court dismissed West Penn's appeal, stating it could not decide the case while West Penn's request for reconsideration before the EPA was pending. West Penn cannot predict the outcome of this proceeding.

 

     In March 1998, the EPA released its Utility Air Toxics Report to Congress. The report itself did not recommend regulatory controls. However, the EPA did make a determination for regulatory controls in December 2000. The regulatory determination did not include any recommendations regarding the level or timing of reductions. However, the EPA plans to issue a proposed rule by December 2003 and a final rule by December 2004. Based on this schedule, it is unlikely implementation of mercury controls would be required before 2007-08.



Water Standards

 

     Under the National Pollutant Discharge Elimination System (NPDES), permits for all of Allegheny's stations and disposal sites are in place and all facilities are compliant with all permit terms, conditions and effluent limitations. However, as permits are renewed, more stringent permit limitations are being applied. Thus far Allegheny has successfully developed and scientifically justified, to the satisfaction of the regulatory agencies, alternate site-specific water quality criteria and thus avoided incurring the capital costs and potential liabilities of advanced wastewater treatment.

 

     However, there is significant activity at the Federal level on Clean Water Act (CWA) issues. There are pending rulemakings, for example regarding the Total Maximum Daily Load (TMDL) program, water quality standards, antidegradation review, human health and aquatic life water quality criteria, and mixing zones and CWA Section 316(b) Cooling Water Intake Structure. In

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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 comprehensive and integrated watershed management. 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.
 

     Over the past several years TMDLs have become a significant issue because of successful legal challenges to the EPA's treatment of TMDLs under the CWA in various states. Resulting consent orders in West Virginia and Pennsylvania require development and implementation of waste loads for point sources and load allocations for nonpoint sources on numerous water bodies not currently meeting water quality standards within a relatively short time frame (twelve years). Because of the scientific complexity of the issue, paucity of water quality data, the resource limitations of the state agencies as well as political considerations, it is likely that resulting TMDLs will require a disproportionate reduction in point source versus nonpoint source discharges. The direct result of the TMDLs will be further reductions in the amount of pollutants permitted to be discharged by Allegheny-owned power stations located on water quality impaired rivers. Indirectly, TMDL's can adversely affect Allegheny by prohibiting new or increased discharges and curtailing the wastewater discharges of its industrial customers.

 

     On July 13, 2000 the EPA finalized a rule that modifies the way states are required to implement the TMDL provisions of the CWA. The rule has drawn widespread bipartisan criticism from the regulated community, environmental organizations, governors, and state regulators, primarily because it usurps state authority, lacks a sound scientific basis and requires states to develop and implement a complex program in a short time frame with inadequate federal support. Congress responded to the criticism by placing a provision in a supplemental appropriations bill prohibiting the EPA from implementing the rule until October 2001. Although the final rule is not as onerous as the proposal, it still carries objectionable provisions, particularly those that require preparation of TMDLs for water bodies that are impaired in whole or in part by air emissions (particularly NOx and mercury). A number of petitions for review have been filed by various industry, agricultural, forestry and environmental groups with briefing likely to occur in 2001.

 

     The full implications of the evolving TMDL program will not be known until the EPA implements the final rule, the challenges are settled, and TMDLs are developed and implemented in specific watersheds.

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     In anticipation of the potentially adverse impact of the TMDL program, Allegheny is proactively working with a number of watershed TMDL stakeholder groups, state agencies and the EPA to ensure development of sound and equitable TMDLs.

 

     In January 1993, The Hudson Riverkeeper and other environmental groups filed suit against the EPA to force the agency to promulgate rules that would minimize environmental impact from cooling water intake structures. Section 316(b) of the CWA requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. After several amendments, the resulting consent decree divides the rulemaking into three phases:

 

1. Phase 1 applies to new facilities that employ a cooling water intake structure. The proposal was promulgated in June 2000 and final action must be taken by November 2001.

2. Phase 2 pertains to existing utilities and non-utility power producers that currently employ a cooling water intake structure, and whose flow exceeds a minimum threshold to be determined by the EPA. The rule is to be proposed by February 2002 with final action taken by August 2003.

3. Phase 3 will govern existing facilities that employ a cooling water intake structure not covered by the Phase 2 rule (pulp and paper, chemical plants, etc.) and whose intake flow exceeds a minimum threshold that will be determined by the EPA. The proposal is due by June 2003 with final action in December 2004.

 

     The Phase 1 new facility rule proposes strict uniform minimum technology requirements along with extensive site-specific study and monitoring requirements. If the proposal stands, new facilities will suffer severe siting restrictions, and will be subjected to costly environmental studies and time delays to accomplish the studies. In some situations, the new facilities could be required to apply dry cooling at significant additional cost. Moreover, the precedent-setting impact the new facility rule would have on existing facilities could be significant. It likely will require additional environmental studies and possibly even the installation of cooling towers on those facilities that are shown to be causing an "adverse environmental impact." Additionally, specific units could be forced to accept overall flow volume and velocity restrictions in water usage that could lead to derating units and undesirable energy supply reductions.



Hazardous and Solid Wastes

 

     Pursuant to the Resource Conservation and Recovery Act of 1976 (RCRA) and the Hazardous and Solid Waste Management Amendments of 1984, the EPA regulates the disposal of hazardous and solid waste materials. Maryland, Ohio, Pennsylvania, Virginia, and West Virginia have also enacted hazardous and solid waste management regulations that are as stringent as or more stringent than the corresponding the EPA regulations.

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     Allegheny is in a continual process of either permitting new or re-permitting existing disposal capacity to meet future disposal needs. All disposal areas are currently operated to be in compliance with their permits.

 

     In addition to using coal combustion by-products (CCB's) in various power plant applications such as scrubber by-product stabilization at Harrison and Mitchell Power Stations, Allegheny Energy Supply on its own behalf and on behalf of Monongahela Power (the only Distribution Company still owning generation) continues to expand its efforts to market CCB's for beneficial applications and thereby reduce landfill requirements. In 2000, Allegheny received approximately $1,100,000 from the external sale and utilization of approximately 435,000 tons of fly ash, 225,000 tons of bottom ash and 28,000 tons of boiler slag. These CCB's were beneficially used in applications such as cement replacement, anti-skid materials, grit blasting material, mine reclamation, mine subsidence, structural fills, and grouting of mines and oil wells.

 

     Allegheny completed the construction of a processing plant, which will convert the flue gas desulfurization by-product from the Pleasants Power Station into a commercial grade synthetic gypsum material to be used in the manufacture of wallboard. The processing plant went into commercial production in 2000 and is expected to produce between 400,000 and 600,000 tons of gypsum per year for a wallboard manufacturing facility. This process will significantly reduce the amount of by-product going to an impoundment.

 

     Potomac Edison received a notice from the Maryland Department of the Environment (MDE) in 1990 regarding a remediation ordered under Maryland law at a facility previously owned by Potomac Edison. The MDE has identified Potomac Edison as a potentially responsible party under Maryland law. Remediation is being implemented by the current owner of the facility which is located in Frederick. It is not anticipated that Potomac Edison's share of remediation costs, if any, will be substantial.

 

     The Distribution Companies are also among a group of potentially responsible parties under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), for the Jack's Creek/Sitkin Smelting Superfund Site and the Butler Tunnel Superfund Site in Pennsylvania. (See ITEM 3. LEGAL PROCEEDINGS for a description of these Superfund cases.)



Toxic Release Inventory (TRI)

 

     On Earth Day 1997, President Clinton announced the expansion of Right-to-Know Toxics Release Inventory (TRI) reporting to include electric utilities, limited to facilities that combust coal and/or oil for the purpose of generating power for distribution in commerce. The purpose of TRI is to provide site-specific information on chemical releases to the air, land, and water. On June 4, 1999, AE joined with other members of the Edison Electric Institute in reporting power station releases to the public. Packets of information about power station releases were provided to media in Allegheny's service area and posted on the AE web site. The first TRI report was filed with the Environmental Protection Agency prior to the July 1, 1999

49

deadline date, reporting 18 million pounds of total releases for calendar year 1998. The TRI releases reported for AE facilities will vary from year to year, but are consistent with its role as one of the nation's major coal-fired generators of electricity. The releases reported are a direct result of the volume of coal burned to meet the demand of power. Other factors that may contribute to the changes in the releases from year to year include the kind of coal use, facility operational changes, and revised calculation methodologies. In June 2000, AE reported 28 million pounds of total estimated releases for calendar year 1999.

Global Climate Change

 

     Many uncertainties remain in the global climate change debate, including the relative contributions of human activities and natural processes, the extremely high potential costs of extensive mitigation efforts, and the significant economic and social disruptions, which may result from a large-scale reduction in the use of fossil fuels. Allegheny is responding appropriately and will continue to explore cost-effective opportunities to improve efficiency and performance. The scientific debate is continuing; however the Clinton Administration signed an international treaty called the Kyoto Protocol, which would require the U.S. to reduce emissions of Green House Gases (GHG) by 7% from 1990 levels in the 2008-2012 time period. With normal economic growth this requirement could mean as much as a 40% reduction of GHG by 2012. The U.S. Senate must ratify the Kyoto Protocol before it can be of any effect domestically, as must other nations subject to the treaty's provisions. The Senate passed a resolution in 1997 (S.R. 98) by a vote of 95-0 that placed two conditions on entering into any international climate change treaty. First, any treaty must include all nations, and, second, any treaty must not cause serious harm to the U.S. economy. The Kyoto Protocol does not appear to satisfy either of these conditions and, therefore, the previous Administration withheld it from consideration by the Senate. The U.S. electric utility industry generates about one third of the GHG emitted, with other Industries, Transportation and Agriculture the rest, or two thirds. Implementation of the Kyoto Protocol would raise considerable uncertainty about the future viability of fossil fuels as an energy source for new and existing power plants.

 

     If and when the need for reducing GHG emissions has been identified and scientifically supported, Allegheny believes that a global solution involving all nations will be needed and must give credit for voluntary actions taken; precipitous and urgent action under strict limits and timetables will result in severe economic dislocation and is not warranted based on the ongoing scientific debate; and that appropriate results can be achieved domestically by continuing to build upon Allegheny's corporate awareness and the notable progress of existing voluntary programs.

 

     For these reasons, Allegheny actively participates in a number of groups to address this environmental matter. Allegheny supports research on the climate change issue through EPRI and participates in a number of organizations to help influence policy matters at the domestic and international levels. Allegheny also conducts a program to identify cost-effective and voluntary measures that reduce emissions of GHG in all areas of our business and in other areas, such as forestry, international projects,

50

and emissions trading.
 

     The Distribution Companies and Allegheny Energy Supply maintain an active climate-related research program and are responsive to the GHG guidelines suggested in the national Energy Policy Act of 1992. As a result, Allegheny Energy Supply and the Distribution Companies have voluntarily reduced their total annual emissions of GHG by about 1,650,000 tons, as described in the latest filing with the Department of Energy .

 

     The Distribution Companies and Allegheny Energy Supply support EPRI whose climate research is funded at around $7 to $10 million per year and also support Edison Electric Institute's Climate Challenge Initiative; and have committed to invest $3.11 million in an electro technology and renewable energy venture capital fund.

 

     The Distribution Companies' and Allegheny Energy Supply's in-house research program has contributed to applications of new technology, operating efficiencies, reduced electrical losses and pollution emission reductions.

 

     West Penn, as part of its restructuring settlement approved by the Pennsylvania PUC in 1998, agreed to support five important climate related initiatives: 1) Renewable Energy Development, 2) Sustainable Energy Fund ($11,425,721 paid on December 31, 1998), 3) Renewable Energy Pilot Program ($300,000 each year), 4) Energy Cooperative Association of Pennsylvania (contribution of $4 million) and 5) Universal Service and Energy Conservation Program ($8.082 million per year).

 

     In response to environmental issues over the past 30 years, the Distribution Companies and Allegheny Energy Supply spent over $1.6 billion in capital expenditures and approximately $200 million annually in operations and maintenance. Allegheny is committed to environmental stewardship and the research needed to provide answers to difficult compliance problems. These actions will mitigate the impact of the Distribution Companies' and Allegheny Energy Supply's operations on the environment and ameliorate any alleged climate change impacts.



REGULATION

 

     Allegheny is subject to the broad jurisdiction of the SEC under PUHCA. The Distribution Companies are regulated as to substantially all of their operations by regulatory commissions in the states in which they operate. These companies and Allegheny Energy Supply's unregulated generation are also regulated as to various aspects of their business by the FERC. In addition, they are subject to numerous other local, state, and federal laws, regulations, and rules.

 

     In June 1995, the SEC published its report, which recommended changes to PUHCA, including a recommendation to Congress to repeal the entire act. Bills have been introduced in the Congress to repeal PUHCA, but have not passed. Allegheny cannot predict what changes, if any, will be made to PUHCA as a result of these activities.

 

     In 2000, the Distribution Companies continued to take part in and fund

51

various programs to assist low-income customers, customers with special needs, and/or customers experiencing temporary financial hardship.

 

ITEM 2. PROPERTIES

 

     Substantially all of the properties of Monongahela and Potomac Edison are held subject to the lien of indentures securing their first mortgage bonds. In many cases, the properties of Monongahela, Potomac Edison, West Penn and Allegheny Energy Supply may be subject to certain reservations, minor encumbrances, and title defects which do not materially interfere with their use. Some of the properties are also subject to a second lien securing certain solid waste disposal and pollution control notes. The indenture under which AGC's unsecured debentures and medium-term notes 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 and medium-term notes are contemporaneously secured equally and ratably with all other indebtedness secured by such lien. Transmission and distribution lines, in substantial part, 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 transmission and distribution lines and substations are located. Each of the Distribution Companies possesses the power of eminent domain with respect to its public utility operations. (See also ITEM 1. BUSINESS and ALLEGHENY MAP.)

 

     MGS owns more than 375 natural gas wells located throughout West Virginia and has active leaseholds that cover more than 86,000 acres. In addition to its production assets, MGS owns (1) approximately 125 miles of high-pressure transmission facilities running from Jackson County, West Virginia, west to Huntington (Cabell County), West Virginia, where it terminates at various delivery locations into the facilities of Mountaineer, Columbia Gas, and the industrial plant facilities of various industrial end-users, and (2) approximately 400 miles of gathering lines located in the same general vicinity.

 

ITEM 3. LEGAL PROCEEDINGS

 

     On August 13, 1996, American Bituminous Partners, L.P., (AmBit), filed a request for arbitration alleging that the energy rate payable under its purchase power contract with Monongahela had been improperly calculated. The arbitration proceeding was bifurcated into a liability phase and, if necessary, a damages phase. On February 18, 1998, the arbitration panel made a determination in the liability phase. They determined that certain lime handling costs should have been a component of the energy rate and therefore were improperly accounted for in 1995 and 1996. Ambit and Monongahela entered into a Settlement Agreement, subject to the approval of the West Virginia PSC, resolving all disputes presented in, or which could have been presented in, the arbitration. By Order entered August 7, 2000, the Public Service Commission approved the Settlement Agreement.

52

 

     On December 17, 1999, AES/Beaver Valley, Inc., (AES/BV) filed a demand for arbitration with the American Arbitration Association. AES/BV requested a declaratory judgment that the Electric Energy Purchase Agreement (EEPA) approved by the PaPUC in 1986 continues to govern the transaction between West Penn and AES/BV for the sale of up to 125 MWH per hour of power as set forth in the EEPA, even if AES/BV's proposed improvements to the plant to comply with the more rigorous NOx standards result in an increase in the amount of energy the plant produces annually. AES/BV also requested an award of its attorneys fees and costs. On April 4, 2000, an arbitrator granted the declaratory judgment request of AES/BV, but denied its request for attorneys fees and costs.

 

     As of February 16, 2001, Monongahela has been named as a defendant along with multiple other defendants in a total of 7,825 pending asbestos cases involving one or more plaintiffs. Potomac Edison and West Penn have been named as defendants along with multiple other defendants in approximately one-half of those cases. Because these cases are filed in a "shotgun" format wherein multiple plaintiffs file claims against multiple defendants in the same case, it is presently impossible to determine the actual number of cases in which plaintiffs make claims against the Distribution Companies. However, based upon past experience and available data, it may be estimated that about one-third of the total number of cases filed actually involve claims against any or all of the Distribution Companies. All complaints allege that the plaintiffs sustained unspecified injuries resulting from claimed exposure to asbestos in various generating plants and other industrial facilities operated by the various defendants, although all plaintiffs do not claim exposure at facilities operated by all defendants. With very few exceptions, plaintiffs claiming exposure at stations operated by the Distribution Companies were employed by third-party contractors, not the Distribution Companies. Three plaintiffs are known to be either present or former employees of Monongahela. Each plaintiff generally seeks compensatory and punitive damages against all defendants in amounts of up to $1 million and $3 million, respectively; in those cases, which include a spousal claim for loss of consortium, damages are generally sought against all defendants in an amount of up to an additional $1 million. A total of 1,465 cases have been previously settled and/or dismissed against Monongahela for an amount substantially less than the anticipated cost of defense. While the Distribution Companies believe that all of the cases are without merit, they cannot predict the outcome nor are they able to determine whether additional cases will be filed.

 

     On January 27, 1995, Allegheny filed a declaratory judgment action in the Court of Common Pleas of Westmoreland County, Pa., against its historic comprehensive general liability (CGL) insurers. This suit sought a declaration that the CGL insurers have a duty to defend and indemnify the Distribution Companies in the asbestos cases, as well as in certain environmental actions. Three insurers settled. Another was dismissed as a party. The declaratory judgment action may be re-filed against that party in a different venue. Settlements from other insurance carriers are also being pursued. The final outcome of such proceedings, however, cannot be predicted.

53

 

     On March 4, 1994, the Distribution Companies received notice that the EPA had identified them as potentially responsible parties (PRPs) under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, with respect to the Jack's Creek/Sitkin Smelting Superfund Site (Site). There are approximately 175 other PRPs involved. A Remedial Investigation/Feasibility Study (RI/FS) prepared by the EPA originally indicated remedial alternatives, which ranged as high as $113 million, to be shared by all responsible parties. A PRP Group consisting of approximately 40 members, and to which the Distribution Companies belong, has been formed and has submitted an addendum to the RI/FS, which proposes a substantially less expensive cleanup remedy. In 1999, the PRP Group entered into a consent order with the EPA to remediate the site. A final determination has not been made for the Distribution Companies' share of the remediation costs. However, at this time it is estimated that the effect on the Distribution Companies will not be material.

 

     On October 1, 1996, Potomac Edison received a questionnaire from the EPA concerning a release or threat of release of hazardous substances, pollutants, or contaminants into the environment at the Butler Tunnel Site located in Luzerne County, Pa. Potomac Edison notified the EPA that it has no records or recollection of any business relations with the site or any of the companies identified in the questionnaire. It is not possible to determine at this time what effect, if any, this matter may have on Potomac Edison.

 

     In 1979, National Steel Corporation (National Steel) filed suit against AE and certain subsidiaries in the Circuit Court of Hancock County, W.Va., alleging damages of approximately $7.9 million as a result of an order issued by the West Virginia PSC requiring curtailment of National Steel's use of electric power during the United Mine Workers' strike of 1977-8. A jury verdict in favor of AE and the subsidiaries was rendered in June 1991. National Steel has filed a motion for a new trial, which is still pending before the Circuit Court of Hancock County. AE and the subsidiaries believe the motion is without merit; however, they cannot predict the outcome of this case.

 

     The Attorney General of the State of New York and the Attorney General of the State of Connecticut, in letters dated September 15, 1999, and November 3, 1999, respectively, notified AE of their intent to commence civil actions against AE and/or its subsidiaries alleging violations at the Fort Martin Power Station under the federal Clean Air Act, which requires power plants that make major modifications to comply with the same emission standards applicable to new power plants. Similar actions may be commenced by other governmental authorities in the future. Fort Martin is located in West Virginia and is now jointly owned by Allegheny Energy Supply and Monongahela. Both Attorneys General stated their intent to seek injunctive relief and penalties. In addition, the Attorney General of the State of New York indicated that he may assert claims under the state common law of public nuisance seeking to recover, among other things, compensation for alleged environmental damage caused in New York by the operation of the Fort Martin Power Station. At this time, AE and its subsidiaries are not able to determine what effect, if any, these actions may have on them.

54

 

     On August 2, 2000, AE received a letter from the EPA requiring it to provide certain information on the following ten electric generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. These electric generating stations are owned by Allegheny Energy Supply and Monongahela Power. The letter requested information under Section 114 of the federal Clean Air Act to determine compliance with federal Clean Air Act and state implementation plan requirements, including potential application of the new source performance standards, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in some cases. AE believes its subsidiaries' generating facilities have been operated in accordance with the Clean Air Act and the rules implementing that Act. The experience of other utilities, however, suggests that in recent years, the EPA may have revised its interpretation of the rules regarding the determination of whether an action at a facility constitutes routine maintenance, which would not trigger the requirements of the new source performance standards, or a major modification of the facility, which would require compliance with the new source performance standards. At this time, AE is not able to determine what effect, if any, the EPA's inquiry may have on its operations. If new source performance standards are applied to Allegheny generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures.

 

     In June, 2000, Monongahela was contacted by the U.S. Environmental Protection Agency (EPA) and the Environmental Enforcement Section of the Department of Justice (DOJ) concerning the release of approximately 19,000 gallons of non-PCB oil to the environment, following the catastrophic failure of a 500 MVA, 265 kV transformer on April 11, 1998 at Monongahela's Belmont substation. Monongahela informed the EPA and DOJ that it responded to this release immediately, thereby preventing any of the oil from reaching major waterways. Monongahela also informed the federal agencies that it has been working in conjunction with West Virginia Division of Environmental Protection regarding site clean-up and remediation. Monongahela continues to cooperate with EPA and DOJ toward resolution of the agencies' concerns. At this time, Monongahela cannot predict the outcome of this matter but reasonably believes it will not have a material impact on Monongahela.

 

      In connection with litigation concerning DQE, Inc.'s unilateral termination of the Agreement and Plan of Merger dated April 5, 1997 with AE, on May 17, 2000, the Third Circuit Court of Appeals affirmed the District Court's decision that DQE did not breach the merger agreement. No request for reconsideration or other appeal has been filed.

 

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

 

     AE, Monongahela, Potomac Edison, West Penn and AGC did not submit any matters to a vote of shareholders during the fourth quarter of 2000.

55

 

 

The names of the executive officers of each company, their ages as of December 31, 2000, the positions they hold, or held during 2000, and their business experience during the past five years appears below:

Executive Officers of the Registrants

Position (a) and Period of Service

 

Name

Age

AE

MP

PE

WP

AGC

             

Paul M. Barbas(b)

44

Vice President

(7/99 - )

       

David C. Benson(c)

         

Vice President

(2/00 -

Regis F. Binder(d)

48

Vice President & Treasurer

(12/98 - )

Treasurer

(12/98 - )

Treasurer

(12/98 - )

Treasurer

(12/98 - )

V.P.

(2/00- )

and

Treasurer

(12/98 - )

Eileen M. Beck(e)

59

Secretary

(1988-7/00)

Previously

Asst. Treasurer

(1979-95)

Secretary

(1995-7/00)

Previously

Asst. Treasurer

(1981-95)

Asst. Secretary

(1988-94)

Secretary

(1996-7/00)

Previously

Asst. Secretary

(1988-95)

Secretary

(1996-7/00)

Previously

Asst. Secretary

(1988-95)

Secretary

(1982-7/00)

Marleen L. Brooks(f)

49

Secretary

(7/00 - )

Previously,

Asst. Secretary

(4/00-7/00)

Secretary

(7/00 - )

Previously,

Asst. Secretary

(4/00-7/00)

Secretary

(7/00 - )

Previously,

Asst. Secretary

(4/00-7/00)

Secretary

(7/00 - )

Previously,

Asst. Secretary

(4/00-7/00)

Secretary

(7/00 - )

Previously,

Asst. Secretary

(4/00-7/00)

Donald R. Feenstra(g)

         

Vice President

(2/00-1/01)

Richard J. Gagliardi

50

Vice President

(1991 - )

Asst. Secretary

(1990-96)

   

Vice President

(2/00 - )

Previously,

Asst. Treasurer

(1982-96)

56

 

Executive Officers of the Registrants (continued)

Position (a) and Period of Service

Name

Age

AE

MP

PE

WP

AGC

             

James R. Haney(h)

44

 

Vice President

(1998- )

Vice President

(1998- )

Vice President

(1998- )

 

Thomas K. Henderson

60

Vice President

(1997- ) &

General Counsel

(5/99- )

Vice President

(1995- )

Vice President

(1995- )

Vice President

(1985- )

Director & V.P.

(1996- )

Kenneth M. Jones(i)

63

V.P.

(1991-4/00)

Previously,

Controller

(1991-1998)

     

Director & V.P.

(1991-1999)

Thomas J. Kloc

48

Vice President & Controller

(1998- )

Controller

(1996- )

Controller

(1988- )

Controller

(1995- )

V.P.

(1999- )

Controller &

(1988- )

Director

(1999-2/00)

James D. Latimer(j)

62

 

Vice President

(1995-11/00)

Vice President

(1995-11/00)

Previously

Exec. V.P.

(1994-95)

Vice President

(1995-11/00)

 

Ronald A. Magnuson(k)

43

 

Vice President

(1999- )

Vice President

(1999- )

Vice President

(1999- )

 

Michael P. Morrell(l)

52

Senior Vice President

(1996- )

Dir. V.P.

(1996- )

Dir. V.P.

(1996- )

Dir. V.P.

(1996- )

Dir. V.P.

(1996- )

Alan J. Noia

53

Chairman & CEO

(1996- )

& President & Director

(1994- )

Previously,

COO

(1994-96)

Chairman & CEO

(1996- )

& Director

(1994- )

Chairman & CEO

(1996- )

& Director

(1990- )

Chairman & CEO

(1996- )

& Director

(1994- )

Chairman & CEO

(1996- )

Previously,

President

(1996-2/00)

Director & V.P.

(1994-96)

Karl V. Pfirrmann(m)

   

Vice President

(5/00- )

Vice President

(5/00- )

Vice President

(5/00- )

 

Jay S. Pifer

63

Senior Vice President

(1996- )

President & Director

(1995- )

President & Director

(1995- )

President

(1990- )

& Director

(1992- )

 

57

Executive Officers of the Registrants (continued)

Position (a) and Period of Service

             

Victoria V. Schaff(n)

56

Vice President

(1997- )

Vice President

(5/00- )

& Director

(2/01 - )

Vice President

(5/00- )

& Director

(2/01 - )

Vice President

(5/00- )

& Director

(2/01 - )

Director

(2/01 - )

Peter J. Skrgic(o)

59

Senior Vice President

(1994-2/01)

Vice President

(1996-2/01)

& Director

(1990-2/01)

Vice President &

Director

(1990-2/01)

Vice President

(1996-2/01)

& Director

(1990-2/01)

President &

Director

(2/00-2/01)

Previously,

Vice President &

Director

(1989-2/00)

Robert R. Winter

57

 

Vice President

(1987- )

Vice President

(1995- )

Vice President

(1995- )

 

(a)

All officers and directors are elected annually, except the Board of AE, which is a staggered Board.

(b)

Prior to his appointment as Vice President of AE, Mr. Barbas was President, GE Capital Rental Services (3/97-2/99) and President, GE Capital Computer Rental Services (10/93-3/97).

(c)

Prior to his appointment as Vice President of AGC, Mr. Benson was Vice President, AESC (7/98); Vice President & Assistant Treasurer AESC(5/96-7/98); and Vice President AESC (6/95-5/96).

(d)

Prior to his appointment as Vice President and Treasurer of AE and Treasurer of MP, PE, WPP and AGC, Mr. Binder was Executive Director, Regulation and Rates for AESC (1997-1998); General Manager, Industrial Marketing for AESC (1996-1997); and Director, Rates for AESC (1995-1996).

(e)

Ms. Beck retired effective July 1, 2000.

(f)

Prior to her appointment as Assistant Secretary, Ms. Brooks was Senior Attorney for AESC (2/99 - 4/00); and Attorney for AESC and Potomac Edison (7/81 - 2/99).

(g)

Mr. Feenstra retired effective 1/01. Prior to his appointment as Vice President of AGC, Mr. Feenstra was Vice President of AESC from 6/95-1/01.

(h)

Prior to his appointment as Vice President Customer Operations, Mr. Haney was Executive Director, Operating Business Unit (8/98-10/98); Director, Operations Services (5/96-8/98); Director, Transmission Projects (12/95-5/96); Manager, Construction (AESC) (2/95-12/95).

(i)

Mr. Jones retired effective April 1, 2000.

(j)

Mr. Latimer retired effective November 1, 2000.

(k)

Prior to his appointment as Vice President of MP, PE and WPP, Mr. Magnuson was Executive Director, Customer Affairs (4/99-7/99); Executive Director, Human Resources (10/98-4/99); and Director Human Resources (1/95-10/98).

(l)

Prior to his appointment as Senior Vice President of AE and Vice President of MP, PE WPP and AGC, Mr. Morrell was V.P. - Regulatory and Public Affairs, Jersey Central Power & Light Company (JCPP&L) (8/94-4/96).

(m)

Prior to his appointment as Vice President of MP, PE, WPP, Mr. Pfirrmann was Vice President AESC (9/95-5/96); Vice President MP, PE, WP(5/96-8/98); and Vice President AESC (8/98-5/00).

(n)

Prior to her appointment as Vice President of AE, Ms.Schaff was a Vice President of AESC (1/96-1/97) and a Federal Affairs Representative with The Union Electric Company (4/88-12/95).

(o)

Mr. Skgric resigned all of his positions effective February 1, 2001.

58

 

PART II

 

ITEM 5.     MARKET FOR THE REGISTRANTS' COMMON

            EQUITY AND RELATED STOCKHOLDER MATTERS

 

     AE

 

     AYE is the trading symbol of the common stock of AE on the New York, Chicago, and Pacific Stock Exchanges. The stock is also traded on the Amsterdam (Netherlands) and other stock exchanges. As of December 31, 2000, there were 40,589 holders of record of AE's common stock.

 

     The tables below show the dividends paid and the high and low sale prices of the common stock for the periods indicated:

 

2000

1999

 

Dividend

High

Low

Dividend

High

Low

1st Quarter

43 cents

$29.5625

$23.625

43 cents

$34.5

$28.6875

2nd Quarter

43 cents

$31.75

$26.6875

43 cents

$35.1875

$29.50

3rd Quarter

43 cents

$39.875

$27.75

43 cents

$34.875

$31.0

4th Quarter

43 cents

$48.75

$36.6875

43 cents

$33.125

$26.1875

 

     The high and low prices through March 10, 2001 were $49.00 and $39.5625 The last reported sale on that date was at $47.34.

 

     Monongahela, Potomac Edison, and West Penn. The information required by this Item is not applicable as all the common stock of those companies is held by AE.

 

     AGC. The information required by this Item is not applicable as all the common stock of AGC is held by Monongahela and Allegheny Energy Supply Company, LLC.

59




ITEM 6.
SELECTED FINANCIAL DATA

 

Page No.

AE

D-1

Monongahela

D-6

Potomac Edison

D-9

West Penn

D-12

AGC

D-15

The information required by this Item was furnished in the copy of the Form 10-K filed with the Securities and Exchange Commission and is also found in AE's Annual Report to Stockholders for 2000. You may obtain an Annual Report to Stockholders upon making a written or an oral request directed to: Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740, Attention: Marleen L. Brooks, Secretary (tel. 301-790-3400).

 

Allegheny Energy, Inc.

Condensed Financial Statements

 

 

 

 

 

Year ended December 31, 2000

 

Monongahela

Power

Company

and Subsidiaries

The Potomac

Edison

Company

and Subsidiaries

 

West Penn

Power Company

and Subsidiaries

 

 

Allegheny

Ventures,

Inc.

and Subsidiaries

Allegheny Energy

Supply

Company, LLC

and Subsidiary

(Thousands of dollars)

Balance Sheets

Assets

Property, plant, and equipment*

$2,545,764

$1,410,382

$1,654,283

$25,341

$3,807,691

Accumulated depreciation

(1,152,953)

(514,167)

(543,000)

(1,040)

(1,754,823)

1,392,811

896,215

1,111,283

24,301

2,052,868

Excess of cost over net assets acquired

200,183

1,152

Cash and temporary cash investments

3,658

4,685

6,116

2,422

420

Other current assets

282,525

139,891

282,428

11,145

535,478

Regulatory assets

90,004

53,712

428,953

Other

60,387

14,258

10,856

25,072

18,806

Total

$2,029,568

$1,108,761

$1,839,636

$64,092

$2,607,572

*Includes construction work in progress

$ 33,476

$ 14,122

$ 25,459

$107,284

Capitalization and liabilities

Common stock, other paid-in capital,

retained earnings, and accumulated other

comprehensive income

$ 707,899

$ 412,753

$ 422,121

$58,741

$759,643

Preferred stock

74,000

Long-term debt and QUIDS

606,734

410,011

678,284

563,433

Minority interest

38,980

Short-term debt

37,015

42,685

219,015

Other current liabilities

277,739

94,394

212,574

5,345

535,084

Unamortized investment credit

11,859

10,555

20,899

65,823

Deferred income taxes

219,647

89,285

189,302

399,751

Regulatory liabilities

50,231

32,309

15,162

23,625

Adverse power purchase commitments

278,338

Other

44,444

16,769

22,956

6

2,218

Total

$2,029,568

$1,108,761

$1,839,636

$64,092

$2,607,572

Statements of operations

Operating revenues

$ 828,047

$ 827,818

$1,045,627

$22,626

$2,259,572

Operating expenses

692,680

707,029

881,311

20,981

2,151,660

Operating income

135,367

120,789

164,316

1,645

107,912

Other income and deductions

4,186

6,125

4,379

821

3,542

Income before interest charges, preferred

dividends, and extraordinary charge, net

139,553

126,914

168,695

2,466

111,454

Interest charges and preferred dividends

50,013

42,529

66,293

264

33,458

Balance for common stock before

extraordinary charge, net

89,540

84,385

102,402

2,202

77,996

Extraordinary charge, net

(63,124)

(13,899)

Minority interest

(2,508)

Balance for common stock

$ 26,416

$ 70,486

$ 102,402

$ 2,202

$75,488

D-1

Allegheny Energy, Inc.

Consolidated Statistics

Year ended December 31

2000

1999

1998

1997

1996

1995

1990

Summary of operations (Millions of dollars)

Operating revenues

$4,011.9

$2,808.4

$2,576.4

$2,369.5

$2,327.6

$2,315.2

$1,829.9

Operation expense

2,602.4

1,498.1

1,286.0

1,065.9

1,013.0

1,024.9

866.6

Maintenance

230.3

223.5

217.5

230.6

243.3

249.5

182.0

Restructuring charges and asset write-offs

103.9

23.4

Depreciation

247.9

257.5

270.4

265.7

263.2

256.3

180.9

Taxes other than income

210.2

190.3

194.6

187.0

185.4

184.7

152.5

Taxes on income

184.8

164.4

168.4

168.1

128.0

154.2

106.4

Allowance for funds used during construction

(7.2)

(6.9)

(5.0)

(8.3)

(5.9)

(8.2)

(7.2)

Interest charges, preferred dividends, and preferred

redemption premiums

234.4

197.7

189.7

197.2

191.1

196.9

161.1

Other income and deductions

(4.5)

(1.6)

(8.2)

(18.0)

(4.4)

(6.2)

(3.8)

Consolidated income before extraordinary charge

313.7

285.4

263.0

281.3

210.0

239.7

191.4

Extraordinary charge, net (a)

(77.0)

(27.0)

(275.4)

Consolidated net income (loss)

$236.6

$258.4

($12.4)

$281.3

$210.0

$239.7

$191.4

Common stock data (b)

Shares issued (thousands)

122,436

122,436

122,436

122,436

121,840

120,701

106,984

Treasury shares (thousands)

(12,000)

(12,000)

Shares outstanding (thousands)

110,436

110,436

122,436

122,436

121,840

120,701

106,984

Average shares outstanding (thousands)

110,436

116,237

122,436

122,208

121,141

119,864

106,102

Earnings per average share: (c)

Consolidated income before extraordinary

Charge

$2.84

$2.45

$2.15

$2.30

$1.73

$2.00

$1.80

Extraordinary charge, net (a)

(0.70)

(0.23)

(2.25)

Consolidated net income (loss)

$2.14

$2.22

($0.10)

$2.30

$1.73

$2.00

$1.80

Dividends paid per share

$1.72

$1.72

$1.72

$1.72

$1.69

$1.65

$1.58

Dividend payout ratio (d)

60.6%

64.6%

73.5%

74.7%

97.5%

82.5%

87.6%

Shareholders

40,589

44,873

48,869

53,389

58,677

63,280

63,201

Market price per share:

High

$48 3/4

$35 3/16

$34 15/16

$32 19/32

$31 1/8

$29 1/4

$21 1/16

Low

$23 5/8

$26 3/16

$26 5/8

$25 1/2

$28

$21 1/2

$17

Close

$48 3/16

$26 15/16

$34 1/2

$32 1/2

$30 3/8

$28 5/8

$18 7/16

Book value per share

$15.76

$15.35

$16.61

$18.43

$17.80

$17.65

$15.26

Return on average common equity (d)

18.28%

16.16%

13.26%

12.63%

9.69%

11.35%

11.78%

Capitalization data (Millions of dollars)

Common stock

$1,740.7

$1,695.3

$2,033.9

$2,256.9

$2,169.1

$2,129.9

$1,632.3

Preferred stock:

Not subject to mandatory redemption

74.0

74.0

170.1

170.1

170.1

170.1

235.1

Subject to mandatory redemption

30.6

Long-term debt and QUIDS

2,559.5

2,254.5

2,179.3

2,193.1

2,397.1

2,273.2

1,642.2

Total capitalization

$4,374.2

$4,023.8

$4,383.3

$4,620.1

$4,736.3

$4,573.2

$3,540.2

Capitalization ratios:

Common stock

39.8%

42.1%

46.4%

48.8%

45.8%

46.6%

46.1%

Preferred stock:

Not subject to mandatory redemption

1.7

1.9

3.9

3.7

3.6

3.7

6.6

Subject to mandatory redemption

0.9

Long-term debt and QUIDS

58.5

56.0

49.7

47.5

50.6

49.7

46.4

Total assets (Millions of dollars)

$7,697.0

$6,852.4

$6,535.2

$6,654.1

$6,618.5

$6,447.3

$4,561.3

a Write-off in connection with deregulation proceedings in West Virginia, Virginia, Ohio, Maryland, and Pennsylvania and costs associated with the reacquisition of first mortgage bonds.

b Reflects a two-for-one common stock split effective November 4, 1993.

c Basic and diluted earnings per average share.

d Excludes the extraordinary charge, net, and Pennsylvania restructuring activities in 1998, the extraordinary charge and other charges for merger-related costs and a long dormant pumped-storage generation project in 1999, and the extraordinary charge in 2000. Includes the effect of internal restructuring in 1995 and 1996.

D-2

Allegheny Energy, Inc.

Consolidated Statistics (continued)

Year ended December 31

2000

1999

1998

1997

1996

1995

1990

Property data (Millions of dollars)

Gross property

$9,507.0

$8,839.7

$8,395.3

$8,451.4

$8,206.2

$7,812.7

$5,986.2

Accumulated depreciation

(3,967.6)

(3,632.6)

(3,395.6)

(3,155.2)

(2,910.0)

(2,700.1)

(1,946.1)

Net property

$5,539.4

$5,207.1

$4,999.7

$5,296.2

$5,296.2

$5,112.6

$4,040.1

Gross additions during year

Regulated

$207.6

$266.2

$229.4

$284.7

$289.5

$319.1

$321.8

Unregulated and other

$195.6

$141.3

$1.8

$1.4

$178.5

Ratio of provisions for depreciation to

depreciable property

2.85%

3.23%

3.28%

3.34%

3.47%

3.50%

3.27%

Revenues (Millions of dollars) (e)

Residential

$1,018.6

$930.3

$880.6

$892.9

$932.2

$927.0

$649.5

Commercial

536.5

500.3

501.4

490.5

492.7

493.7

343.0

Industrial

772.8

720.5

753.5

748.1

752.9

770.2

571.5

Wholesale and street lighting

57.4

42.4

69.0

65.1

66.6

59.6

47.1

Revenues from regular utility customers

2,385.3

2,193.5

2,204.5

2,196.6

2,244.4

2,250.5

1,611.1

Other non-gWh

40.7

9.8

9.9

6.4

7.7

6.5

8.5

Bulk power

135.8

45.7

69.8

39.6

22.4

13.0

160.0

Transmission and other energy services

73.2

61.0

45.2

41.1

52.4

45.2

50.3

Total regulated revenues

$2,635.0

$2,310.0

$2,329.4

$2,283.7

$2,326.9

$2,315.2

$1,829.9

Total unregulated revenues

$2,281.6

$879.4

$247.0

$85.8

$0.7

Other

$22.6

$8.9

Sales volumes-gWh

Residential

14,062

13,562

12,939

12,832

13,328

13,003

11,264

Commercial

9,510

8,955

8,626

8,176

8,132

7,963

6,670

Industrial

20,320

19,846

19,675

19,040

18,568

18,457

16,511

Wholesale and street lighting

1,531

1,478

1,409

1,422

1,456

1,304

1,101

Regular utility transactions

45,423

43,841

42,649

41,470

41,484

40,727

35,546

Bulk power

750

571

3,037

1,667

966

507

5,432

Transmission and other energy services

10,851

8,450

7,345f

12,367

17,402

14,586

17,016

Total regulated transactions

57,024

52,862

53,031

55,504

59,852

55,820

57,994

Total unregulated transactions

41,707

15,854

8,278

3,734

109

Output and delivery-gWh

Steam generation

46,773

44,776

44,323

43,463

40,067

39,174

41,933

Hydro and pumped-storage generation

1,969

1,648

1,326

1,171

1,348

1,234

1,426

Pumped - storage input

(2,327)

(1,963)

(1,498)

(1,298)

(1,405)

(1,390)

(1,568)

Purchased power

43,917

17,365

11,505

6,485

5,518

5,021

1,560

Transmission and other energy services

10,851

8,450

7,777

12,367

17,402

14,586

17,016

Combustion turbines

56

7

Losses and system uses

(3,075)

(3,066)

(2,124)

(2,950)

(2,969)

(2,805)

(2,373)

Total transactions as above

98,164g

67,217g

61,309

59,238

59,961

55,820

57,994

Energy supply

Generating capability-MW

Regulated-owned

2,356

4,451

8,121

8,071

8,070

8,070

7,991

Unregulated-owned

6,407

4,142

276

276

Unregulated contracts (h)

479

299

299

299

299

299

160

Maximum hour peak-MW

7,791i

7,788i

7,314i

7,423

7,500

7,280

6,070

Load factor-regulated

70.2%j

70.5%j

69.1%j

68.3%

67.5%

68.3%

71.3%

Heat rate-Btus per kWh

9,919k

9,963

9,939

9,936

9,910

9,970

9,944

Fuel costs-cents per million Btus

118.57l

119.61

128.92

130.05

129.22

130.20

140.97

e Eliminations between regulated and unregulated are shown on page 31.

f Excludes 432 gWh delivered to customers participating in the Pennsylvania pilot program that are included in regulated utility transactions sales volumes

g Net of 1,499 gWh eliminated between regulated and unregulated.

h Capability available through contractual arrangements with unregulated generators.

i Peak coincident load of all customers provided delivery service within the Company's service territory irrespective of the generation service chosen by the customers therein.

j Based on peak coincident load.

k Includes the combustion turbines' heat rate.

l Includes the combustion turbines' fuel costs.

D-3

Allegheny Energy, Inc.

Regulated Statistics

               

Year ended December 31

2000

1999

1998

1997

1996

1995

1990

Customers (thousands) a

Residential

1,495.1

1,250.6

1,236.9

1,224.9

1,213.7

1,204.4

1,133.4

Commercial

187.9

158.1

154.7

151.5

148.5

146.0

132.2

Industrial

26.3

25.9

25.5

25.2

25.0

24.6

22.8

Other

1.3

1.3

1.3

1.3

1.3

1.3

1.3

Total customers

1,710.6

1,435.9

1,418.4

1,402.9

1,388.5

1,376.3

1,289.7

Average annual use (kWh per customer b )

Residential

10,993

10,913

10,486

10,521

11,042

10,865

10,011

All retail service

28,847

28,285

28,174

28,647

29,085

28,908

26,996

Average rate (cents per kWh) b

Residential

6.89

7.03

6.90

6.96

6.99

7.13

5.77

All retail service

5.30

5.45

5.32

5.36

5.46

5.58

4.56

a Electric and gas customers in the Company's regulated franchised service territory receiving delivery service.

b Use and rate statistics are calculated based on full-service customers (customers receiving both generation and delivery from the Company).

Dividends Paid-Range of Common Stock Prices Per Share

2000

1999

NYSE Composite Transactions

 

Dividend

High

Low

Close

Dividend

High

Low

Close

1st Quarter

43cents

$29 9/16

$23 5/8

$27 3/4

43cents

$34 1/2

$28 11/16

$29 1/2

2nd Quarter

43

31 3/4

26 11/16

27 9/16

43

35 3/16

29 1/2

32 1/16

3rd Quarter

43

39 7/8

27 3/4

38

43

34 7/8

31

31 7/8

4th Quarter

43

48 3/4

36 11/16

48 3/16

43

33 1/8

26 3/16

26 15/16

The high and low prices in 2001 were $47.4375 and $41.0625 through February 1, 2001. The last reported sale on that date was $45.10.

Quarterly Financial Information (Unaudited)

(Millions of dollars)

Basic and Diluted Earnings Per Average Share

Quarter Ended

Operating

Revenues

Operating

Income

Consolidated

Income Before

Extraordinary

Charge, Net

Extraordinary

Charge, Net

Consolidated

Net Income

(Loss)

Consolidated

Income Before

Extraordinary

Charge, Net

Extraordinary

Charge, Net

Consolidated

Net Income

(Loss)

March 1999

$ 690.0

$140.2

$97.8

$97.8

$.80

$.80

June 1999

643.4

111.7

64.5

64.5

.55

.55

September 1999

741.4

117.2

71.3

71.3

.63

.63

December 1999*

733.7

105.5

51.8

$(27.0)

24.8

.46

$(.24)

.22

March 2000**

866.8

140.1

86.4

(70.5)

15.9

.78

(.64)

.14

June 2000

865.3

118.9

71.5

71.5

.65

.65

September 2000

1,058.5

128.0

76.1

76.1

.69

.69

December 2000***

1,221.3

149.2

79.7

(6.5)

73.2

.72

(.06)

.66

*  Results for the fourth quarter of 1999 reflect charges for Maryland restructuring, retiring debt related to the securitization

of Pennsylvania stranded costs, merger-related costs, and a long dormant pumped-storage generation project.

** Results for the first quarter of 2000 reflect charges for West Virginia restructuring.

*** Results for the fourth quarter of 2000 reflect charges for Ohio and Virginia restructuring.

D-4

Allegheny Energy, Inc.

Investor Information

 

Dividend Declarations 

Dividends are normally declared on the first Thursday of March, June, September, and December. Record dates are normally the second Monday after the dividend is declared, with payment dates the last business day of March, June, September, and December.

 

Dividend Reinvestment and Stock Purchase Plan 

Our Dividend Reinvestment and Stock Purchase Plan provides shareholders with a convenient way to purchase additional shares of the Company's stock. Participants may at the time of each cash dividend payment on the stock have all or part of their dividends automatically invested in additional shares or invest any additional amount they wish between $50 and $10,000 in such shares or do both. The offering of shares under the Plan is made only by Prospectus. To get the Prospectus and an Authorization Form to enroll in the Plan, contact Mellon Investor Services, L.L.C., at 1-800-648-8389 or write to Gregory L. Fries, Manager, Investor Relations, Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740-1766, or e-mail: investorinfo@alleghenyenergy.com.

 

Annual Meeting 

The Annual Meeting of Shareholders will be held on the eleventh floor of the offices of J.P. Morgan Chase & Co., 270 Park Ave., New York, NY, on Thursday, May 10, 2001, at 9:30 a.m.

 

Options Trading

Allegheny Energy, Inc. has been selected for options trading on The American Stock Exchange, the Pacific
Exchange, and the Chicago Board Options Exchange.

 

Form 10-K 

The Company will provide without charge to each beneficial holder of its common stock, on the written request of such person, a copy of Allegheny Energy's combined Annual Report to the Securities and Exchange Commission on Form 10-K for 2000. Any such request should be directed to Cynthia A. Shoop, Vice President, Corporate Communications, Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740-1766, or investorinfo@alleghenyenergy.com. The report can also be found in electronic format at www.alleghenyenergy.com.

 

Duplicate Mailings/Direct Deposit of Dividends 

If you receive duplicate mailings of the Annual Report or wish to have your dividends deposited directly to your banking institution, please notify Mellon Investor Services, L.L.C., P.O. Box 3316, South Hackensack, NJ 07606. To speak to a representative responsible for Allegheny Energy shareholder accounts, call 1-800-648-8389.

 

Stock Transfer Agent and Registrar 

Mellon Investor Services, L.L.C., Overpeck Centre, 85 Challenger Road, Ridgefield Park, NJ 07660. The internet address is www.mellon-investor.com.

D-5

Monongahela Power Company
and Subsidiaries

QUARTERLY FINANCIAL INFORMATION

(Thousands of Dollars)

Quarter Ended

 

2000

 

1999

 

Mar

June

Sept

Dec

 

Mar

June

Sept

Dec

                   

Operating revenues

$193,477

$176,734

$194,942

$262,894

 

$170,642

$160,459

$178,330

$163,904

Operating income

32,718

25,543

37,633

39,473

 

30,321

25,102

32,595

31,019

Consolidated

net Income (loss)

(33,809)

17,275

28,390

19,599

 

23,250

18,556

26,631

23,890

SUMMARY OF OPERATIONS

Year ended December 31

(Thousands of Dollars)

2000

1999

1998

1997

1996

1995

Electric and gas operating

revenues:

Residential

$230,924

$210,757

$200,896

$199,931

$206,033

$209,065

Commercial

144,345

130,052

126,464

118,825

121,631

124,457

Industrial

220,593

217,792

208,613

196,716

200,970

212,427

Wholesale and street lighting

7,468

7,138

7,656

7,600

7,513

7,255

Electric revenues from regular customers

603,330

565,739

543,629

523,072

536,147

553,204

Affiliated

101,975

84,747

77,314

83,600

74,825

73,216

Gas revenues

103,579

Other non-kWh

4,832

4,299

4,426

4,379

4,136

3,722

Bulk power

818

6,567

8,509

7,299

4,772

2,749

Transmission and other energy

services

13,513

11,983

11,244

9,961

12,591

10,589

Total revenues

828,047

673,335

645,122

628,311

632,471

643,480

Operating expense

444,696

345,565

313,795

305,487

310,480

330,740

Maintenance

70,850

63,993

67,033

70,561

74,735

73,041

Internal restructuring charges and

asset write-off

24,299

5,493

Depreciation

70,508

60,905

58,610

56,593

55,490

57,864

Taxes other than income

55,987

43,395

44,742

38,776

40,418

38,551

Taxes on income

50,639

40,440

49,456

47,519

34,496

41,834

Allowance for funds used during

construction

(902)

(1,774)

(1,043)

(1,386)

(672)

(1,393)

Interest charges

45,738

34,603

36,153

38,730

38,604

39,872

Other income, net

(4,048)

(6,119)

(6,049)

(8,498)

(6,831)

(9,235)

Consolidated Income before

Extraordinary charge

94,579

92,327

82,425

80,529

61,452

66,713

Extraordinary charge, net (a)

(63,124)

.

.

.

.

.

Consolidated Net income

$ 31,455

$ 92,327

$ 82,425

$ 80,529

$ 61,452

$ 66,713

Return on average common equity (b)

14.43%

15.29%

13.62%

13.99%

11.00%

11.92%

(a) Write-off in connection with Ohio and West Virginia deregulation proceedings.

(b) Excludes a charge for a long dormant pumped-storage generation project in 1999. Includes the effect of internal restructuring in 1995 and 1996.

 

D-6

Monongahela Power Company
and Subsidiaries

CONSOLIDATED FINANCIAL AND OPERATING STATISTICS

2000

1999

1998

1997

1996

1995

PROPERTY, PLANT, AND EQUIPMENT

at Dec. 31 (Thousands):

Gross

$2,545,764

$2,173,603

$2,007,876

$1,950,478

$1,879,622

$1,821,613

Accumulated depreciation

(1,152,953)

(958,867)

(883,915)

(840,525)

(790,649)

(747,013)

Net

$1,392,811

$1,214,736

$1,123,961

$1,109,953

$1,088,973

$1,074,600

GROSS ADDITIONS TO PROPERTY

(Thousands):

$ 82,243

$ 82,483

$ 72,795

$ 78,139

$ 72,577

$ 75,458

TOTAL ASSETS at Dec. 31

(Thousands):

$2,005,668

$1,626,406

$1,519,764

$1,497,756

$1,486,742

$1,480,591

CAPITALIZATION at Dec. 31

(Thousands)

Common stock

$ 707,899

$ 578,951

$ 570,188

$ 540,930

$ 512,212

$ 505,752

Preferred stock

74,000

74,000

74,000

74,000

74,000

74,000

Long-term debt and QUIDS

606,734

503,741

453,917

455,088

474,841

489,995

$1,388,633

$1,156,692

$1,098,105

$1,070,018

$1,061,053

$1,069,747

Ratios:

Common stock

51.0%

50.0%

51.9%

50.6%

48.3%

47.3%

Preferred stock

5.3

6.4

6.8

6.9

7.0

6.9

Long-term debt

and QUIDS

43.7

43.6

41.3

42.5

44.7

45.8

100.0%

100.0%

100.0%

100.0%

100.0%

100.0%

GENERATING CAPABILITY-

kw at Dec. 31:

Company-owned

2,356,000

2,352,250

2,326,300

2,326,300

2,326,300

2,326,300

  Nonutility contracts (a)

161,000

161,000

161,000

161,000

161,000

161,000

KILOWATT-HOURS (Thousands):

Sales Volumes:

Residential

3,148,565

2,884,144

2,757,067

2,764,630

2,815,414

2,807,135

Commercial

2,439,764

2,148,361

2,102,604

1,987,147

2,007,116

1,967,473

Industrial

5,975,983

5,736,718

5,510,925

5,224,364

5,024,257

5,114,126

Wholesale and street

lighting

158,303

152,476

142,797

142,827

142,198

138,456

Sales to regular

customers

11,722,615

10,921,699

10,513,393

10,118,968

9,988,985

10,027,190

Affiliated

3,489,689

2,746,111

1,950,803

2,080,542

1,694,722

1,596,081

Bulk power

29,966

191,784

301,656

249,505

196,843

105,126

Transmission and other

energy services

2,698,380

2,138,247

1,932,160

3,007,439

4,218,150

3,497,216

Total sales volumes

17,940,650

15,997,841

14,698,012

15,456,454

16,098,700

15,225,613

Output and Delivery:

Steam generation

12,723,425

12,146,537

11,251,721

10,936,469

10,678,491

10,620,003

Pumped-storage generation

479,128

372,658

288,266

241,958

263,640

257,284

Pumped-storage input

(612,800)

(481,872)

(370,822)

(310,565)

(337,451)

(330,915)

Purchased power

3,358,567

2,562,752

2,283,055

2,294,059

2,040,136

1,903,644

Transmission and other

energy services

2,698,380

2,138,247

1,932,160

3,007,439

4,218,150

3,497,216

Losses and system uses

(706,050)

(740,481)

(686,368)

(712,906)

(764,266)

(721,619)

Total transactions as

above

17,940,650

15,997,841

14,698,012

15,456,454

16,098,700

15,225,613

D-7

Monongahela Power Company
and Subsidiaries

CONSOLIDATED FINANCIAL AND OPERATING STATISTICS (continued)

CUSTOMERS at Dec. 31:

           

Residential

546,643

312,180

309,760

307,920

305,579

303,568

Commercial

65,492

38,654

37,929

37,168

36,323

35,793

Industrial

8,067

8,014

7,992

7,996

8,019

8,085

Other

178

176

218

199

182

170

Total customers

620,380

359,024

355,899

353,283

350,103

347,616

             

RESIDENTIAL SERVICE:

           

Average use-kWh per

           

customer

9,375

9,283

8,938

9,023

9,256

9,306

Average revenue-dollars

           

per customer

687.61

678.38

651.29

652.53

677.37

693.11

Average rate-cents per

           

KWh

7.33

7.31

7.29

7.23

7.32

7.45

             

(a) Capability available through contractual arrangements with nontuility generator.

D-8

 

The Potomac Edison Company
and Subsidiaries

QUARTERLY FINANCIAL INFORMATION

(Thousands of Dollars)

Quarter Ended

 

2000

 

1999

 

Mar*

June

Sept

Dec*

 

Mar

June

Sept

Dec*

Electric operating

                 

revenues

$214,734

$188,604

$206,699

$217,782

 

$202,978

$174,691

$189,489

$186,099

Operating income

40,231

30,273

24,465

25,821

 

45,095

27,543

34,348

28,736

Income before extra-

                 

ordinary charge, net

31,111

20,047

16,014

17,213

 

36,164

18,736

26,492

19,191

Extraordinary charge,

                 

net

(12,278)

 

(1,621)

 

   

(16,949)

Consolidated net income

18,833

20,047

16,014

15,592

 

36,164

18,736

26,492

2,242

*Results for the fourth quarter of 1999 reflect charges for Maryland restructuring and a long dormant pumped-storage generation project. Results for the first and fourth quarters of 2000 reflect charges for West Virginia and Virginia restructuring.

SUMMARY OF OPERATIONS

Year ended December 31

(Thousands of Dollars)

2000

1999

1998

1997

1996

1995

Electric operating revenues

Residential

$332,065

$330,299

$309,058

$299,876

$324,120

$316,714

Commercial

163,800

168,469

156,973

148,287

146,432

145,096

Industrial

207,369

212,205

206,638

198,174

196,813

200,890

Wholesale and street lighting

28,450

5,821(a)

27,667

30,443

32,907

27,028

Revenues from regular customers

731,684

716,794

700,336

676,780

700,272

689,728

Affiliated

45,190

11,352

9,401

9,687

2,399

2,525

Other non-kWh

4,382

539

1,358

(1,273)

(405)

(961)

Bulk power

28,851

8,410

11,690

10,035

7,577

4,566

Transmission and other energy

services

17,712

16,162

14,709

13,552

16,917

14,811

Total

827,819

753,257

737,494

708,781

726,760

710,669

Operating expense

524,098

396,153

369,998

359,350

373,133

374,731

Maintenance

41,423

57,257

52,186

56,815

62,248

60,052

Internal restructuring charges and

asset write-off

26,094

6,847

Depreciation

61,394

75,917

74,344

71,763

71,254

68,826

Taxes other than income

46,892

50,924

49,567

47,585

45,809

47,629

Taxes on income

33,222

37,284

52,603

44,496

34,132

36,936

Allowance for funds used during

construction

(1,300)

(1,993)

(1,576)

(2,830)

(2,491)

(1,752)

Interest charges

43,271

44,902

48,187

49,823

50,197

51,179

Other income, net

(5,566)

(7,770)

(9,297)

(13,976)

(11,791)

(12,044)

Income before extraordinary charge

and cumulative effect of

accounting change

84,385

100,583

101,482

95,755

78,175

78,265

Extraordinary, net(b)

(13,899)

(16,949)

________

________

________

________

Consolidated net income

$ 70,486

$ 83,634

$101,482

$ 95,755

$ 78,175

$ 78,265

Return on average common equity (c)

15.28%

13.20%

13.90%

13.44%

11.42%

11.34%

(a) Includes reduction of $19,949 related to Maryland settlement.

(b) Write-off in connection with deregulation proceedings in Maryland in 1999, and deregulation proceedings in

West Virginia and Virginia in 2000.

(c) Excludes the extraordinary charge, net and a charge for a long dormant pumped-storage generation project in

1999. Includes the effect of internal restructuring in 1995 and 1996.

D-9

The Potomac Edison Company
and Subsidiaries

FINANCIAL AND OPERATING STATISTICS

 

2000

1999

1998

1997

1996

1995

PROPERTY, PLANT, AND EQUIPMENT

At Dec. 31 (Thousands):

Gross

$1,410,381

$2,322,104

$2,249,716

$2,196,262

$2,124,956

$2,050,835

Accumulated depreciation

(514,167)

(998,710)

(926,840)

(859,076)

(791,257)

(729,653)

Net

$ 896,214

$1,323,394

$1,322,876

$1,337,186

$1,333,699

$1,321,182

GROSS ADDITIONS TO PROPERTY

(Thousands):

$ 72,265

$ 91,622

$ 60,525

$ 78,298

$ 86,256

$ 92,240

TOTAL ASSETS at Dec. 31

(Thousands):

$ 1,098,963

$1,613,595

$1,728,619

$1,688,482

$1,696,904

$1,654,444

CAPITALIZATION at Dec. 31

(Thousands)

Retained Earnings

$ 412,754

$ 700,422

$ 762,912

$ 689,781

$ 678,116

$ 667,242

Preferred Stock:

Not subject to mandatory redemption

16,378

16,378

16,378

16,378

Subject to mandatory redemption

Long-term debt and QUIDS

410,010

510,344

578,817

627,012

628,431

628,854

$ 822,764

$1,210,766

$1,358,107

$1,333,171

$1,322,925

$1,312,474

Ratios:

Common stock

50.2%

57.8%

56.2%

51.8%

51.3%

50.8%

Preferred Stock

1.2

1.2

1.2

1.3

Not subject to mandatory redemption

Subject to mandatory redemption

Long-term debt and QUIDS QUIDS

49.8

42.2

42.6

47.0

47.5

47.9

100.0%

100.0%

100.0%

100.0%

100.0%

100.0%

GENERATING CAPABILITY-

kw at Dec. 31:

Company owned

3,000

2,099,120

2,073,292

2,073,292

2,072,292

2,072,292

Non utility contract (a)

180,000

KILOWATT-HOURS (Thousands):

Sales Volumes:

Residential

4,851,357

4,643,621

4,401,238

4,290,117

4,599,758

4,377,416

Commercial

2,791,704

2,667,928

2,498,546

2,331,789

2,288,229

2,213,052

Industrial

5,962,258

5,841,102

5,922,274

5,593,722

5,567,088

5,485,220

Wholesale and street lighting

699,821

683,691

657,357

666,383

724,011

603,572

Sales to regular customers

14,305,140

13,836,342

13,479,415

12,882,011

13,179,086

12,679,260

Affiliated

2,491,265

894,094

498,069

591,876

47,781

52,967

Bulk power

708,518

233,189

402,635

369,732

315,808

173,110

Transmission and other

energy services

3,475,567

2,789,957

2,470,365

4,044,837

5,617,912

4,740,010

Total sales volumes

20,980,490

17,753,582

16,850,484

17,888,456

19,160,587

17,645,347

Output and Delivery:

Steam generation

7,974,419

11,483,502

11,254,505

11,002,533

10,762,678

10,410,118

Hydro and pumped-storage generation

309,093

413,206

416,983

370,026

401,998

395,315

Pumped-storage input

(357,143)

(499,497)

(486,823)

(426,087)

(455,142)

(452,151)

Purchased power

10,309,506

4,493,128

4,190,098

3,934,815

3,639,519

3,318,302

Transmission and other

energy services

3,606,710

2,789,957

2,470,365

4,044,837

5,617,912

4,740,010

Losses and system uses

(862,095)

(926,714)

(994,644)

(1,037,668)

(806,378)

(766,247)

Total transactions as above

20,980,490

17,753,582

16,850,484

17,888,456

19,160,587

17,645,347

D-10

The Potomac Edison Company
and Subsidiaries

2000

1999

1998

1997

1996

1995

CUSTOMERS at Dec. 31:

Residential

353,721

346,821

339,584

333,224

327,344

321,813

Commercial

47,336

45,968

44,828

43,794

42,670

41,759

Industrial

5,382

5,235

5,122

5,010

4,887

4,733

Other

632

620

641

598

571

543

Total customers

407,071

398,644

390,175

382,626

375,472

368,848

RESIDENTIAL SERVICE:

Average use-kWh per customer

13,861

13,523

13,093

13,003

14,179

13,729

Average revenue-dollars per customer

948.77

961.92

919.42

908.87

999.10

993.35

Average rate-cents per kWh

6.84

7.11

7.02

6.99

7.05

7.24

(a) Capability available through contract arrangements with non-utility generators.

D-11

West Penn Power Company
and Subsidiaries

QUARTERLY FINANCIAL INFORMATION

(Thousands of Dollars)

 

Quarter Ended

 

2000

 

1999

 

Mar

June

Sept

Dec

 

Mar

June

Sept

Dec

Electric operating

                 

Revenues

$257,544

$250,563

$266,528

$270,992

 

$317,730

$327,269

$395,662

$313,542

Operating income

36,047

44,377

42,919

40,973

 

58,674

47,089

42,295

45,711

Consolidated net

                 

Income

20,053

33,589

29,972

18,789

 

45,499

33,649

31,507

16,927

 

SUMMARY OF OPERATIONS

Year ended December 31

(Thousands of Dollars)

2000

1999

1998

1997

1996

1995

Operating revenues

$1,045,627

$1,354,203

$1,078,727

$1,082,162

$1,089,124

$1,081,093

Operation expense

684,132

800,438

552,514

524,051

531,522

523,279

Maintenance

37,305

93,436

91,724

98,252

104,211

114,489

Internal restructuring charges

and asset write-offs

53,343

11,099

Depreciation and amortization

62,379

114,268

114,709

113,793

119,066

112,334

Taxes other than income

45,402

80,719

88,722

90,140

90,132

89,694

Taxes on income

52,093

71,573

64,526

73,279

47,455

61,745

Allowance for funds used

during construction

(744)

(2,933)

(2,403)

(4,085)

(2,723)

(5,041)

Interest charges

66,919

68,723

67,640

69,629

71,072

67,902

Other income, net

(4,262)

(9,621)

(11,325)

(17,562)

(13,439)

(12,287)

Consolidated income before extra-

ordinary charge

102,403

137,600

112,620

134,665

88,485

117,879

Extraordinary charge, net (a)

_

(10,018)

(275,426)

_

_

_

Consolidated net income (loss)

$ 102,403

$ 127,582

$ (162,806)

$ 134,665

$ 88,485

$ 117,879

Return on average common equity (b)

40.82%

20.97%

13.12%

13.70%

8.72%

11.46%

 

(a) Write-off in connection with Pennsylvania deregulation proceedings.

(b) Excludes the extraordinary charge, net and Pennsylvania restructuring activities in 1998, and the extraordinary charge, net and a long dormant pumped-storage generation project in 1999. Includes the effect of internal restructuring in 1995 and 1996.

 

D-12

West Penn Power Company
and Subsidiaries

FINANCIAL AND OPERATING STATISTICS

2000

1999

1998

1997

1996

1995

PROPERTY DATA

At Dec. 31 (Thousands):

Gross property

$1,654,283

$1,597,484

$3,365,784

$3,293,039

$3,182,208

$3,097,522

Accumulated depreciation

(543,000)

(506,416)

(1,362,413)

(1,254,900)

(1,152,383)

(1,063,399)

Net property

$1,111,283

$1,091,068

$2,003,371

$2,038,139

$2,029,825

$2,034,123

Gross additions during year:

Regulated operations

$ 53,097

$ 86,290

$ 95,975

$ 128,054

$ 130,606

$ 149,122

Unregulated generation

$ 27,956

TOTAL ASSETS at Dec. 31

(Thousands)

$1,792,547

$1,852,686

$2,887,706

$2,777,375

$2,724,367

$2,771,164

CAPITALIZATION at Dec 31

(Thousands):

Common stock

$ 422,121

$ 79,658

$ 732,161

$ 997,027

$ 962,752

$ 973,188

Preferred stock

79,708

79,708

79,708

79,708

Long-term debt and QUIDS

678,284

966,026

837,725

802,319

905,243

904,669

$1,100,405

$1,045,684

$1,649,594

$1,879,054

$1,947,703

$1,957,565

Ratios:

Common stock

38.4%

7.6%

44.4%

53.1%

49.4%

49.7%

Preferred stock

4.8

4.2

4.1

4.1

Long-term debt and QUIDS

61.6

92.4

50.8

42.7

46.5

46.2

100.0%

100.0%

100.0%

100.0%

100.0%

100.0%

GENERATING CAPABILITY

KW at Dec. 31:

Company-owned

3,721,408

3,671,408

3,671,408

3,671,408

Nonutility contracts (a)

138,000

138,000

138,000

138,000

138,000

138,000

REVENUES (b)

Residential

$ 404,192

$ 389,273

$ 370,636

$ 393,036

$ 402,083

$ 401,186

Commercial

221,038

201,728

217,954

223,347

224,663

224,144

Industrial

323,357

290,491

338,254

352,730

355,120

356,937

Wholesale and street lighting

28,933

27,425

33,650

27,051

26,194

25,330

Revenues from regular

utility customers

977,520

908,917

960,494

996,164

1,008,060

1,007,597

Affiliated

47,052

33,987

45,180

39,031

44,231

44,293

Other non-kWh

(3,528)

6,468

4,152

6,377

3,903

3,765

Bulk power

403

7,549

49,605

22,188

10,012

5,687

Transmission services

24,180

20,300

19,296

18,402

22,918

19,751

Total regulated operations

revenues

$1,045,627

$ 977,221

$1,078,727

$1,082,162

$1,089,124

$1,081,093

Total unregulated generation

revenues

$ 681,637

 

D-13

West Penn Power Company
and Subsidiaries

FINANCIAL AND OPERATING STATISTICS (continued)

2000

1999

1998

1997

1996

1995

KILOWATT-HOURS(Thousands):

Sales Volumes:

Residential

6,061,759

6,028,420

5,778,155

5,756,594

5,913,412

5,818,838

Commercial

4,278,514

3,903,446

4,023,523

3,833,178

3,835,831

3,782,250

Industrial

8,381,329

7,222,636

8,237,627

8,046,166

7,974,265

7,857,689

Wholesale and street lighting

673,015

641,605

617,841

611,105

591,122

561,893

Regulated operations

transactions

19,394,617

17,796,107

18,657,146

18,247,043

18,314,630

18,020,670

Affiliated

2,526,407

1,295,975

1,974,497

1,789,476

1,068,712

1,059,852

Bulk power

11,046

145,717

2,332,825

1,046,905

453,028

227,893

Transmission services

4,677,501

3,522,145

2,942,868(c)

5,392,916

7,567,153

6,348,926

Total regulated operations

transactions

26,609,571

22,759,944

25,907,336

26,476,340

27,403,523

25,657,341

Total unregulated generation

transactions

9,970,100

Output and Delivery:

Steam generation

15,231

17,593,971

20,053,422

19,523,537

18,578,677

18,143,822

Hydro and pumped-storage generation

82

774,505

620,496

559,241

682,747

581,353

Pumped-storage input

(3)

(878,237)

(640,242)

(561,135)

(612,877)

(606,953)

Purchased power

22,992,742

12,979,203

2,890,986

2,968,258

2,583,166

2,507,196

Transmission services

4,677,501

3,522,145

3,850,394

5,392,916

7,567,153

6,348,926

Losses and system uses

(1,075,982)

(1,261,543)

(867,720)

(1,406,477)

(1,395,343)

(1,317,003)

Total transactions as above

26,609,571

32,730,044

25,907,336

26,476,340

27,403,523

25,657,341

CUSTOMERS at Dec. 31(d):

Residential

594,766

591,665

587,503

583,745

580,816

578,983

Commercial

75,035

73,480

71,920

70,559

69,457

68,500

Industrial

12,826

12,615

12,389

12,142

12,051

11,801

Other

559

570

608

629

607

598

Total customers

683,186

678,330

672,420

667,075

662,931

659,882

RESIDENTIAL SERVICE(e):

Average use-

kWh per customer

10,210

10,239

9,775

9,903

10,223

10,096

Average revenue-

dollars per customer

683.90

698.73

644.98

674.73

695.08

696.06

Average rate-

cents per kWh

6.70

6.82

6.60

6.81

6.80

6.89

Capability available through contractual arrangements with nonutility generators.

Eliminations between regulated operations and unregulated generation are shown on page 6.

Excludes 907,526 kWh (in thousands) delivered to customers participating in the Pennsylvania pilot program that are included in regular customer transactions sales volumes.

Customers in the Company's service territory receiving delivery service.

Use, revenue, and rate statistics are calculated based on full service customers (customers receiving both generation and delivery from the Company).

 

D-14

Allegheny Generating Company

QUARTERLY FINANCIAL INFORMATION

(Thousands of Dollars)

Quarter Ended

2000

1999

Dec

Sept

June

March

Dec

Sept

June

March

Operating revenues

$18,256

$17,257

$17,359

$17,155

$16,853

$18,072

$17,810

$17,857

Operating income

8,535

9,032

8,939

8,583

8,220

8,821

8,586

8,455

Net income

5,095

5,914

5,593

5,278

5,344

5,516

5,302

5,053

 

D-15

Allegheny Generating Company

SUMMARY OF OPERATIONS

Year ended December 31

(Thousands of Dollars)

2000

1999

1998

1997

1996

1995

Operating revenues

$ 70,027

$ 70,592

$ 73,816

$ 76,458

$ 83,402

$ 86,970

Operation and maintenance expense

5,652

5,023

4,592

4,877

5,165

5,740

Depreciation

16,963

16,980

16,949

17,000

17,160

17,018

Taxes other than income taxes

4,963

4,510

4,662

4,835

4,801

5,091

Federal income taxes

7,360

9,997

10,959

11,213

13,297

13,552

Interest charges

13,494

13,261

13,987

15,391

16,193

18,361

Other income, net

(285)

(394)

(86)

(9,126)

(3)

(16)

Net Income

$ 21,880

$ 21,215

$ 22,753

$ 32,268

$ 26,789

$ 27,224

Return on average common equity

14.37%

13.08%

12.57%

15.98%

12.58%

12.46%

FINANCIAL AND OPERATING STATISTICS

PROPERTY, PLANT, AND EQUIPMENT

at Dec. 31 (Thousands):

Gross

$829,872

$828,894

$828,806

$828,658*

$837,050

$836,894*

Accumulated depreciation

(244,138)

(227,177)

(210,198)

(193,173)

(176,178)

(159,037)

Net

$585,734

$601,717

$618,608

$635,485

$660,872

$677,857

GROSS ADDITIONS TO PROPERTY

(Thousands)

$ 978

$ 85

$ 69

$ 444

$ 178

$ 14,165*

TOTAL ASSETS

at Dec. 31 (Thousands)

$602,045

$620,881

$639,458

$663,920

$692,408

$710,287

CAPITALIZATION AND SHORT-TERM DEBT

at Dec. 31: (Thousands):

Common stock

$144,370

$154,491

$165,276

$199,523

$202,955

$214,153

Long-term and short-term debt

202,295

201,081

215,579

208,735

239,234

256,084

$346,665

$355,572

$380,855

$408,258

$442,189

$470,237

Ratios:

Common stock

41.6%

43.4%

43.4%

48.9%

45.9%

45.5%

Long-term and short-term debt

58.4%

56.6

56.6

51.1

54.1

54.5

100.0%

100.0%

100.0%

100.0%

100.0%

100.0%

KILOWATT-HOURS (Thousands):

Pumping energy supplied by Parents

2,326,923

1,962,534

1,497,887

1,297,787

1,405,470

1,390,019

Pumped-storage generation

1,822,568

1,526,824

1,164,325

1,011,366

1,098,278

1,081,112

*Reflects a balance sheet reclassification in 1995 of $12 million from deferred charges to plant for a prior tax payment, and a related settlement of $8.8 million in 1997 that was recorded as a reduction to plant.

D-16

60

 

ITEM 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Page No.

AE

M-1

Monongahela

M-22

Potomac Edison

M-35

West Penn

M-46

AGC

M-58

The information required by this Item was furnished in the copy of the Form 10-K filed with the Securities and Exchange Commission and is also found in AE's Annual Report to Stockholders for 2000. You may obtain an Annual Report to Stockholders upon making a written or an oral request directed to: Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740, Attention: Marleen L. Brooks, Secretary (tel. 301-790-3400).

 

Allegheny Energy, Inc.

Management's Discussion and

Analysis of Financial Condition

and Results of Operations

 

Allegheny Energy, Inc.

 

FACTORS THAT MAY AFFECT FUTURE RESULTS

 

Certain statements within constitute forward-looking statements with respect to Allegheny Energy, Inc. and its subsidiaries (collectively, the Company). Such forward-looking statements include statements with respect to deregulated activities and movements towards competition in the states served by the Company, markets, products, services, prices, results of operations, capital expenditures, regulatory matters, liquidity and capital resources, resolution and impact of litigation, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

 

Factors that could cause actual results of the Company to differ materially include, among others, the following: general and economic and business conditions; industry capacity; changes in technology; changes in political, social, and economic conditions; changes in the price of power and fuel for electric generation; changes in laws and regulations applicable to the Company; litigation involving the Company; environmental regulations; the loss of any significant customers and suppliers; and changes in business strategy, operations, or development plans.

 

Overview 

 

The Company has experienced significant changes in its business as deregulation of electric generation has been approved and implemented in states where the Company operates its regulated utility businesses. As deregulation of generation has been implemented on a state-by-state basis, the Company has transferred its generating assets from its regulated utility businesses to its unregulated generation business in accordance with approved deregulation plans. It is the Company's goal that all of its generating assets will be transferred to the unregulated generation business.

 

In 1999, the Company formed Allegheny Energy Supply Company, LLC (Allegheny Energy Supply), to consolidate the Company's unregulated generating assets into a single company that is not subject to state regulation of rates. Allegheny Energy Supply is an unregulated energy company that markets competitive wholesale and retail electricity. Also, Allegheny Energy Supply operates regulated electric generation for its affiliates until deregulation is implemented in all states where the regulated utilities operate. The Company intends to make Allegheny Energy Supply a national energy merchant.

 

In November 1998, the Pennsylvania Public Utility Commission (Pennsylvania PUC) approved a settlement agreement between West Penn Power Company (West Penn) and parties to West Penn's restructuring proceedings. Under the terms of the settlement, two-thirds of West Penn's customers were permitted to choose an alternate generation supplier as of January 2, 1999. The remaining one-third of West Penn's customers were permitted to do so starting January 1, 2000. The settlement also allowed West Penn to transfer its 3,778 megawatts (MW) of generating assets at net book value to Allegheny Energy Supply, which was completed in 1999.

 

Also in 1999, Allegheny Energy Supply purchased from AYP Energy, Inc. (AYP Energy) its 276-MW share of merchant capacity at Fort Martin Unit No. 1.

 

In December 1999, the Maryland Public Service Commission (Maryland PSC) approved a settlement agreement, which allowed nearly all Maryland customers of The Potomac Edison Company (Potomac Edison) to choose their generation supplier beginning July 1, 2000. In June 2000, the Maryland PSC authorized Potomac Edison to transfer the Maryland portion of its generating assets to Allegheny Energy Supply on or after July 1, 2000. Potomac Edison also obtained the necessary approvals from the Virginia State Corporation Commission (Virginia SCC) and the Public Service Commission of West Virginia (W.Va. PSC) to transfer the Virginia and West Virginia portions of its generating assets to Allegheny Energy Supply in conjunction with the transfer of the Maryland portion of those assets. In August 2000, Potomac Edison transferred approximately 2,100 MW of generating assets to Allegheny Energy Supply.

 

In March 2000, the West Virginia Legislature passed House Resolution 27 approving an electric deregulation plan submitted by the W.Va. PSC. Under the resolution, the implementation of the West Virginia deregulation plan cannot occur until the Legislature enacts certain tax changes regarding the preservation of tax revenues for state and local government. The plan provides for customer choice of a generation supplier for all customers and allows Monongahela Power Company (Monongahela Power) to transfer the West Virginia portion (approximately 2,004 MW) of its generating assets to Allegheny Energy Supply. On August 15, 2000, and supplemented on

M-1

 

October 31, 2000, Monongahela Power filed a petition with the W.Va. PSC for approval to transfer its West Virginia portion of its generating assets to Allegheny Energy Supply on or after January 1, 2001, contemporaneously with the transfer of its Ohio jurisdictional generating assets. We now consider it highly unlikely that legislative action will occur in West Virginia in 2001. If legislative action does not occur, the Company intends to explore other ways to complete the transfer of Monongahela Power's West Virginia jurisdictional generating assets to Allegheny Energy Supply.

 

In October 2000, the Public Utilities Commission of Ohio (Ohio PUC) approved a settlement to implement a restructuring plan for Monongahela Power. This restructuring plan allowed Ohio customers of Monongahela Power to choose their generation supplier starting January 1, 2001. Also, Monongahela Power was permitted to transfer the Ohio jurisdictional portion (approximately 352 MW) of its generating assets to Allegheny Energy Supply at net book value on or after January 1, 2001.

 

In addition to the assets transferred by the Company's regulated utility subsidiaries, the Company announced that Allegheny Energy Supply plans to construct a 1,080-MW natural gas-fired merchant generating plant in La Paz County, Arizona (expected completion in 2005); a 540-MW combined-cycle facility in Springdale, Pennsylvania (expected completion in 2003); and two 44-MW simple-cycle combustion turbines in Pennsylvania. The Company completed the acquisition of a 50 percent share of the existing 48-MW coal-fired generation at Hunlock Creek with partner UGI Development in the fourth quarter of 2000. In January 2001, the Company completed the acquisition of a 4.86-percent ownership share (83 MW) of the 1,711-MW Conemaugh Generating Station from Potomac Electric Power Company (PEPCO). The Company completed construction of five 44-MW simple-cycle combustion turbines in Pennsylvania during 1999 and 2000, which are part of its unregulated generation fleet. In November 2000, the Company announced that Allegheny Energy Supply entered into an agreement to purchase from Enron Corporation three natural gas-fired merchant generating facilities located in the Midwest totaling 1,710 MW. In January 2001, the Company announced that Allegheny Energy Supply plans to construct a 630-MW natural gas-fired merchant generating facility in St. Joseph County, Indiana. Allegheny Energy Supply will have nearly 13,000 MW of generating capacity when the plants being acquired and under construction and the transfer of the Ohio and West Virginia generating assets of Monongahela Power are completed.

 

The table below summarizes the Company's electric generating capacity, excluding generating capacity purchased through contractual obligations of which the Company does not exercise 100 percent control, in operation at December 31, 2000, and announced additions:

Capacity

Cost per

(MW)

Kilowatt

In operation:

Unregulated generation

6,407

$290

Regulated generation

2,356

253

Announced additions:

Unregulated generation

4,131

619

*

Total

12,894

$388

 

* Reflects the estimated cost of facilities under construction and pending acquisitions of generating facilities.

In January 2001, the Company announced the signing of a definitive agreement to acquire Global Energy Markets (G.E.M.), Merrill Lynch's energy commodity marketing and trading unit. Under the agreement, Allegheny Energy Supply will acquire G.E.M. by paying Merrill Lynch $490 million plus a two percent ownership interest in Allegheny Energy Supply. The acquisition is intended to help transform the Company into a major national energy merchant in the energy marketplace. The combination of G.E.M.'s sophisticated structured transaction and trading skills and market presence and the Company's low-cost generating fleet will allow the Company to take advantage of the growth opportunities created by the changing energy industry. The transaction, which is being accounted for as a purchase, is expected to be closed in the first quarter of 2001. However, transfer of the two percent ownership interest (which is not required for closing) cannot occur until it is approved by the Securities and Exchange Commission (SEC).

 

The Company is considering additional ways of maximizing the value of its generating assets, including partnering with other generating companies, converting Allegheny Energy Supply into a corporation and selling a portion of its common equity through an initial public offering, or combining a partial initial public offering with a spin-off of the remaining stock to the Company's shareholders.

 

Monongahela Power expanded its service territory with the acquisition of West Virginia Power Company assets (West Virginia Power) in December 1999 for approximately $95 million. The acquisition of West Virginia Power added approximately 26,000 electric distribution customers and 24,000 natural gas customers to Monongahela Power's existing business in West Virginia. Also, Monongahela Power acquired Mountaineer Gas Company (Mountaineer Gas) in August 2000 for approximately $326 million, which included the assumption of existing long-term debt of $100 million. The acquisition of Mountaineer Gas added approximately 200,000 natural gas customers to Monongahela Power's West Virginia regulated utility operations.

M-2

 

The Company's state regulated subsidiaries, Monongahela Power, Potomac Edison, and West Penn, collectively with Mountaineer Gas, now doing business as Allegheny Power, also signed a Memorandum of Agreement with the Pennsylvania-New Jersey-Maryland Interconnection, LLC (PJM), to develop a new affiliation. Allegheny Power is leading the new initiative, known as PJM West, which will facilitate economic transmission service while simultaneously expanding the PJM market.

 

SIGNIFICANT EVENTS IN 2000, 1999, AND 1998

 

Transfer of Generating Assets 

 

In August 2000, Potomac Edison transferred approximately 2,100 MW of its Maryland, Virginia, and West Virginia jurisdictional generating assets to Allegheny Energy Supply at net book value. State utility commissions in Maryland, Virginia, and West Virginia approved the transfer of these assets as part of deregulation proceedings in those states. During the fourth quarter of 1999, West Penn transferred its deregulated generating capacity, which totaled 3,778 MW, to Allegheny Energy Supply at net book value. The Federal Energy Regulatory Commission (FERC) and the SEC also approved these transfers.

 

Under the terms of the deregulation plans approved in Pennsylvania for West Penn and in Maryland for Potomac Edison, West Penn and Potomac Edison retain the obligation to provide electricity to customers that do not choose an alternative electricity supplier during a transition period. For West Penn, the Pennsylvania transition period continues through December 31, 2008. For Potomac Edison, the Standard Offer Service (provider of last resort) will be provided to Maryland residential customers during a transition period from July 1, 2000, to December 31, 2008, and to all other Maryland customers during a transition period of July 1, 2000, to December 31, 2004. See Note B to the consolidated financial statements for details regarding the deregulation plans approved in Pennsylvania and Maryland.

 

Pursuant to contracts, Allegheny Energy Supply provides West Penn and Potomac Edison with power during the Pennsylvania and Maryland transition periods. Allegheny Energy Supply also provides power pursuant to contracts to cover the retail load of Potomac Edison in Virginia and West Virginia prior to and throughout the ensuing period of any retail choice programs that may be implemented in those states. Under these contracts, Allegheny Energy Supply provides these regulated electricity distribution affiliates with the amount of electricity, up to their retail load, that they may demand. These contracts currently represent a significant portion of the normal operating capacity of Allegheny Energy Supply's fleet of generating assets and require it to absorb changes in fuel prices and increased costs of environmental compliance.

 

On May 25, 2000, Potomac Edison filed an application with the Virginia SCC to separate its approximately 380 MW of Virginia jurisdictional generating assets, excluding the hydroelectric assets located within the state of Virginia, from its transmission and distribution (T&D) assets, effective July 1, 2000. On July 11, 2000, the Virginia SCC issued an order approving Potomac Edison's separation plan that provided for the transfer of its Virginia jurisdictional generating assets to Allegheny Energy Supply in exchange for the aforementioned contractual commitment from Allegheny Energy Supply to provide power.

 

On August 10, 2000, Potomac Edison applied to the Virginia SCC to transfer the five MW of hydroelectric assets located within the state of Virginia to Green Valley Hydro, LLC (a subsidiary of Potomac Edison). On December 14, 2000, the Virginia SCC approved the transfer. Potomac Edison anticipates the transfer to Allegheny Energy Supply will occur during the first half of 2001, after receiving final approval from the SEC.

 

On June 23, 2000, the W.Va. PSC issued an order regarding the transfer of the approximately 2,004 MW of West Virginia jurisdictional generating assets of Monongahela Power as well as the generating assets of Potomac Edison that serve West Virginia load. Potomac Edison was granted approval to transfer its assets to Allegheny Energy supply to be consolidated with other Potomac Edison generating assets so transferred. In part, Monongahela Power is required to file with the W.Va. PSC a petition seeking a Commission finding that a proposed transfer of generating assets complies with the conditions of the deregulation plan. The order also permits Monongahela Power to submit a petition to the Commission seeking approval to transfer its West Virginia jurisdictional generating assets prior to the implementation of the deregulation plan. A filing before the implementation of the deregulation plan is required to include commitments to the consumer and other protections contained in the deregulation plan. In a petition filed on August 15, 2000, and supplemented on October 31, 2000, Monongahela Power sought W.Va. PSC approval to transfer its West Virginia jurisdictional generating assets to Allegheny Energy Supply contemporaneously with the transfer of its Ohio jurisdictional generating assets. We now consider it highly unlikely that legislative action will occur in West Virginia in 2001. If legislative action does not occur, the Company intends to explore other ways to complete the transfer of Monongahela Power's West Virginia jurisdictional generating assets to Allegheny Energy Supply.

M-3

 

On October 5, 2000, the Ohio PUC approved a stipulation agreement between Monongahela Power and the major parties regarding a transition plan to bring electric choice to Monongahela Power's approximately 29,000 Ohio customers. As part of the agreement, Monongahela Power is permitted to transfer its Ohio jurisdictional generating assets (approximately 352 MW) to Allegheny Energy Supply at net book value on or after January 1, 2001. That transfer is intended to occur in the second quarter of 2001.

 

See Notes B and C to the consolidated financial statements for details of the Company's various state restructurings and other information about the electric generation deregulation process.

 

Additional Generation 

 

On January 5, 2001, the Company announced that Allegheny Energy Supply plans to construct a 630-MW natural gas-fired merchant generating facility in St. Joseph County, Indiana, approximately 10 miles west of South Bend. Construction on the facility will begin in 2002 and will be completed in two stages. Two 44-MW simple-cycle combustion turbines will be constructed first, followed by the addition of 542 MW of combined-cycle capacity in 2005. When completed, the facility will allow Allegheny Energy Supply to sell additional generation into the East Central Area Reliability Region (ECAR), as well as give Allegheny Energy Supply greater access to other markets.

 

The Company and PPL Global, Inc., a subsidiary of PPL Corporation, in January 2001 submitted a successful co-bid to purchase PEPCO's 9.72-percent share in the 1,711-MW Conemaugh Generating Station. Each company acquired 83 MW at a cost of approximately $78 million. The Company financed its share through the issuance of debt. The purchase will enhance the Company's presence in the PJM power market.

 

In November 2000, the Company announced that Allegheny Energy Supply and Enron North America (Enron), a wholly owned subsidiary of Enron Corporation, signed a definitive agreement under which Allegheny Energy Supply will purchase three natural gas-fired merchant generating facilities. The purchase includes the following generating assets, all of which have been in service since June 2000: the Gleason plant (546 MW) in Gleason, Tennessee; the Wheatland plant (508 MW) in Wheatland, Indiana; and the Lincoln Energy Center plant (656 MW) in Manhattan, Illinois. These assets will provide Allegheny Energy Supply with additional natural gas-fired generating capacity within ECAR, the Mid-America Interconnected Network, and the Southeastern Electric Reliability Council. The purchase is anticipated to close in the second quarter of 2001.

 

In October 2000, the Company announced that Allegheny Energy Supply plans to construct a 1,080-MW natural gas-fired merchant generating facility in La Paz County, Arizona, approximately 75 miles west of Phoenix. Construction is expected to begin on the $540-million combined-cycle facility in 2002. When completed in 2005, the facility will allow Allegheny Energy Supply to sell generation into Arizona and other states served by the Western System Power Pool, including all or parts of California, western Canada, Colorado, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming.

 

In September 2000, Allegheny Energy Supply announced that Allegheny Energy Supply Hunlock Creek, LLC, a wholly owned subsidiary of the Company, along with partner UGI Development, a subsidiary of UGI Corporation (UGI), will market generating output from facilities at UGI's Hunlock Creek generating station near Wilkes-Barre, Pennsylvania.

 

In addition to sharing 48 MW of existing coal-fired generation at Hunlock Creek, Allegheny Energy Supply Hunlock Creek, LLC, installed a 44-MW natural gas-fired combustion turbine on property owned by UGI in the fourth quarter of 2000. UGI Development and Allegheny Energy Supply Hunlock Creek, LLC will jointly share in the combined output of the coal-fired and combustion turbine generating units. Allegheny Energy Supply Hunlock Creek, LLC, was responsible for construction of the Hunlock Creek combustion turbine, while UGI operates the facilities. These additions will give Allegheny Energy Supply access to 46 MW of generating capacity to sell into the PJM market.

 

In February 2000, the Company announced that it would install five simple-cycle gas combustion turbines, including the turbine installed by Allegheny Energy Supply Hunlock Creek, LLC, with a combined capacity of 198 MW (adjusted for UGI's share of one 44-MW unit) at various sites within Pennsylvania. The construction of two units (88 MW) was completed in the fourth quarter of 2000. The construction of the other two units will be completed in 2001. The generation output from the five units will be sold into competitive wholesale and retail power markets in the eastern United States. The units, which will be capable of running on either natural gas or No. 2 diesel oil, represent an investment of approximately $120 million for Allegheny Energy Supply.

 

In January 2000, the Company also announced the construction of a 540-MW combined-cycle generating plant at Springdale, Pennsylvania, at a cost of $318 million. The new facility will include two gas-fired combustion turbines and a steam turbine. The combined-cycle facility is expected to be operational and providing power for sale into competitive markets in 2003.

M-4

 

In 1999, the Company completed construction of and placed into operation two new 44-MW, simple-cycle gas combustion turbines at Springdale, Pennsylvania.

G.E.M. Acquisition

 

On January 8, 2001, the Company announced that it had signed a definitive agreement to acquire G.E.M., Merrill Lynch's energy commodity marketing and trading unit. Under the agreement, Allegheny Energy Supply will acquire G.E.M. by paying Merrill Lynch $490 million, plus a two percent equity interest in Allegheny Energy Supply. Merrill Lynch has also agreed, in connection with the G.E.M. transaction, to refrain from competition with the Company for a period of 30 months. The transaction will be accounted for under the purchase method of accounting.

 

The acquisition is intended to help transform the Company into a major participant in the national energy marketplace and allow the Company to take advantage of growth opportunities created by changes in the energy industry. The addition of G.E.M.'s sophisticated structured transaction and trading skills and market presence to the Company's existing marketing and operating skills will assist in extracting the maximum value from the Company's low-cost generating fleet.

 

With G.E.M., Allegheny Energy Supply will have a significant trading and marketing operation and a national platform from which to sell its wholesale generation. G.E.M. was ranked in the top 20 in the nation in terms of electric volumes traded as of the third quarter of 2000. It is expected that Allegheny Energy Supply and G.E.M.'s combined volumes traded will be in the top 10 of all power marketers in the nation.

 

The acquisition of G.E.M. includes the support infrastructure necessary to conduct business immediately upon completion of the transaction. Additionally, under the agreement, for 30 months Merrill Lynch will refer its clients with energy trading needs to Allegheny Energy Supply.

 

The acquisition is contingent upon regulatory approvals, including approval of the FERC. The transfer of the two percent equity interest also requires approval of the SEC. This transfer is not required to be completed for closing. The Company expects the transaction to be closed in the first quarter of 2001.

 

Mountaineer Gas and West Virginia Power Acquisitions 

 

On August 18, 2000, Monongahela Power completed the purchase of Mountaineer Gas, a regulated natural gas sales, transportation, and distribution company serving a large portion of West Virginia, from Energy Corporation of America (ECA) for approximately $326 million, which included the assumption of $100 million of existing long-term debt. The acquisition included the assets of Mountaineer Gas Services, which operates natural gas-producing properties, natural gas-gathering facilities, and intrastate transmission pipelines. The acquisition increased Monongahela Power's number of gas customers in West Virginia by approximately 200,000. (See Note E to the consolidated financial statements for additional information.)

 

In December 1999, Monongahela Power purchased from UtiliCorp United Inc. the assets of West Virginia Power, an electric and natural gas distribution company located in southern West Virginia, for approximately $95 million.

 

Leasing Technologies International, Inc. Acquisition

 

On December 29, 2000, Allegheny Ventures, Inc. (Allegheny Ventures), an unregulated subsidiary of the Company, signed an agreement to acquire Leasing Technologies International, Inc. (LTI), a financial services firm that specializes in equipment financing solutions for emerging growth companies. Allegheny Ventures will acquire LTI for $26 million. In addition, LTI's leadership and employee shareholders could receive additional shares of the Company's common stock over the next three years if LTI reaches or exceeds earnings targets. The stock-for-stock transaction will be accounted for under the purchase method of accounting. The Company expects the transaction will be closed in the second quarter of 2001, subject to SEC approval.

 

Rate Matters 

 

The Company's regulated subsidiaries, doing business as Allegheny Power, operate electric transmission and electric and natural gas distribution systems. Allegheny Power also generates electric energy in jurisdictions which have not yet deregulated electric generation. These subsidiaries are subject to federal and state regulation, including the Public Utility Holding Company Act of 1935 (PUHCA). Allegheny Power's markets for regulated electric and gas retail sales are in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia.

 

Potomac Edison decreased the fuel portion of Maryland customers' bills by approximately $6.4 million annually, effective with bills rendered on or after December 7, 1999, based on the outcome of proceedings before the Maryland PSC. A proposed order was issued on February 18, 2000, granting the requested decrease in Potomac

M-5

Edison's fuel rate, and, on March 21, 2000, the proposed order became final. Effective July 1, 2000, coincident with customer choice in Maryland, the fuel rates were rolled into base rates.

 

On March 24, 2000, the Maryland PSC issued an order requiring Potomac Edison to refund the 1999 deferred fuel balance overrecovery of approximately $9.9 million to customers over a period of 12 months that began April 30, 2000. The refund of the overrecovered balance does not affect Potomac Edison's earnings since the overrecovered amounts had been deferred.

 

On October 4, 2000, the Maryland PSC approved Potomac Edison's filing, which represents the final reconciliation of its deferred fuel balance. Potomac Edison is refunding to customers a $3.2 million overrecovery balance existing in the Maryland deferred fuel account as of September 30, 2000. The deferred fuel credit to customers began in October 2000 and will be effective until the balance falls to zero, which is projected to take 12 months. The refund of the overrecovered balance does not affect Potomac Edison's earnings, since the overrecovered amounts had been deferred.

 

On June 23, 2000, the W.Va. PSC approved a Joint Stipulation and Agreement for Settlement, stating agreed-upon rates designed to make the rates of Potomac Edison and Monongahela Power consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require several incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue reduction of approximately $0.3 million for 2000, increasing over eight years to an annual reduction of approximately $1.7 million. Offsetting the decrease in rates, the settlement approved by the W.Va. PSC directs Monongahela Power and Potomac Edison to amortize the existing overcollected deferred fuel balance as of June 30, 2000 (approximately $16 million), as a reduction of expenses over a four-and-one-half year period beginning July 1, 2000. Also, effective July 1, 2000, Potomac Edison and Monongahela Power ceased their expanded net energy cost (fuel clause) as part of the settlement.

 

On November 29, 2000, the Maryland PSC approved the Power Sales Agreement between Potomac Edison and the winning bidder covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2001, through December 31, 2001. The AES Warrior Run cogeneration project was developed under the Public Utility Regulatory Policies Act of 1978 (PURPA) and achieved commercial operation on February 10, 2000. Under the terms of the Maryland deregulation plan approved in 1999, the revenues from the sale of the AES Warrior Run output are used to offset the capacity and energy costs Potomac Edison pays to the AES Warrior Run cogeneration project before determining amounts to be recovered from Maryland customers.

 

Effective with bills rendered on or after January 8, 2001, there was an increase in Maryland base rates as a result of the phase-in of the rate increase approved by the Maryland PSC on October 27, 1998. A settlement agreement, which includes recognition and dollar-for-dollar recovery of costs to be incurred from the AES Warrior Run project, was filed with the Maryland PSC on July 30, 1998, and approved by that Commission on October 27, 1998. The Maryland PSC approved rates for each customer class on December 22, 1998. Under the terms of the agreement, Potomac Edison increased its rates about four percent in each of the years 1999 and 2000 and will increase rates by about four percent in 2001 (a $79 million total revenue increase during 1999 through 2001). The increases are designed to recover additional costs of about $131 million over the period 1999-2001 for capacity purchases from the AES Warrior Run project net of alleged overearnings of $52 million for the same period. The agreement also requires that Potomac Edison share 50 percent of earnings above an 11.4 percent return on equity with customers for 1999 and 2000. As a result, 50 percent of the amount above the threshold earnings amount, or $9.7 million applicable to 1999, is being distributed to customers in the form of an Earnings Sharing Credit, effective June 7, 2000, through April 30, 2001. Any sharing of earnings required for 2000 will be reflected as a credit on customers' bills starting in May 2001.

 

On October 11, 2000, the W.Va. PSC approved an interim increase on the commodity rate for gas customers of Monongahela Power (formerly West Virginia Power customers) for gas service bills rendered on and after December 1, 2000. On December 11, 2000, the W.Va. PSC approved additional increases for gas service bills rendered on and after January 1, 2001, through November 30, 2001 (total revenue increase for the 12-month period of $5.1 million or 22.6 percent). The commodity rate is the portion of the gas service bill that reflects the cost of natural gas, which has increased significantly during 2000. The W.Va. PSC has approved a tiered rate structure with rates established for the winter heating season, effective January 1, 2001, through April 30, 2001, and further increased rates effective May 1, 2001, through November 30, 2001, dependent upon the level of cost recovery after the winter heating season. This approach allows Monongahela Power full recovery, but eases the increase on the average customer. These increases have no effect on earnings because they were implemented via the Purchased Gas Adjustment mechanism. Under the Purchased Gas Adjustment mechanism, differences between revenues received for energy costs and actual energy costs are deferred until the next proceeding, when energy rates are adjusted to return or recover previous overrecoveries or underrecoveries, respectively.

 

Mountaineer Gas, in response to significant increases in the market price for natural gas, filed for a rate increase with the W.Va. PSC on January 4, 2001. If natural gas prices remain at current levels, the proposed overall rates will increase by approximately 39 percent ($67 million) over present rates. Mountaineer Gas anticipates that the W.Va. PSC will postpone the effective date until November 1, 2001, when the current rate moratorium ends. The conclusion of the current rate moratorium coincides with the expiration of the primary Mountaineer Gas fixed-price fuel supply contract.

M-6

 

Regional Transmission Organization

 

In adopting its Rule 2000, the FERC defined requirements for transmission facility owners, such as Monongahela Power, Potomac Edison, and West Penn, to participate in some form of a regional transmission organization (RTO). Additionally, the state jurisdictions within which the Company operates have, to different degrees, started to define their transition to a competitive generation marketplace. As part of this, they have identified transmission as a key link to making the electricity market efficient.

 

Allegheny Power announced on October 5, 2000, that it had signed a Memorandum of Agreement with PJM to develop a new transmission affiliation with PJM, referred to as PJM West. The Memorandum of Agreement was outlined in a filing submitted to the FERC on October 16, 2000, in order to meet the requirements of FERC's Order 2000.

 

FERC's Order 2000 required all electric utilities, not currently in an independent system operator (ISO), to file a plan on how they would participate in an RTO, those entities that oversee and control the power grid. Although PJM is an ISO, Allegheny Power will not join PJM, but will pursue the development of an affiliation with PJM, working within the PJM framework, which would also be available to other utilities.

 

Allegheny Power is leading the new initiative, known as PJM West, which will facilitate economic transmission service, while simultaneously expanding the PJM market. Allegheny Energy Supply will benefit from the PJM West initiative by having its generation within PJM and open to markets in the current PJM region.

 

In December 2000, Allegheny Power and PJM announced the execution of an agreement in principle to broaden PJM West that will further expand the PJM market into the Pittsburgh area. This agreement provides for Duquesne Light Company to join Allegheny Power in the development of PJM West by executing a similar joint agreement with PJM as did Allegheny Power.

 

AFN Communications, LLC

 

Allegheny Communications Connect, Inc. (ACC) announced in March 2000 that it, along with five other energy and telecommunications companies and a consulting partner, were creating AFN Communications, LLC (AFN), a super-regional high-speed telecommunications company. The network initially offered more than 7,700 route miles, or 140,000 fiber miles, connecting major markets in the eastern United States to secondary markets with a growing need for broadband access. The initial footprint of fiber in AFN positions it to reach areas responsible for roughly 35 percent of the national wholesale communications capacity market.

 

AFN expects to expand its network from the current 7,700 route miles to 10,000 route miles or 200,000 fiber miles by the end of 2002. AFN will reach this capacity by adding partners with existing fiber, installing fiber in areas of opportunity, and acquiring existing fiber from others or contracting long-term lease agreements for existing fiber.

 

ACC received a 17 percent interest in AFN by contributing 339 miles of lit fiber, including revenue from capacity contracts related to these routes, and 761 miles of committed dark fiber. Other members include AEP Fiber Venture, LLC, a subsidiary of American Electric Power; GPU Telcom Services, Inc., a subsidiary of GPU, Inc.; Fiber Venture Equity, Inc., a subsidiary of FirstEnergy Corporation; CFW Network, Inc.; R&B Network, Inc.; and A.T. Kearney, Inc.

 

Allegheny Energy Solutions, Inc.

 

On May 15, 2000, one of the Company's unregulated subsidiaries, Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions) announced the formation of a strategic alliance with Capstone Turbine Corporation (Capstone). Capstone manufactures commercial, ultra-low emission microturbine power systems. The alliance will help position Allegheny Energy Solutions as a local and national solutions provider for distributed generation services.

 

On December 7, 2000, Allegheny Energy Solutions added Siemens Solar Industries, L.P., to its portfolio of suppliers for distributed generation products. Through its agreement with Siemens Solar Industries, Allegheny Energy Solutions will provide its customers with a comprehensive offering of solar electric solutions called earthsafe.™

 

Stockholder Protection Rights Agreement

 

The Company has adopted a Stockholder Protection Rights Agreement (Rights Agreement). Under the Rights Agreement, rights were distributed as a dividend at the rate of one right per each share of the Company's common stock. The dividend was paid to shareholders of record as of March 16, 2000. Under its principal provision, if any person or group acquires 15 percent or more of the Company's outstanding common stock, all other

M-7

shareholders of the Company would be entitled to buy, for the exercise price of $100 per right, common stock of the Company having a market value equal to twice the exercise price, thereby substantially diluting the acquiring person's or group's investment.

 

The rights may cause substantial dilution to a person or group that acquires 15 percent or more of the Company's common stock. The rights should not interfere with a transaction that is in the best interests of the Company and its shareholders, because the rights can be redeemed or terminated prior to a triggering event.

 

The SEC previously issued an order pursuant to the PUHCA, granting the Company authority to adopt and implement the Rights Agreement.

Review of Operations

Earnings Summary

Earnings

Basic and Diluted Earnings

Per Average Share

(Millions of dollars except per share data)

2000

1999

1998

2000

1999

1998

Operations:

Regulated operations

$227.7

$236.5

$283.3

$2.06

$2.03

$2.32

Unregulated generation

83.7

49.1

(19.6)

.76

0.42

(0.16)

Other

2.2

(0.2)

(0.7)

.02

(0.01)

Consolidated income before extraordinary charges

313.7

285.4

263.0

2.84

2.45

2.15

Extraordinary charges, net (Notes B, C, and F to

consolidated financial statements)

(77.0)

(27.0)

(275.4)

(0.70)

(0.23)

(2.25)

Consolidated net income (loss)

$236.6

$258.4

($12.4)

$2.14

$2.22

($0.10)

The increase in earnings for 2000, before extraordinary charges, resulted from the Company's unregulated generation segment due to the transfer of Potomac Edison's Maryland, Virginia, and West Virginia jurisdictional generating assets from regulated operations to unregulated generation in August 2000. In addition, the earnings for unregulated generation increased due to colder than normal weather in November and December of 2000. This increase was partially offset by the milder summer weather for 2000.

 

Earnings for the Company's regulated operations decreased in 2000 due to the transfer of Potomac Edison's generating assets in August 2000. This decrease was partially offset by the acquisition of two energy distribution companies, West Virginia Power in 1999 and Mountaineer Gas in 2000.

 

The increase in earnings per share for 2000, before the extraordinary charge, reflects higher net revenue in the unregulated generation segment and a lower number of average shares of common stock outstanding as a result of the Company's 1999 stock repurchase program.

 

The extraordinary charge of $77 million, net of taxes, reflects write-offs by the Company's regulated subsidiaries, Monongahela Power and Potomac Edison, as a result of West Virginia, Ohio, and Virginia legislation requiring deregulation of electric generation.

 

The decrease in 1999 earnings from regulated operations, before extraordinary charges, reflects the deregulation of two-thirds of West Penn's electric generation, effective January 1, 1999, as approved by the Pennsylvania PUC's restructuring order for West Penn. Accordingly, the operating results for these assets are classified as unregulated generation in 1999.

 

In 1999, earnings from unregulated generation, before extraordinary charges, increased consolidated net income by $49.1 million, an increase of $68.7 million over 1998's loss. This increase in unregulated earnings reflects the sale of generation from two-thirds of West Penn's generating assets into deregulated markets as discussed under Sales and Revenues and improved results over 1998 performance in such markets.

 

Extraordinary charges in 2000, 1999, and 1998 resulted from the Maryland, Ohio, Pennsylvania, Virginia, and West Virginia electric utility restructuring orders as discussed in Notes B and C to the consolidated financial statements and the redemption of debt by West Penn in 1999 related to the securitization of stranded costs as discussed in Note F to the consolidated financial statements.

M-8

 

Sales and Revenues Total operating revenues for 2000, 1999, and 1998 were as follows:

(Millions of dollars)

2000

1999

1998

Operating revenues:

Regulated operations:

Electric

$2,315.8

2,169.0

2,201.2

Gas

81.8

Choice

28.4

34.3

14.0

Bulk power

135.8

45.7

69.8

Transmission and other energy services

73.2

61.0

45.2

Total regulated revenues

2,635.0

2,310.0

2,330.2

Unregulated generation revenues:

Retail and other

232.8

155.5

25.0

Bulk power

2,048.8

723.9

215.3

Total unregulated generation revenues

2,281.6

879.4

240.3

Other

22.6

8.9

6.7

Eliminations

(927.3)

(389.9)

(0.8)

Total operating revenues

$4,011.9

$2,808.4

$2,576.4

The increase in regulated electric and gas revenues for 2000 was primarily due to an increase in the number of customers and the acquisition of the assets of West Virginia Power purchased by Monongahela Power in December 1999, and by Monongahela Power's acquisition of Mountaineer Gas in August 2000. The decrease in regulated revenues in 1999 was due primarily to Pennsylvania deregulation, which gave two-thirds of West Penn's regulated customers the ability to choose another energy supplier. This decrease was also due to a reduction in Potomac Edison's Maryland rates as part of a settlement agreement. Electric energy supplied to West Penn customers by alternative energy suppliers was seven percent and 11 percent of West Penn's total megawatt sales for 2000 and 1999. The decrease to regulated revenues was offset in part by colder winter weather in 1999, which led to increased residential kilowatt-hour (kWh) sales and revenues.

 

Choice revenues represent T&D revenues from franchised customers in West Penn's Pennsylvania and Potomac Edison's Maryland distribution territories who chose other suppliers to provide their energy needs. Pennsylvania and Maryland deregulation gave West Penn and Potomac Edison's regulated customers the ability to choose another energy supplier. For 2000, all of West Penn's regulated customers had the ability to choose, and, for 1999, two-thirds of West Penn's customers had the ability to choose. As of July 1, 2000, all of Potomac Edison's Maryland customers had the right to choose. At December 31, 2000, less than one percent of West Penn's customers and Potomac Edison's Maryland customers chose alternate energy suppliers. The decrease in choice revenues for 2000 was due to the decline in the number of West Penn customers choosing alternate energy suppliers.

 

In 1998, the choice revenues represent five percent of previously fully bundled customers (full service customers) who participated in the Pennsylvania pilot program that began November 1, 1997, and continued through December 31, 1998, and were required to buy energy from an alternate supplier. To assure participation in the program, pilot participants received an energy credit from their local utility and a price for energy pursuant to an agreement with an alternate supplier.

 

The increases in regulated operations bulk power for 2000 was primarily due to increased sales by Monongahela Power and Potomac Edison to Allegheny Energy Supply. In early 2000, a dispatch agreement was implemented between regulated operations and unregulated generation. With this agreement, regulated operations sells the amount of its bulk power that exceeds its regulated load to Allegheny Energy Supply and conversely buys generation from unregulated operations when regulated load at times exceeds regulated generation. Such a relationship allows all of the Company's generation to be dispatched in a more efficient manner. In addition, $28.1 million for 2000 was the result of the sale of the output of the AES Warrior Run cogeneration facility into the open wholesale market. This output was part of a Maryland PSC settlement agreement with Potomac Edison. The 1999 decrease in regulated operations bulk power was due to the movement of generation available for sale from regulated operations to unregulated generation.

M-9

 

In October 1998, the Maryland PSC approved a settlement agreement for Potomac Edison. Under the terms of that agreement, Potomac Edison increased its rates about four percent in 1999 and 2000, and will increase rates about four percent in 2001 (a $79 million total revenue increase during 1999 through 2001). (See Rate Matters beginning on page 28 for additional information).

 

Total regulated operations revenues reflect not only changes in kilowatt-hour sales and base rate changes, but also changes in revenues from fuel and energy cost adjustment clauses (fuel clauses), which were applicable in all Company jurisdictions, except for Pennsylvania, through various dates in 2000. Effective July 1, 2000, Potomac Edison's Maryland jurisdiction and the West Virginia jurisdiction for Monongahela Power and Potomac Edison ceased to have a fuel clause. Effective August 7, 2000, a fuel clause ceased to exist for Potomac Edison's Virginia jurisdiction. Effective January 1, 2001, a fuel clause ceased to exist for Monongahela Power's Ohio jurisdiction.

 

Where a fuel clause is in effect, changes in fuel revenues have no effect on consolidated net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power are passed on to customers through fuel clauses. Once the fuel clause is eliminated, the Company assumes the risks and benefits of changes in fuel and purchased power costs and sales of transmission services and bulk power.

 

Gas sales and services and electric revenues from the assets of West Virginia Power purchased by Monongahela Power in December 1999 and Mountaineer Gas purchased by Monongahela Power in August 2000 are included in regulated revenues in 2000. Because a significant portion of the gas sold by Monongahela Power's gas distribution operations is ultimately used for space heating, both revenues and earnings are subject to seasonal fluctuations. The Purchased Gas Adjustment mechanism (fuel clause) continues to exist for West Virginia Power and may come into effect for Mountaineer Gas following its current three-year moratorium, which ends on October 31, 2001.

 

There may be significant volatility in the spot prices for electricity at the wholesale level, which may significantly affect the Company's operating results. The effect may be either positive or negative, depending on whether the Company's subsidiaries are net buyers or sellers of electricity and their open commitments or previously concluded market positions that exist at such times.

 

The increase in unregulated generation revenues reflects increased transactions by Allegheny Energy Supply in the unregulated marketplace to sell electricity to both wholesale and retail customers and is also due to having increased generation available for sale. As a result of the Electricity Generation Customer Choice and Competition Act (Customer Choice Act) in Pennsylvania, two-thirds of West Penn's generation was released in the first quarter of 1999 and was available for sale into the unregulated marketplace by Allegheny Energy Supply, subject to its obligations under the full requirements contracts it entered into with West Penn. In the first quarter of 2000, the final one-third of West Penn's generation was similarly released and became available for sale into the deregulated marketplace. In addition, the Company transferred approximately 2,100 MW of Potomac Edison's Maryland, Virginia, and West Virginia jurisdictional generating assets to Allegheny Energy Supply in August 2000. As a result, the unregulated generation segment had more generation available for sale into the deregulated marketplace in 2000, and had concluded more commitments to sell generation in that marketplace, including sales to West Penn and Potomac Edison to meet their provider of last resort obligations.

 

In addition, the unregulated generation segment had a net gain of $8.4 million, before tax, as a result of recording its energy trading contracts at fair value on the balance sheet at December 31, 2000, in accordance with Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." See Note J to the consolidated financial statements for additional details.

 

Other revenues increased by $13.7 million for 2000 primarily due to increased sales of dark fiber by ACC.

 

The elimination between regulated operations, unregulated generation, and other revenues is necessary to remove the effect of affiliated revenues, primarily sales of power. See Note B to the consolidated financial statements for information regarding the Competitive Transition Charge (CTC).

 

OPERATING EXPENSES

Fuel expenses for 2000, 1999, and 1998 were as follows:

Fuel expenses

(Millions of dollars)

2000

1999

1998

Regulated operations

$232.7

$355.5

$545.4

Unregulated generation

319.5

180.2

21.1

Total fuel expenses

$552.2

$535.7

$566.5

Total fuel expenses for 2000 increased due to increased kilowatt-hours generated, offset in part by decreased average fuel prices. Total fuel expenses decreased in 1999 due primarily to a decrease in average fuel prices. The decreases in fuel expenses for regulated operations and the increases in fuel expenses for unregulated generation in 2000 and 1999 were due to the fuel expenses associated with the transfer of West Penn's and Potomac Edison's generating assets from regulated operations to unregulated generation as a result of deregulation activities in Maryland, Pennsylvania, Virginia, and West Virginia.

M-10

Purchased power and exchanges, net, represents power purchases from and exchanges with other companies and purchases from qualified facilities under PURPA and consists of the following items:

 

Purchased Power and Exchanges, Net

(Millions of dollars)

2000

1999

1998

Regulated operations:

Purchased power:

From PURPA generation*

$191.1

$104.1

$129.0

Other

775.1

395.8

50.0

Total purchased power for regulated operations

966.2

499.9

179.0

Power exchanges, net

6.9

(2.6)

(0.7)

Unregulated generation purchased power

1,472.5

390.1

210.5

Elimination

(852.9)

(356.0)

Purchased power and exchanges, net

$1,592.7

$531.4

$388.8

*PURPA cost (cents per kWh)

5.5cents

4.8cents

5.4cents

The increase of $87.0 million in regulated operations from PURPA generation for 2000 was due to the start of commercial operations of the AES Warrior Run cogeneration project. The Maryland PSC has approved Potomac Edison's full recovery of the AES Warrior Run purchased power costs as part of the September 23, 1999, settlement agreement to implement deregulation for Potomac Edison. Accordingly, the Company defers, as a component of other operation expenses, the difference between revenues collected related to AES Warrior Run and the cost of the AES Warrior Run purchased power.

 

Regulated operations purchased power costs from PURPA generation decreased $24.9 million in 1999. This decrease reflects an $11.1 million reduction related to West Penn's purchase commitment at costs in excess of the market value of the AES Beaver Valley PURPA contract previously accrued as a loss contingency in accordance with Statement of Financial Accounting Standards (SFAS) No. 5, "Accounting for Contingencies." The decrease in purchased power also includes a $12.5 million reduction in the purchase price for that contract due to a scheduled capacity rate decrease defined annually in the contract.

 

The increase in other regulated operations purchased power in 2000 was due primarily to West Penn's and Potomac Edison's purchase of power from their unregulated generation affiliate, Allegheny Energy Supply, in order to provide energy to customers eligible to choose an alternate supplier, but electing not to do so. The generation previously available to serve those customers has been transferred to Allegheny Energy Supply. Also, unplanned generating plant outages in the first quarter of 2000 caused the regulated utility operations of Potomac Edison and Monongahela Power to make purchases of higher-priced power on the open energy market. The 1999 increase was due to West Penn's purchase of power from Allegheny Energy Supply.

 

The increase in unregulated generation purchased power in 2000 was for power to serve the provider of last resort load of West Penn and Potomac Edison, unplanned first quarter generating plant outages that caused the Company to make purchases of higher-priced power on the open market, and increased buy-sell transactions to optimize the value of unregulated generating assets in the fourth quarter. The increase in unregulated generation purchases in 1999 was due to increased purchases for sale to regulated affiliates and to take advantage of transaction opportunities in the wholesale market.

 

The elimination, between regulated and unregulated purchased power, is necessary to remove the effect of affiliated purchased power expenses.

 

Gas purchases and production expenses for 2000, 1999, and 1998 were as follows:

Gas Purchases and Production

(Millions of dollars)

2000

1999

1998

Regulated operations

$57.0

Total gas and production expenses

$57.0

   

Gas purchases and gas production reflects the acquisition of West Virginia Power in December 1999 and Mountaineer Gas in August 2000.

M-11

 

Other operation expenses for 2000, 1999, and 1998 were as follows:

Other Operation Expenses

(Millions of dollars)

2000

1999

1998

Regulated operations

$345.7

$340.8

$319.3

Unregulated generation

127.7

66.6

10.5

Other

18.2

5.8

7.6

Elimination

(74.5)

(23.8)

Total other operation expenses

$417.1

$389.4

$337.4

The increase in regulated operations expense of $4.9 million for 2000 reflects additional expenses related to the acquisition of West Virginia Power and Montaineer Gas. These additional expenses were offset in part by reduced expenses related to the transfer of generating assets from regulated operations to unregulated generation during the year.

 

The increase in unregulated generation other operation expenses of $61.1 million for 2000 was primarily due to increased purchases of transmission capacity for electricity for delivery of energy to customers and expenses related to the transfer of generating assets during the current year.

 

The increase in other of $12.4 million for 2000 was due primarily to increased expenses related to the expanding telecommunications business of ACC and distributed generation sales business of Allegheny Energy Solutions. Allegheny Energy Solutions and ACC are subsidiaries of Allegheny Ventures.

 

The increase in total other operation expenses in 1999 of $52.0 million was due primarily to recording $19.7 million in merger-related costs previously deferred and $16.2 million related to a pumped-storage generation project no longer considered useful, increases in salaries and wages of $8.0 million, $5.0 million for costs associated with settling litigation concerning a PURPA project, and increased allowances for uncollectible accounts of $2.1 million.

 

The elimination between regulated and unregulated operation expenses is primarily to remove the effect of affiliated transmission purchases.

 

Maintenance expenses for 2000, 1999, and 1998 were as follows:

Maintenance Expenses

(Millions of dollars)

2000

1999

1998

Regulated operations

$149.0

$182.6

$212.3

Unregulated generation

81.3

40.8

5.3

Other

0.1

Total maintenance expenses

$230.3

$223.5

$217.6

Maintenance expenses represent costs incurred to maintain the power stations, T&D system, and general plant, and reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. Variations in maintenance expense result primarily from unplanned events and planned projects, which vary in timing and magnitude depending upon the length of time equipment has been in service and the amount of work found necessary when the equipment is inspected.

 

The decreases in regulated operations maintenance and the increases in unregulated generation maintenance in 2000 and 1999 were due mainly to the transfer of generating assets from regulated operations to unregulated generation.

 

Unregulated generation maintenance in 2000 reflects the capitalization policy for Allegheny Energy Supply, which was formed in November 1999. The capitalization policy of Allegheny Energy Supply is based on operating generating assets in an unregulated environment in which less costs are capitalized and more costs expensed as maintenance. See Note L to the consolidated financial statements for additional details.

 

Total maintenance expenses increased $5.9 million in 1999 due primarily to increased maintenance and renovations of general plant structures of $5.1 million.

M-12

 

Depreciation and amortization expenses for 2000, 1999, and 1998 were as follows:

Depreciation and Amortization Expenses

(Millions of dollars)

2000

1999

1998

Regulated operations

$194.5

$198.0

$264.6

Unregulated generation

52.4

58.9

5.7

Other

1.0

0.6

0.1

Total depreciation and amortization expenses

$247.9

$257.5

$270.4

Total depreciation and amortization expenses for 2000 decreased $9.6 million, reflecting the changes related to the establishment of capital recovery policies of Allegheny Energy Supply. See Note L to the consolidated financial statements for additional details. The decreases in regulated operations depreciation and amortization expenses reflects the transfer of generating assets from regulated operations to unregulated generation during the year offset by depreciation of new capital additions, including the acquisitions of West Virginia Power and Mountaineer Gas.

 

Total depreciation and amortization expenses in 1999 decreased $12.9 million due primarily to a $24.6 million reduction related to a 1998 write-down of West Penn's share of costs in excess of the fair value of the Allegheny Generating Company (AGC) pumped-storage project.

 

Depreciation expense will be reduced $234 million during the period 1999 through 2025 from the historical depreciation amounts as a result of the AGC plant impairment charge recorded as an extraordinary charge in 1998 by West Penn.

 

Taxes other than income taxes for 2000, 1999, and 1998 were as follows:

 

Taxes Other Than Income Taxes

(Millions of dollars)

2000

1999

1998

Regulated operations

$148.4

$157.9

$187.7

Unregulated generation

61.3

32.2

6.6

Other

0.5

0.2

0.3

Total taxes other than income taxes

$210.2

$190.3

$194.6

Total taxes other than income taxes increased $19.9 million for 2000 due primarily to increased gross receipts taxes resulting from higher revenues from retail customers, increased property taxes, and increased West Virginia Business and Occupation Taxes. The increases for 2000 were offset in part by reduced franchise and capital stock taxes due to reduced tax rates and Pennsylvania Capital Stock tax adjustments related to prior years.

 

Total taxes other than income taxes decreased $4.3 million in 1999 primarily due to an adjustment which increased 1998's West Virginia Business and Occupation Taxes by $1.4 million related to a previous period, lower capital stock taxes relating to the 1998 asset write-down as a result of Pennsylvania restructuring, and decreased gross receipts taxes, partially offset by higher Federal Insurance Contribution Act taxes.

 

Regulated operations and unregulated generation taxes other than income taxes in 2000 and 1999 reflect the recategorization of taxes other than income taxes associated with the transfer of generating assets during those years. The 2000 decrease in regulated taxes other than income taxes is partially offset by taxes related to the acquisitions of West Virginia Power and Mountaineer Gas.

 

Federal and state income taxes for 2000 increased $20.4 million, due to an increase in taxable income and an increase in state income tax net of federal income tax benefit.

 

The 1999 decrease in federal and state income taxes of $4.0 million was primarily due to tax benefits related to the flow through of plant removal costs for regulatory purposes, offset in part by increased taxable income.

 

Note G to the consolidated financial statements provides a further analysis of income tax expenses.

 

The increases in allowance for borrowed funds used during construction and interest capitalized of $1.4 million in 2000 and $1.6 million in 1999 reflects an increase in construction activity financed by short-term debt. The allowance for borrowed funds used during construction component of the formula receives greater weighting when short-term debt increases. In addition, increases in unregulated generation construction capitalized interest contributed to the increases.

M-13

 

Other income, net, increased $2.9 million for 2000 due to interest income on temporary cash investments, income related to investments of the Company's unregulated subsidiary, Allegheny Ventures, and a refund of hydroelectric license fees of $2.8 million ($1.8 million net of taxes) related to a cancelled facility.

 

The decrease in other income, net, of $6.6 million in 1999 was primarily due to a $4.3 million insurance settlement received in 1998.

 

Interest on long-term debt and other interest for 2000, 1999, and 1998 were as follows:

Interest Expense

(Millions of dollars)

2000

1999

1998

Interest on long-term debt:

Regulated operations

$152.5

$127.5

$151.0

Unregulated generation

34.9

29.2

10.1

Elimination

(14.7)

(1.5)

Total interest on long-term debt

172.7

155.2

161.1

Other interest::

Regulated operations

49.8

27.9

19.4

Unregulated generation

10.7

3.7

Other

0.3

Elimination

(4.2)

Total other interest

56.6

31.6

19.4

Total interest expense

$229.3

$186.8

$180.5

The increases in total interest on long-term debt for 2000 of $17.5 million resulted from increased average long-term debt outstanding. The decrease in total interest on long-term debt in 1999 of $5.9 million resulted from reduced average long-term debt outstanding.

 

The elimination between regulated operations and unregulated generation on long-term debt is to remove the effect of pollution control debt interest recorded by Allegheny Energy Supply and also by West Penn and Potomac Edison. Allegheny Energy Supply assumed the service obligation for the pollution control debt in conjunction with the transfer of West Penn and Potomac Edison's generating assets. West Penn and Potomac Edison continued to be co-obligors with respect to the pollution control debt through December 22, 2000.

 

Other interest expense reflects changes in the levels of short-term debt maintained by the companies throughout the year, as well as the associated interest rates.

 

Other interest expense increased by $25 million in 2000 due to an increase in the average short-term debt outstanding and an increase in the average interest rates. The increase in other interest expense of $12.2 million in 1999 resulted primarily from the increase in short-term debt outstanding in conjunction with the repurchase of the Company's common stock that began in the first quarter of 1999.

 

For additional information regarding the Company's short-term and long-term debt, see the consolidated statement of capitalization and Note I to the consolidated financial statements.

 

Dividends on the preferred stock of the subsidiaries decreased due to the redemption by Potomac Edison and West Penn of their cumulative preferred stock on September 30, 1999, and July 15, 1999, respectively.

 

The extraordinary charge in 2000 of $77 million, net of taxes, reflects a write-off by the Company's subsidiaries, Monongahela Power and Potomac Edison, for net regulatory assets determined to be unrecoverable from customers and the establishment of a rate stabilization account for residential and small commercial customers as required by the deregulation plans adopted in Ohio, Virginia, and West Virginia.

 

The extraordinary charge in 1999 of $27 million after taxes was required to reflect a write-off of $17 million after taxes related to the Maryland PSC's approval in December 1999 of a deregulation plan for Potomac Edison and $10 million after taxes for the difference between the reacquisition price and the net carrying amount of first mortgage bonds repurchased as a result of the deregulation process in Pennsylvania. The extraordinary charge in 1998 of $275.4 million after taxes was required to reflect a write-off of certain costs not recoverable under the Pennsylvania deregulation plan for West Penn approved by the Pennsylvania PUC in 1998. See Notes B, C, and F to the consolidated financial statements for additional information.

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FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

 

Liquidity and Capital Requirements 

 

To meet cash needs for operating expenses, the payment of interest and dividends, retirement of debt and certain preferred stocks, and for acquisitions and construction programs, the Company and its subsidiaries have used internally generated funds and external financings, such as the sale of common and preferred stock, debt instruments, installment loans, and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions, the companies' cash needs, and capital structure objectives of the Company. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and market conditions.

 

Capital expenditures, including construction expenditures, of all of the subsidiaries in 2000 were $402 million and, for 2001 and 2002, are estimated at $2,231.5 million and $543.4 million, respectively. In 1999, Monongahela Power acquired the assets of West Virginia Power for approximately $95 million, and, in 2000, purchased Mountaineer Gas for approximately $326 million (which included the assumption of $100 million in existing debt). The 2001 and 2002 estimated expenditures include $189 million and $225 million, respectively, for environmental control technology. Future unregulated construction expenditures will reflect additions of generating capacity to sell into deregulated markets. As described under Environmental Issues on page 39, the subsidiaries could potentially face significant mandated increases in capital expenditures and operating costs related to environmental issues. The subsidiaries also have additional capital requirements for debt maturities. (See Note Q to the consolidated financial statements.)

 

Internal Cash Flow 

 

Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $346 million in 2000, compared with $415 million in 1999. Current rate levels and reduced levels of construction expenditures permitted the regulated subsidiaries to finance all of their construction expenditures in 2000 and 1999 with internal cash flow.

 

Dividends paid on common stock in each of the years 2000 and 1999 were $1.72 per share. The dividend payout ratio in 2000 of 60.6 percent, excluding the extraordinary charges, decreased from the 64.6 percent ratio in 1999, excluding the extraordinary and other charges.

 

Financing 

 

The Company did not issue any common stock in 2000, 1999, or 1998. The Company began a stock repurchase program in 1999 to repurchase common stock worth up to $500 million from time to time at price levels the Company deemed attractive. The Company repurchased 12 million shares of its common stock in 1999 at an aggregate cost of $398.4 million (an average cost of $33.20 per share). There were no shares repurchased during 2000. The shares for its Dividend Reinvestment and Stock Purchase Plan, Employee Stock Ownership and Savings Plan, Restricted Stock Plan for Outside Directors, and Performance Share Plan were purchased on the open market.

 

Short-term debt increased $81.1 million to $722.2 million in 2000. At December 31, 2000, unused lines of credit with banks were $565 million.

 

The Company and its subsidiaries anticipate meeting their 2001 cash needs through internal cash generation, cash on hand, short-term borrowings as necessary, external financings, and by issuing debt and equity.

 

On March 1, 2000, $75 million of Potomac Edison's 57⁄8 percent series first mortgage bonds matured; Monongahela Power's $65 million of 55⁄8 percent series first mortgage bonds matured on April 1, 2000; and, in March, June, September, and December of 2000, West Penn redeemed a total of $46.8 million of class A-1 6.32 percent transition bonds.

 

On June 1, 2000, Potomac Edison issued $80 million of floating rate private placement notes, due May 1, 2002, assumable by Allegheny Energy Supply upon its acquisition of Potomac Edison's Maryland generating assets. In August 2000, after the Potomac Edison generating assets were transferred to Allegheny Energy Supply, the notes were remarketed as Allegheny Energy Supply floating rate (three-month London Interbank Offer Rate (LIBOR) plus .80 percent) notes with the same maturity date. No additional proceeds were received.

 

On August 18, 2000, Monongahela Power borrowed $61 million, under a senior secured credit facility, at a rate of 7.18 percent, with a maturity of November 20, 2000. On November 20, 2000, Monongahela Power paid off the original $61 million borrowing and borrowed $100 million at a rate of 7.21 percent with a maturity of May 21, 2001. The facility will be transferred to Allegheny Energy Supply concurrent with the transfer of Monongahela Power's West Virginia generating assets to Allegheny Energy Supply.

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On August 18, 2000, the Company issued $165 million aggregate principal amount of its 7.75 percent notes due August 1, 2005. The Company contributed $162.5 million of the proceeds from its financing to Monongahela Power. Monongahela Power used the proceeds from the Company and the $61 million borrowed under the senior secured credit facility (as discussed above) in connection with the purchase of Mountaineer Gas.

 

As part of the purchase of Mountaineer Gas on August 18, 2000, Monongahela Power assumed $100 million of existing Mountaineer Gas debt. This debt consists of several senior unsecured notes and a promissory note with fixed interest rates between 7.00 percent and 8.09 percent, and maturity dates between April 1, 2009, and October 31, 2019.

 

On November 7, 2000, the Company also issued unsecured notes in an aggregate principal amount of $135 million, bearing an interest rate of 7.75 percent due 2005. These notes were a further issuance of, and form a single series with, the $165 million aggregate principal amount of the Company's 7.75 percent notes issued on August 18, 2000, as discussed above.

 

In 1999, West Penn issued $600 million of transition bonds with varying average lives ranging from one to eight years with a weighted average cost of 6.887 percent to "securitize" transition costs related to its restructuring settlement described in Note B to the consolidated financial statements. During 1999, West Penn reacquired all of its outstanding $525 million of first mortgage bonds.

 

West Penn called or redeemed all outstanding shares of its cumulative preferred stock with a combined par value of $79.7 million plus redemption premiums of $3.3 million on July 15, 1999, with proceeds from new $84 million five-year unsecured medium-term notes issued in the second quarter of 1999 at a 6.375 percent coupon rate. Potomac Edison called all outstanding shares of its cumulative preferred stock with a combined par value of $16.4 million plus redemption premiums of $0.5 million on September 30, 1999, with funds on hand. The redemption of the preferred stock allowed Potomac Edison and West Penn to revise their Articles of Incorporation, providing greater financial flexibility in restructuring debt.

 

In April 1999, Monongahela Power, Potomac Edison, and West Penn issued $7.7 million, $9.3 million, and $13.8 million, respectively, of 5.50 percent 30-year pollution control revenue notes to Pleasants County, West Virginia. In December 1999, Monongahela Power issued $110 million of 7.36 percent unsecured medium-term notes, due in January 2010, in part to finance the purchase of West Virginia Power.

 

In October 1999, AYP Energy prepaid $30 million of its bank loan, reducing the obligation from $160 million to $130 million. In December 1999, the $130 million debt obligation was assigned to Allegheny Energy Supply. Allegheny Energy Supply prepaid the remaining debt obligation on October 25, 2000, with funds obtained from short-term debt.

 

The long-term debt due within one year at December 31, 2000, of $160.2 million represents $100.0 million of Monongahela Power's senior credit facility due May 21, 2001, and $60.2 million of West Penn Funding, LLC, transition bonds due on various dates. The transition bonds are supported by an Intangible Transition Charge (ITC) that replaces a portion of the CTC that customers pay. The proceeds from the ITC will be used to pay the principal and interest on these transition bonds, as well as other associated expenses.

 

SIGNIFICANT CONTINUING ISSUES

 

Electric Energy Competition 

 

The electricity supply segment of the electric industry in the United States is becoming increasingly competitive. The national Energy Policy Act of 1992 deregulated the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. This resulted in open access transmission tariffs being established nationwide. The Company continues to be an advocate of federal legislation to remove artificial barriers to competition in electricity markets, avoid regional dislocations, and ensure level playing fields.

 

In addition, with the wholesale electricity market becoming more competitive, the majority of states have taken active steps toward allowing retail customers the right to choose their electricity supplier.

 

The Company is at the forefront of state-implemented retail competition, having negotiated settlement agreements in all of the states that Allegheny Power serves. Pennsylvania and Maryland have retail choice programs in place. In October 2000, Ohio approved the implementation of a deregulation plan for Monongahela Power beginning January 1, 2001. In March 2000, West Virginia's Legislature approved a deregulation plan for Monongahela Power pending additional legislation regarding tax revenues for state and local governments. In July 2000, Virginia approved a separation plan for the generating assets of Potomac Edison and continues to make progress toward the implementation of customer choice.

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Activities at the Federal Level 

 

The Company continues to seek enactment of federal legislation to bring choice to all retail electric customers, deregulate the generation and sale of electricity on a national level, and create a more liquid, free market for electric power. Fully meeting challenges in the emerging competitive environment will be difficult for the Company unless certain outmoded and anticompetitive laws, specifically the PUHCA and Section 210 (Mandatory Purchase Provisions) of PURPA, are repealed or significantly revised. The Company continues to advocate the repeal of PUHCA and Section 210 of PURPA on the grounds that they are obsolete and anticompetitive and that PURPA results in utility customers paying above-market prices for power. H.R. 2944, which was sponsored by U.S. Representative Joe Barton, was favorably reported out of the House Commerce Subcommittee on Energy and Power. While the bill does not mandate a certain date for customer choice, several key provisions favored by the Company are included in the legislation, including an amendment that allows existing state restructuring plans and agreements to remain in effect. Other provisions address important Company priorities by repealing PUHCA and the mandatory purchase provisions of PURPA. Although there was considerable activity and discussion on this bill and several other bills in the House and Senate, that activity fell short of moving consensus legislation forward prior to adjournment of the 106th Congress. The Company anticipates that the 107th Congress will address these issues.

 

Maryland Activities 

 

On June 7, 2000, the Maryland PSC approved the transfer of the generating assets of Potomac Edison to Allegheny Energy Supply. The transfer was made in August 2000. Maryland customers of Potomac Edison had the right to choose an alternative electric provider on July 1, 2000, although the Maryland PSC has not yet finalized all of the rules that will govern customer choice in the state.

 

On July 1, 2000, the Maryland PSC issued a restrictive order imposing standards of conduct for transactions between Maryland utilities and their affiliates. Among other things, the order:

- restricts sharing of employees between utilities and affiliates;

- announces the Maryland PSC's intent to impose a royalty fee to compensate the utility for the use by an affiliate of the utility's name and/or logo and for other "intangible or unqualified benefits; " and

- requires asymmetric pricing for asset transfers between utilities and their affiliates (excluding the transfer of Potomac Edison's Maryland jurisdictional generating assets to Allegheny Energy Supply). Asymmetric pricing requires that transfers of assets from the regulated utility to an affiliate be recorded at the greater of book cost or market value while transfers of assets from the affiliate to the regulated utility be recorded at the lesser of book costs or market value.

Potomac Edison, along with substantially all of Maryland's gas and electric utilities, filed a Circuit Court petition for judicial review and a motion for stay of the order. The Circuit Court has granted a partial stay of the Maryland PSC's Code of Conduct/Affiliated Transactions Order. The Judge granted a stay on the issues of employee sharing, royalties for the use of the name and logo and for certain intangibles, and on the requirement to use a disclaimer on advertising for non-core services.

 

Ohio Activities 

 

The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. All of the state's customers were able to choose their electricity supplier starting January 1, 2001, beginning a five-year transition to market rates. Residential customers are guaranteed a five percent cut in the generation portion of their rate.

 

Monongahela Power reached a stipulated agreement with major parties on a transition plan to bring electric choice to its approximately 29,000 Ohio customers. The Ohio PUC approved the stipulation on October 5, 2000. The restructuring plan allows the Company to transfer its Ohio generating assets to Allegheny Energy Supply at net book value on or after January 1, 2001. See Note B to the consolidated financial statements for additional information.

 

Pennsylvania Activities 

 

Two-thirds of West Penn's customers in Pennsylvania were able to choose their electricity supplier effective January 2, 1999. As of January 1, 2000, all of West Penn's electricity customers in Pennsylvania had the right to choose their electric suppliers. The Company has retained more than 99 percent of its Pennsylvania customers as of December 31, 2000. See Note B to the consolidated financial statements for additional information.

 

Virginia Activities 

 

The Virginia Electric Utility Restructuring Act (Restructuring Act) became law on March 25, 1999. All state utilities were required to submit a restructuring plan by January 1, 2001, to be effective on January 1, 2002. Accordingly, the Company filed Phase II of the Functional Separation Plan on December 19, 2000. Customer choice will be phased in beginning on January 1, 2002, with full customer choice by January 1, 2004.

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The Restructuring Act was amended during the 2000 General Assembly legislative session to direct the Virginia SCC to prepare for legislative approval a plan for competitive metering and billing and to authorize the Virginia SCC to implement a consumer education program on electric choice, funded through its regulatory tax.

 

On July 11, 2000, the Virginia SCC issued an order approving the Company's separation plan, permitting the transfer of Potomac Edison's generating assets and the provisions of the Phase I application. See Note B to the consolidated financial statements for additional information.

 

Various rulemaking proceedings to implement customer choice are ongoing before the Virginia SCC.

 

West Virginia Activities 

 

In March 1998, the West Virginia Legislature passed legislation that directed the W.Va. PSC to develop a restructuring plan which would meet the dictates and goals of the legislation. In January 2000, the W.Va. PSC submitted a restructuring plan to the Legislature for approval that would open full retail competition on January 1, 2001. On March 11, 2000, the West Virginia Legislature approved the W.Va. PSC's plan, but assigned the tax issues surrounding the plan to the 2000 Legislative Interim Committees to recommend the necessary tax changes involved and come back to the Legislature in 2001 for approval of those changes and authority to implement the plan. The start date of competition is contingent upon the necessary tax changes being made and approved by the Legislature. The W.Va. PSC is currently in the process of developing the rules under which competition will occur.

 

The W.Va. PSC approved Potomac Edison's request to transfer its generating assets to Allegheny Energy Supply on or after July 1, 2000, and established a process for obtaining approval to transfer Monongahela Power's assets on or before the starting date for customer choice. In accordance with the restructuring agreement, Potomac Edison and Monongahela Power implemented a commercial and industrial rate reduction program on July 1, 2000.

 

Accounting for the Effects of Price Deregulation 

 

In accordance with the guidance of EITF Issue No. 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statement Nos. 71 and 101," the Company has discontinued the application of SFAS No. 71 to its electric generation businesses in all of the states in which the Company provides utility service. See Note C to the consolidated financial statements for additional information.

 

Environmental Issues

 

The Environmental Protection Agency (EPA) nitrogen oxides (NOX) State Implementation Plan (SIP) call regulation has been under litigation. On March 3, 2000, the District of Columbia Circuit Court of Appeals issued a decision that basically upheld the regulation. However, state and industry litigants filed an appeal of that decision in April 2000. On June 23, 2000, the Court denied the request for the appeal. Although the Court did issue an order to delay the compliance date from May 1, 2003, until May 31, 2004, both the Maryland and Pennsylvania state rules to implement the EPA NOX SIP call regulation still require compliance by May 1, 2003. West Virginia has issued a proposed rule that would postpone compliance until May 1, 2005. However, the EPA Section 126 petition regulation also requires the same level of NOX reductions as the EPA NOX SIP call regulation with a May 1, 2003, compliance date. The EPA Section 126 petition rule is also under litigation in the District Court of Columbia Circuit Court of Appeals, with a decision expected in early 2001. The Company's compliance with such stringent regulations will require the installation of expensive post-combustion control technologies on most of its power stations. The Company's construction forecast includes the expenditure of $376.9 million of capital costs during the 2001 through 2004 period to comply with these regulations. Approximately $63.5 million was spent in 2000.

 

On August 2, 2000, the Company received a letter from the EPA requiring it to provide certain information on the following 10 electric generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island. Allegheny Energy Supply and Monongahela Power now own these electric generating stations. The letter requested information under Section 114 of the federal Clean Air Act to determine compliance with federal and state implementation plan requirements, including potential application of federal New Source Performance Standards. In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing facility. The Company submitted these records in January 2001. The eventual outcome of the EPA investigation is unknown.

 

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in many cases. The Company believes its generating facilities have been operating in accordance with the Clean Air Act and the rules implementing the Act. The experience of other utilities, however, suggests that, in recent years, the EPA may well have revised its interpretation of the rules regarding the determination of whether an action at a facility constitutes routine maintenance, which would not trigger the requirements of the New Source Performance Standards, or a major modification of the facility, which would require compliance with the New Source Performance Standards. If federal New Source Performance Standards were to be applied to these generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. In connection with the deregulation of generation, the Company has agreed to rate caps in each of its jurisdictions, and there are no provisions under those arrangements to increase rates to cover such expenditures.

M-18

 

In December 2000, the EPA issued a decision to regulate coal- and oil-fired electric utility mercury emissions under Title III, Section 112 of the 1990 Clean Air Act Amendments. The EPA plans to issue a proposed regulation by December 2003 and a final regulation by December 2004. The timing and level of required mercury emission reductions are unknown at this time.

 

Right-to-Know

 

On Earth Day 1997, former President Clinton announced the expansion of the federal Emergency Planning and Community Right-to-Know Act (RTK) reporting to include electric utilities, but limited to facilities that combust coal and/or oil for the purpose of generating power for distribution in commerce. The purpose of RTK is to provide site-specific information on chemical emissions to the air, land, and water. Packets of information about the Company's emissions were provided to the media in the Company's area and posted on the Company's web site. The Company filed its 1999 RTK report with the EPA prior to the July 1, 2000, deadline, reporting 27.5 million pounds of total releases for calendar year 1999.

 

Energy Risk Management

 

The Company is exposed to a variety of commodity driven risks associated with the wholesale and retail marketing of electricity, including the generation, procurement, and marketing of power. The Company is mandated by the Board of Directors of the Company to engage in a program that systematically identifies, measures, evaluates, and actively manages and reports on market-driven risks.

 

The Company's wholesale and retail activities principally consist of marketing and buying and selling over-the-counter contracts for the purchase and sale of electricity. The majority of the forward contracts represent commitments to purchase or sell electricity at fixed prices in the future. These contracts require physical delivery of electricity.

 

The Company also uses option contracts to buy and sell electricity at fixed prices in the future. These option contracts are primarily entered into for risk management purposes. The risk management activities focus on management of volume risks (supply) and operational risks (plant outages). The Company's principal intent and business objective for the use of its capital assets and contracts is the same - provide it with physical power supply to enable it to deliver electricity to meet customers' needs.

 

The Company has entered into long-term contractual obligations for sales of electricity to other load-serving entities, including affiliated electric utilities, municipalities, and retail load aggregators.

 

The Company has a Corporate Energy Risk Control Policy adopted by the Board of Directors and monitored by an Exposure Management Committee chaired by the Chief Executive Officer and composed of senior management. An independent risk management group, operating separately from the businesses actively managing these risk exposures, monitors market risks to ensure compliance with the Policy.

 

Market risk arises from the potential for changes in the value of energy related to price and volatility in the market. The Company reduces these risks by using its generating assets to back positions on physical transactions. A Value-at-Risk (VaR) model is used to measure the market exposure resulting from the wholesale and retail activities. VaR is a statistical model that attempts to predict risk of loss based on historical market price and volatility data over a given period of time. The Company's 12-month average one-day VaR with respect to its wholesale and retail marketing of electricity for its unregulated generation segment, excluding the commodity price exposure related to the procurement of fuel, was $12.3 million using a 95 percent confidence level. The Company entered into long-term arrangements (terms of 12 months or longer) to purchase approximately 90 percent of its base fuel requirements in 2000. The Company depends on short-term arrangements and spot purchases for its remaining requirements. Until 2005, the Company expects to meet its total coal requirements for its generating assets under existing contracts or from known suppliers.

 

Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. The credit standing of counterparties is established through the evaluation of the prospective counterparty's financial condition, specified collateral requirements where deemed necessary, and the use of standardized agreements which facilitate netting of cash flows associated with a single counterparty. Financial conditions of existing counterparties are monitored on an ongoing basis.

 

Market exposure and credit risk have established aggregate and counterparty limits that are monitored within the guidelines of the Corporate Energy Risk Control Policy.

M-19

 

Energy Trading Activities 

 

In November 1998, the EITF released Issue No. 98-10 under which contracts entered into in connection with energy trading must be marked to market, with gains and losses included in earnings. The Issue defines energy trading activities or energy trading contracts as energy contracts entered into with the objective of generating profits on or from exposure to shifts in market prices.

 

During 2000, Allegheny Energy Supply substantially increased the volume of its wholesale electricity trading activities due to the completion of the construction or acquisition of additional capacity. Allegheny Energy Supply also anticipates the expansion of additional capacity, through construction and acquisition activities, in future years as a result of announcements made during 2000. Based upon the Company's continual evaluation of its business activities under the provisions of EITF Issue No. 98-10, the Company concluded that Allegheny Energy Supply's wholesale electricity activities now represent trading activities. Accordingly, Allegheny Energy Supply recorded its energy trading contracts at fair value on the balance sheet at December 31, 2000, and recorded a gain to earnings for these contracts. See Note J to the consolidated financial statements for additional details.

 

Derivative Instruments and Hedging Activities 

 

In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 was subsequently 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," and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - an amendment of FASB Statement No. 133." Effective January 1, 2001, the Company implemented the requirements of these accounting standards.

 

These Statements establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. They require that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The Statements require that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement or other comprehensive income, and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 is expected to increase the volatility in reported earnings and other comprehensive income.

 

The Company has completed an inventory of financial instruments, commodity contracts, and other commitments for the purpose of identifying and assessing all of the Company's derivatives. The Company determined the fair value of the derivatives, designated certain derivatives as hedges, and assessed the effectiveness of those derivatives as hedges.

 

Allegheny Energy Supply has entered into two forward contracts for the purchase of electricity that qualify for cash flow hedge treatment under SFAS No. 133. Allegheny Energy Supply entered these transactions with the risk management objectives of assuring its ability to meet its contractual obligations to serve the instantaneous physical demands of its customers and to ensure that market movements do not cause a significant degradation in Allegheny Energy Supply's earnings.

 

Cash flow hedge accounting is appropriate only if the derivative is effective at offsetting cash flows from the hedged item and is designated as a hedge at its inception. Additionally, changes in the market value of the hedge must move in an inverse direction from changes in the market value of the hedged item. This effectiveness is measured both at the inception of the hedge and on an ongoing basis, with an acceptable level of effectiveness being at least 80 percent and not more than 125 percent. If and when effectiveness ceases to exist at an acceptable level, hedge accounting ceases and mark-to-market accounting is applied. Any ineffectiveness in Allegheny Energy Supply's hedges will be reported as part of "Purchased power and exchanges, net" on the consolidated statement of operations. The effective portion will be reported in other comprehensive income.

 

Allegheny Energy Supply will record an asset of $1.5 million on its 2001 balance sheet based on the fair value of the two cash flow hedge contracts at January 1, 2001. An offsetting amount will be recorded in other comprehensive income as a change in accounting principle as provided by SFAS No. 133. Allegheny Energy Supply anticipates that the hedges will be highly effective and that there will be no ineffectiveness to be recognized in earnings because the critical terms of the hedging instruments and hedged items match, the fair value of hedging instruments was zero at inception, and the change in expected cash flows on the hedged items and the hedging instruments are based on the same forward commodity prices. Allegheny Energy Supply anticipates that the amounts accumulated in other comprehensive income related to these contracts will be reclassified to earnings during July and August of 2001, when the hedged transactions are recorded.

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Allegheny Energy Supply has certain option contracts for the future sale of electricity that meet the derivative criteria in SFAS No. 133, which do not qualify for special hedge accounting. Allegheny Energy Supply also has entered into option contracts for emission allowances that qualify as derivatives. Allegheny Energy Supply entered into these energy derivatives for the purpose of optimizing the value of its generating assets. Allegheny Energy Supply will record an asset of $0.1 million and a liability of $52.4 million on its balance sheet based on the fair value of these contracts at January 1, 2001. The majority of this liability is related to one contract. The terms of this three-year contract entered into on January 1, 1999, provides the counterparty with the right to purchase, at a fixed price, 270 MW of electricity per hour until December 31, 2001. The fair value of this contract represented a liability of approximately $52.3 million on January 1, 2001. The liability associated with this contract will reduce to zero at December 31, 2001, with the expiration of the contract. The fair value of these contracts will fluctuate over time due to changes in the underlying commodity prices that are influenced by various market factors, including the weather and availability of regional electric generation and transmission capacity. In accordance with SFAS No. 133, Allegheny Energy Supply will record a charge of $31.2 million against earnings, net of the related tax effect ($52.3 million before tax) for these contracts as a change in accounting principle as of January 1, 2001.

 

New Accounting Standard

 

In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." The Statement provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities and is effective for transfers occurring after March 31, 2001. The Statement is not expected to have a material impact on the Company.

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Monongahela Power Company

and Subsidiaries

MANAGEMENT'S DISCUSSION AND

ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

 

FACTORS THAT MAY AFFECT FUTURE RESULTS

 

Certain statements within constitute forward-looking statements with respect to Monongahela Power Company and its subsidiary, Mountaineer Gas Company (Mountaineer Gas) (collectively, the Company). Such forward-looking statements include statements with respect to deregulated activities and movements towards competition in the states served by the Company, markets, products, services, prices, results of operations, capital expenditures, regulatory matters, liquidity and capital resources, resolution and impact of litigation, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

 

Factors that could cause actual results of the Company to differ materially include, among others, the following: general and economic and business conditions; industry capacity; changes in technology; changes in political, social and economic conditions; changes in the price of power and fuel for electric generation; regulatory matters; litigation involving the Company; regulatory conditions applicable to the Company; the loss of any significant customers; and changes in business strategy or development plans.

 

Business Strategy

 

A component of the deregulation plans sponsored by the Company in West Virginia and Ohio is the authority to transfer electric generating assets at net book value to an unregulated affiliate. The West Virginia Legislature passed House Concurrent Resolution 27 on March 11, 2000, approving an electric deregulation plan submitted by the Public Service Commission of West Virginia (W.Va. PSC). Under the resolution, the implementation of the West Virginia deregulation plan cannot occur until the Legislature enacts certain tax changes. The plan provides for customer choice of a generation supplier for all customers and allows the Company to transfer the West Virginia portion (approximately 2,004 megawatts (MW)) of its generating assets to its unregulated affiliate, Allegheny Energy Supply, LLC (Allegheny Energy Supply).

 

On October 5, 2000, the Public Utilities Commission of Ohio (Ohio PUC) approved a stipulation agreement between the Company and the major parties regarding a transition plan to bring electric choice to the Company's approximately 29,000 Ohio customers. As part of the agreement, the Company is permitted to transfer its Ohio jurisdictional generating assets (approximately 352 MW) to Allegheny Energy Supply at net book value on or after January 1, 2001. That transfer is intended to occur in the second quarter 2001.

 

In December 1999, the Company expanded its service territory with the acquisition of West Virginia Power Company (West Virginia Power) assets. The acquisition of West Virginia Power added approximately 26,000 electric distribution customers and 24,000 natural gas customers to the Company's existing business in West Virginia. Also, the Company acquired Mountaineer Gas in August 2000. The acquisition of Mountaineer Gas added approximately 200,000 natural gas customers to the Company's West Virginia regulated utility operations.

 

SIGNIFICANT EVENTS IN 2000, 1999, AND 1998

 

Transfer of Generating Assets

 

In March 2000, the West Virginia Legislature passed House Resolution 27 approving an electric deregulation plan submitted by the W.Va. PSC. Under the resolution, the implementation of the West Virginia deregulation plan cannot occur until the Legislature enacts certain tax changes regarding the preservation of tax revenues for state and local government. The plan provides for customer choice of a generation supplier for all customers and allows the Company to transfer the West Virginia portion (approximately 2,004 MW) of its generating assets to

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Allegheny Energy Supply. In part, the Company is required to file with the W.Va. PSC a petition seeking a Commission finding that a proposed transfer of generating assets complies with the conditions of the deregulation plan. The order also permits the Company to submit a petition to the Commission seeking approval to transfer its West Virginia jurisdictional generating assets prior to the implementation of the deregulation plan. A filing before the implementation of the deregulation plan is required to include commitments to the consumer and other protections contained in the deregulation plan. In a petition filed on August 15, 2000, and supplemented on October 31, 2000, the Company sought W.Va. PSC approval to transfer its West Virginia portion of its generating assets to Allegheny Energy Supply on or after January 1, 2001, contemporaneously with the transfer of its Ohio jurisdictional generating assets. The Company now considers it highly unlikely that legislative action will occur in West Virginia in 2001. If legislative action does not occur, the Company intends to explore other ways to complete the transfer of its West Virginia jurisdictional generating assets to Allegheny Energy Supply.

 

In October 2000, the Ohio PUC approved a settlement to implement a restructuring plan for the Company. This restructuring plan allowed Ohio customers of the Company to choose their generation supplier starting January 1, 2001. Also, the Company was permitted to transfer the Ohio jurisdictional portion (approximately 352 MW) of its generating assets to Allegheny Energy Supply at net book value on or after January 1, 2001. That transfer is intended to occur in the second quarter of 2001.

 

See Note B and C to the consolidated financial statements for details of the Company's various state restructurings and other information about the electric generation deregulation process.

 

Acquisitions

 

On August 18, 2000, the Company completed the purchase of Mountaineer Gas, a regulated natural gas sales, transportation, and distribution company serving a large portion of West Virginia, from Energy Corporation of America (ECA) for approximately $326 million, which included the assumption of $100 million of existing long-term debt. The acquisition included the assets of Mountaineer Gas Services, which operates natural gas-producing properties, natural gas-gathering facilities, and intrastate transmission pipelines. The acquisition increased the Company's number of gas customers in West Virginia by approximately 200,000. (See Note D to the consolidated financial statements for additional information.)

 

In December 1999, the Company purchased from UtiliCorp United, Inc. the assets of West Virginia Power, an electric and natural gas distribution company located in southern West Virginia, for approximately $95 million.

 

Rate Matters

 

The Company and its affiliates, The Potomac Edison Company (Potomac Edison) and West Penn Power Company (West Penn), together doing business as Allegheny Power, operate electric transmission and electric and natural gas distribution systems. Allegheny Power also generates electric energy in jurisdictions which have not yet deregulated electric generation. These subsidiaries are subject to federal and state regulation, including the Public Utility Holding Company Act of 1935 (PUHCA). Allegheny Power's markets for regulated electric and gas retail sales are in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia.

 

On June 23, 2000, the W.Va. PSC approved a Joint Stipulation and Agreement for Settlement, stating agreed-upon rates designed to make the rates of Potomac Edison and the Company consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require several incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue reduction of approximately $0.5 million for 2000 increasing over eight years to an annual reduction of approximately $6.0 million. Offsetting this decrease, the settlement approved by the W.Va. PSC directs the Company to amortize the existing overcollected deferred fuel balance as of June 30, 2000 (approximately $6.0 million), as a reduction of expenses over a four-and-one-half year period beginning July 1, 2000. Also, effective July 1, 2000, the Company ceased their expanded net energy cost (fuel clause) as part of the settlement.

 

On October 11, 2000, the W.Va. PSC approved an interim increase on the commodity rate for gas customers of the Company (formerly West Virginia Power customers) for gas service bills rendered on and after December 1,

M-23

2000. On December 11, 2000, the W.Va. PSC approved additional increases for gas service bills rendered on and after January 1, 2001, through November 30, 2001 (total revenue increase for the 12-month period of $5.1 million or 22.6 percent). The commodity rate is the portion of the gas service bill that reflects the cost of natural gas, which has increased significantly during 2000. The W.Va. PSC has approved a tiered rate structure with rates established for the winter heating season, effective January 1, 2001, through April 30, 2001, and further increased rates effective May 1, 2001, through November 30, 2001, dependent upon the level of cost recovery after the winter heating season. This approach allows the Company full recovery, but eases the increase on the average customer. These increases have no effect on earnings because they were implemented via the Purchased Gas Adjustment mechanism. Under the Purchased Gas Adjustment mechanism, differences between revenues received for energy costs and actual energy costs are deferred until the next proceeding, when energy rates are adjusted to return or recover previous overrecoveries or underrecoveries, respectively.

 

Mountaineer Gas, in response to significant increases in the market price for natural gas, filed for a rate increase with the W.Va. PSC on January 4, 2001. If natural gas prices remain at current levels, the proposed overall rates will increase by approximately 39 percent ($67 million) over present rates. Mountaineer Gas anticipates that the W.Va. PSC will postpone the effective date until November 1, 2001, when the current rate moratorium ends. The conclusion of the current rate moratorium coincides with the expiration of the primary Mountaineer Gas fixed-price fuel supply contract.

 

Regional Transmission Organization

 

In adopting its Rule 2000, the Federal Energy Regulatory Commission (FERC) defined requirements for transmission facility owners, such as the Company, Potomac Edison, and West Penn, to participate in some form of a regional transmission organization (RTO). Additionally, the state jurisdictions within which the Company operates have, to different degrees, started to define their transition to a competitive generation marketplace. As part of this, they have identified transmission as a key link to making the electricity market efficient.

 

Allegheny Power announced on October 5, 2000, that it had signed a Memorandum of Agreement with the Pennsylvania-New Jersey-Maryland Interconnection, LLC (PJM) to develop a new transmission affiliation with PJM, referred to as PJM West. The Memorandum of Agreement was outlined in a filing submitted to the FERC on October 16, 2000, in order to meet the requirements of FERC's Order 2000.

 

FERC's Order 2000 required all electric utilities, not currently in an independent system operator (ISO), to file a plan on how they would participate in an RTO, those entities that oversee and control the power grid. Although PJM is an ISO, Allegheny Power will not join PJM, but will pursue the development of an affiliation with PJM, working within the PJM framework, which would also be available to other utilities.

 

Allegheny Power is leading the new initiative, known as PJM West, which will facilitate economic transmission service, while simultaneously expanding the PJM market. Allegheny Energy Supply will benefit from the PJM West initiative by having its generation within PJM and open to markets in the current PJM region.

 

In December 2000, Allegheny Power and PJM announced the execution of an agreement in principle to broaden PJM West that will further expand the PJM market into the Pittsburgh area. This agreement provides for Duquesne Light Company to join Allegheny Power in the development of PJM West by executing a similar joint agreement with PJM as did Allegheny Power.

 

PURPA Power Project Termination

 

In 1999, the Company settled for $2.3 million litigation by a developer alleging failure by the Company to comply with the Public Utility Regulatory Policies Act of 1978 (PURPA) regulations.

 

Electric Industry Restructuring

 

See Electric Energy Competition on page 12 for ongoing information regarding electric industry restructuring.

M-24

REVIEW OF OPERATIONS

 

Earnings Summary

(Millions of Dollars)

2000

1999

1998

       

Operations

$94.6

$92.3

$82.4

Extraordinary charge, net (Note C)

(63.1)

    

    

Consolidated net income

$31.5

$92.3

$82.4

The increase in 2000 earnings from operations, before extraordinary charge, of $2.3 million was due primarily to increased income of $2.8 million related to the acquisition of Mountaineer Gas. The increase in 1999 earnings resulted, in part, from increased retail kilowatt-hour (kWh) sales, including increased sales to residential customers due to winter weather that was cooler than the relatively warm winter of 1998, as measured by heating degree days. The increase is also due to a 1999 decrease in federal and state income taxes of $9.0 million primarily due to the Company's share of tax savings in consolidation related to its parent, Allegheny Energy, Inc. and to a net change in income tax provisions related to prior years.

 

The extraordinary charge of $63.1 million, net of taxes, reflects write-offs by the Company of costs determined to be unrecoverable as a result of West Virginia and Ohio legislation requiring deregulation of electric generation and recognition of a rate stabilization obligation.

 

Sales and Revenues

 

The major retail customer classes (residential, commercial, and industrial) include electric and gas revenues as shown below:

(Millions of Dollars)

2000

1999

1998

       

Electric revenues

$595.9

$558.6

$536.0

Gas revenues

80.2

        

        

Total retail revenues

$676.1

$558.6

$536.0

The Company's residential, commercial, and industrial revenues in 2000 were favorably affected by the addition of gas services related revenues. In August 2000, the Company acquired Mountaineer Gas, a natural gas distribution company serving approximately 200,000 retail natural gas customers in West Virginia, from ECA. Also, the Company acquired West Virginia Power and its 24,000 natural gas customers from Utilicorp United, Inc. in late December 1999.

 

Percentage changes in electric revenues and kWh sales in 2000 and 1999 by major retail customer classes were:

 

2000 vs. 1999

1999 vs. 1998

 

Revenues

KWh

Revenues

KWh

         

Residential

9.6%

9.2%

4.9%

4.6%

Commercial

11.0

13.6

2.8

2.2

Industrial

1.3

4.2

4.4

4.1

Total

6.7%

7.4%

4.2%

3.8%

The increase in 2000 residential, commercial, and industrial kWh sales was primarily due to growth in the number of customers, due to the acquisition of West Virginia Power and its 26,000 electric customers, from Utilicorp United, Inc. in late December 1999.

M-25

 

Residential kWh sales, which are more weather sensitive than the other classes, also increased due to customer usage, primarily because of weather conditions in late 2000. The 1999 increase in residential kWh sales was due primarily to changes in customer usage because of weather conditions, and to a lesser extent, growth in the number of customers.

 

Commercial kWh sales, are also affected by weather, but to a lesser extent than residential, also increased in 2000 due to customer usage. The increase in commercial kWh sales in 1999 reflects growth in the number of customers and increased usage.

 

The increase in industrial kWh sales in 2000 was primarily due to increased kWh sales to iron and steel customers and to chemical customers. The increase in industrial kWh sales in 1999 was due to increased kWh sales to iron and steel customers and to paper and printing product customers.

 

Changes in electric revenues from retail customers resulted from the following:

 

 

Changes from Prior Year

(Millions of Dollars)

2000 vs 1999

1999 vs 1998

     

Fuel clauses

$ 9.4

All other

$37.3

13.2

Net change in retail revenues

$37.3

$22.6

Revenues reflect not only the changes in kWh sales and base rate changes, but also any changes in revenues from fuel and energy cost adjustment clauses (fuel clauses) through June 30, 2000, for West Virginia and December 31, 2000, for Ohio. Effective July 1, 2000, the Company's West Virginia jurisdiction ceased to have a fuel clause. Effective January 1, 2001, a fuel clause ceased to exist for the Company's Ohio jurisdiction. Through June 30, 2000, for West Virginia and December 31, 2000, for Ohio, changes in fuel revenues had no effect on the Company's net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power were passed on to customers by adjustment of customers' bills through a fuel clause.

 

All other is the net effect of kWh sales changes due to changes in customer usage (primarily weather for residential customers), growth in the number of customers, and changes in pricing other than changes in general tariff and fuel clause rates. The increases in 2000 and 1999 all other retail revenues were primarily the result of increased customer usage and growth in the number of customers.

 

Electric wholesale and other revenues were as follows:

(Millions of Dollars)

2000

1999

1998

       

Wholesale customers

$ 4.9

$ 4.6

$ 5.2

Affiliated companies

102.0

84.7

77.3

Street lighting and other

7.4

6.9

6.9

Total wholesale and other revenues

$114.3

$96.2

$89.4

Wholesale customers are cooperatives and municipalities that own their distribution systems and buy all or part of their bulk power needs from the Company under FERC regulation. Competition in the wholesale market for electricity was initiated by the national Energy Policy Act of 1992, which permits wholesale generators, utility-owned and otherwise, and wholesale customers to request from owners of bulk power transmission facilities a commitment to supply transmission services. All of the Company's wholesale customers have signed contracts to remain as customers until November 30, 2003.

M-26

 

Revenues from affiliated companies represent sales of energy and intercompany allocations of generating capacity, generation spinning reserves, and transmission services pursuant to a power supply agreement among the Company and the other regulated utility subsidiaries of the Parent. Revenues from affiliated companies increased $17.3 million in 2000 as the Company now sells bulk power to its unregulated affiliate Allegheny Energy Supply, allowing for a more efficient dispatch of power. The Company has a dispatch arrangement with Allegheny Energy Supply. The 1999 increase of $7.4 million in affiliated revenues was due to increased energy sales to affiliates. As a result of increased generation at one of the Company's power stations in 1999, the Company had more generation available for sale after meeting the needs of its regular customers. Some of this excess generation was sold to affiliates to meet their needs.

 

Street lighting and other affiliated revenues increased $.5 million in 2000 due to gas sales related to the Mountaineer Gas and West Virginia Power acquisitions.

 

The Company had gas revenues of $103.6 million for 2000 due to the acquisitions of West Virginia Power in 1999 and Mountaineer Gas in August 2000.

Bulk power transactions include sales of bulk power and transmission and other energy services to power marketers and other utilities. Bulk power and transmission and other energy services sales for 2000, 1999, and 1998 were as follows:

2000

1999

1998

kWh Transactions (in billions):

Bulk power

.2

.3

Transmission and other energy services

to nonaffiliated companies

2.7

2.1

1.9

Total

2.7

2.3

2.2

Revenues (in millions):

Bulk power

$ .8

$ 6.6

$ 8.5

Transmission and other energy services

to nonaffiliated companies

13.5

12.0

11.3

Total

$14.3

$18.6

$19.8

Revenues from bulk power transactions decreased in 2000 and 1999 due to decreased sales to power marketers and other utilities. In 2000, this decrease was a result of increased affiliated sales due to a dispatch agreement with the Company's unregulated affiliate, Allegheny Energy Supply. With this agreement, regulated operations sells the amount of its bulk power that exceeds its regulated load to Allegheny Energy Supply and conversely buys generation from unregulated operations when regulated load at times exceeds regulated generation. Such a relationship allows the Company's generation to be dispatched in a more efficient manner.

 

Through June 30, 2000, and December 31, 2000, for the Company's West Virginia and Ohio jurisdictions, respectively, the costs of purchased power and revenues from sales to power marketers and other utilities, including transmission services, were recovered from or credited to customers under fuel and energy cost recovery procedures. The impact to the fuel and energy cost recovery clauses may either be positive or negative depending on whether the Company is a net buyer or seller of electricity during such periods and the open commitments, which exist at such times. The impact of such price volatility was insignificant to the Company in the first six months of 2000 for West Virginia and twelve months ended 2000 for Ohio because increases or decreases were passed on to customers through operation of fuel clauses.

 

Effective July 1, 2000, and December 31, 2000, once the fuel clauses were eliminated in West Virginia and Ohio, respectively, the Company assumed the risk and benefits of changes in fuel and purchased power costs and sales of transmission services and bulk power in its West Virginia and Ohio jurisdiction.

 

When a fuel clause is in effect, changes in fuel revenues have no effect on consolidated net income because increases and decreases in fuel and purchased power costs and sales of transmission services and bulk power are passed on to the customer through fuel clauses.

M-27

 

Revenues from transmission and other energy services in 2000 and 1999 increased $1.5 million and $0.7 million, respectively. Revenues from transmission and other energy services increased in 2000 and 1999 due primarily to increased megawatt-hours (MWh) transmitted.

 

Operating Expenses

 

Fuel expenses increased 3.7% in 2000 due primarily to a 4.3% increase related to kWhs generated, offset in part by a .6% decrease in average fuel prices. The increase in 1999 of .9% was due to an 8.9% increase related to kWhs generated, offset in part by an 8% decrease in average fuel prices. The increases in kWhs generated were to meet retail customer requirements and increased sales to affiliates. The decrease in 1999 average fuel prices was due to renegotiated fuel contracts.

Purchased power and exchanges, net, represents power purchases from and exchanges with other companies and purchases from qualified facilities under the PURPA, capacity charges paid to Allegheny Generating Company (AGC), an affiliate partially owned by the Company, and other transactions with affiliates made pursuant to a power supply agreement whereby each company uses the most economical generation available in the System at any given time, and consists of the following items:

(Millions of Dollars)

2000

1999

1998

Nonaffiliated transactions:

Purchased power:

From PURPA generation*

$70.7

$65.1

$65.5

Other

22.9

15.1

11.6

Power exchanges, net

1.6

(.6)

(.2)

Affiliated transactions:

AGC capacity charges

18.9

19.1

18.4

Other

5.3

.1

.3

Purchased power and exchanges, net

$119.4

$98.8

$95.6

*PURPA cost (cents per kWh)

5.4cents

5.2cents

5.1cents

The $7.8 million increase in other purchased power in 2000 was primarily due to purchases required to serve customers acquired through the acquisition of West Virginia Power. The increase in other purchased power in 1999 resulted primarily from increased purchases for sales.

 

The increase in other affiliated transactions of $5.2 million in 2000 was primarily due to increased purchases from Allegheny Energy Supply. In early 2000, a dispatch agreement was implemented between the Company and Allegheny Energy Supply. The dispatch agreement is a relationship that allows the Company's generation to be dispatched in a more efficient manner. In 2000, the Company purchased generation from Allegheny Energy Supply when the Company's load exceeded its generation. When the Company's generation exceeds its load, the excess generation is sold to Allegheny Energy Supply.

 

Gas purchases and production expenses for 2000, 1999, and 1998 were as follows:

 

(Millions of Dollars)

2000

1999

1998

Total gas purchases and production

expenses

$57.0

$  

$  

Gas purchases and gas production reflects the acquisition of West Virginia Power in December 1999 and Mountaineer Gas in August 2000.

 

Other operations expenses increased $26.8 million in 2000 due primarily to additional expenses associated with serving the customers acquired through the acquisitions of West Virginia Power and Mountaineer Gas. The

M-28

increase in other operation expenses of $8.0 million in 1999 resulted primarily from a write-off of $4.2 million of costs related to a pumped-storage generation project no longer considered useful, $2.3 million of costs associated with settling litigation concerning a PURPA project, and increases in salaries and wages costs.

 

The increase in maintenance expenses of $6.9 million in 2000 was due primarily to increased power station maintenance and the transmission and distribution (T&D) maintenance expenses associated with the West Virginia Power and Mountaineer Gas acquisitions. Maintenance expenses decreased in 1999 by $3.0 million due to decreases in T&D maintenance expenses, offset in part by increases in general plant maintenance which includes renovations of office facilities.

 

Maintenance expenses represent costs incurred to maintain the power stations, the T&D system, and general plant and reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power stations and periodic storm damage on the T&D system. Variations in maintenance expense result primarily from unplanned events and planned projects, which vary in timing and magnitude depending upon the length of time equipment has been in service and the amount of work found necessary when the equipment is dismantled.

 

Depreciation and amortization expense increased $9.6 million in 2000 due to increased investment, primarily associated with the acquisitions of West Virginia Power and Mountaineer Gas. Depreciation and amortization expense in 1999 increased $2.3 million due to increased investment.

 

Taxes other than income taxes increased $12.6 million in 2000 primarily due to additional tax expenses related to the acquisitions of West Virginia Power and Mountaineer Gas. The decrease of $1.3 million in taxes other than income in 1999 was due primarily to a 1998 adjustment to West Virginia Business and Occupation Taxes for prior year.

 

The increase in federal and state income tax expense in 2000 of $10.2 million was primarily due to increased operating income resulting in an increase in taxes of approximately $5.8 million and depreciation differences resulting in an approximate $3.2 million increase in taxes. The decrease in federal and state income taxes of $9.0 million in 1999 was primarily due to the Company's share of tax savings in consolidation related to its parent, Allegheny Energy, and to a net change in income tax provisions related to prior years.

 

Other Income and Deductions

 

The decrease in other income, net, of $2.1 million in 2000 was primarily due the amortization of goodwill related to the West Virginia Power and Mountaineer Gas acquisitions.

 

Interest Charges

 

The increase in interest on long-term debt in 2000 resulted primarily from increased average long-term debt outstanding related to the debt incurred for the acquisitions of West Virginia Power in December 1999 and Mountaineer Gas in August 2000.

 

See Financing on page 11 for more information related to the Company's long-term debt.

 

Other interest expense reflects changes in the levels of short-term debt maintained by the Company throughout the year, as well as the associated interest rates.

 

Extraordinary Charge

 

The extraordinary charge in 2000 of $63.1 million, net of taxes, reflects a write-off by the Company of net regulatory assets determined to be unrecoverable from customers and the establishment of a rate stabilization account for residential and small commercial customers as required by the deregulation plans adopted in Ohio and West Virginia. See Note C of the consolidated financial statements for additional information.

M-29

FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES

 

Liquidity and Capital Requirements

 

To meet cash needs for operating expenses, the payment of interest and dividends, retirement of debt and certain preferred stocks, and for its acquisitions and construction programs, the Company has used internally generated funds and external financings, such as the sale of common and preferred stock, debt instruments, and installment loans. The timing and amount of external financings depend primarily upon economic and financial market conditions, the Company's cash needs, and capitalization ratio objectives. The availability and cost of external financings depend upon the financial health of the companies seeking those funds and market conditions.

Construction expenditures in 2000 were $82 million and, for 2001 and 2002, are estimated at $109.9 million and $111.5 million, respectively. In addition, in 1999 the Company acquired the assets of West Virginia Power for approximately $95 million, and, in 2000, purchased Mountaineer Gas for approximately $326 million (which included the assumption of $100 million in existing debt). The 2001 and 2002 estimated expenditures include $40.9 million and $55.8 million, respectively, for construction of environmental control technology. It is the Company's goal to constrain future construction spending to the approximate level of depreciation currently in rates. As described under Environmental Issues starting on page 15, the Company could potentially face significant mandated increases in construction expenditures and operating costs related to environmental issues. Whether the Company can continue to meet the majority of its construction needs with internally generated cash is largely dependent upon the outcome of these issues. The Company also has additional capital requirements for debt maturities (see Note K to the consolidated financial statements).

Internal Cash Flow

 

Internal generation of cash, consisting of cash flows from operations reduced by dividends, was $140 million in 2000, compared with $86 million in 1999. The increase in 2000 cash flows from operations resulted primarily from a decrease in the level of common stock dividends payable to its Parent, Allegheny Energy. The decrease in 1999 cash flows resulted from an increase in the level of common stock dividends to the Company's Parent. Current rate levels and reduced levels of construction expenditures permitted the Company to finance all of its construction expenditures in 2000 and 1999 with internal cash flow.

 

Financing

 

Short-term debt is used to meet temporary cash needs. An Allegheny Energy internal money pool accommodates intercompany short-term borrowing needs, to the extent that Allegheny Energy and its regulated subsidiaries, including the Company, have funds available. The money pool provides funds to approved Allegheny Energy subsidiaries at the lower of the previous day's Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day's seven-day commercial paper rate, as quoted by the same source, less four basis points. Short-term debt, including notes payable to affiliates under the money pool, increased $8.4 million to $37 million in 2000. At December 31, 2000, the Company had Securities and Exchange Commission (SEC) authorization to issue up to $206 million of short-term debt. The Company anticipates meeting its 2000 cash needs through internal cash generation, cash on hand, and short-term borrowings as necessary, and external financings.

 

The Company's $65 million of 5 5/8 percent series first mortgage bonds matured on April 1, 2000.

 

On August 18, 2000, the Company borrowed $61 million, under a senior secured credit facility, at a rate of 7.18 percent, with a maturity of November 20, 2000. On November 20, 2000, the Company paid off the original $61 million borrowing and borrowed $100 million at a rate of 7.21 percent with a maturity of May 21, 2001. The Company intends to transfer this facility to Allegheny Energy Supply concurrent with the transfer of the Company's West Virginia generating assets to Allegheny Energy Supply.

 

On August 18, 2000, the Company's parent, Allegheny Energy, Inc., issued $165 million aggregate principal amount of its 7.75 percent notes due August 1, 2005. The Company's parent contributed $162.5 million of the proceeds from its financing to the Company. The Company used the proceeds from its parent and the $61 million borrowed under the senior secured credit facility (as discussed above) in connection with the purchase of Mountaineer Gas.

M-30

As part of the purchase of Mountaineer Gas on August 18, 2000, the Company assumed $100 million of existing Mountaineer Gas debt. This debt consists of several senior unsecured notes and a promissory note with fixed interest rates between 7.00 percent and 8.09 percent, and maturity dates between April 1, 2009, and October 31, 2019.

 

In April 1999, the Company issued $7.7 million of 5.50 percent 30-year pollution control revenue notes to Pleasants County, West Virginia. In December 1999, the Company issued $110 million of 7.36 percent unsecured medium-term notes due in January 2010, in part to finance the purchase of West Virginia Power.

 

The Company's long-term debt due within one year at December 31, 2000, was $100 million of 7.21 percent senior credit facility due May 21, 2001.

 

SIGNIFICANT CONTINUING ISSUES

 

Electric Energy Competition

 

The electricity supply segment of the electric industry in the United States is becoming increasingly competitive. The national Energy Policy Act of 1992 deregulated the wholesale exchange of power within the electric industry by permitting the FERC to compel electric utilities to allow third parties to sell electricity to wholesale customers over their transmission systems. This resulted in open access transmission tariffs being established nationwide. The Company, and its parent, Allegheny Energy, continue to be an advocate of federal legislation to remove artificial barriers to competition in electricity markets, avoid regional dislocations, and ensure level playing fields.

 

In addition, with the wholesale electricity market becoming more competitive, the majority of states have taken active steps toward allowing retail customers the right to choose their electricity supplier.

Allegheny Energy is at the forefront of state-implemented retail competition, having negotiated settlement agreements in all of the states that Allegheny Power serves. Pennsylvania and Maryland have retail choice programs in place. In October 2000, Ohio approved the implementation of a deregulation plan for the Company beginning January 1, 2001. In March 2000, West Virginia's Legislature approved a deregulation plan for the Company pending additional legislation regarding tax revenues for state and local governments. In July 2000, Virginia approved a separation plan for the generating assets of Potomac Edison and continues to make progress towards the implementation of customer choice.

 

Activities at the Federal Level

 

The Company and its parent, Allegheny Energy, continue to seek enactment of federal legislation to bring choice to all retail electric customers, deregulate the generation and sale of electricity on a national level, and create a more liquid, free market for electric power. Fully meeting challenges in the emerging competitive environment will be difficult for the Company unless certain outmoded and anticompetitive laws, specifically the PUHCA and Section 210 (Mandatory Purchase Provisions) of PURPA, are repealed or significantly revised. The Company and Allegheny Energy continue to advocate the repeal of PUHCA and Section 210 of PURPA on the grounds that they are obsolete and anticompetitive and that PURPA results in utility customers paying above-market prices for power. H.R. 2944, which was sponsored by U.S. Representative Joe Barton, was favorably reported out of the House Commerce Subcommittee on Energy and Power. While the bill does not mandate a certain date for customer choice, several key provisions favored by the Company are included in the legislation, including an amendment that allows existing state restructuring plans and agreements to remain in effect. Other provisions address important Company priorities by repealing PUHCA and the mandatory purchase provisions of PURPA. Although there was considerable activity and discussion on this bill and several other bills in the House and Senate, that activity fell short of moving consensus legislation forward prior to adjournment of the 106th Congress. The 107th Congress will address these issues.

 

Ohio Activities

 

The Ohio General Assembly passed legislation in 1999 to restructure its electric utility industry. All of the state's customers were able to choose their electricity supplier starting January 1, 2001, beginning a five-year transition to market rates. Residential customers are guaranteed a five percent cut in the generation portion of their rate.

M-31

 

The Company reached a stipulated agreement with major parties on a transition plan to bring electric choice to its approximately 29,000 Ohio customers. The Ohio PUC approved the stipulation on October 5, 2000. The restructuring plan allows the Company to transfer its Ohio generating assets to Allegheny Energy Supply at net book value on or after January 1, 2001. See Note B to the consolidated financial statements for additional information.

 

West Virginia Activities

 

In March 1998, the West Virginia Legislature passed legislation that directed the W.Va. PSC to develop a restructuring plan, which would meet the dictates and goals of the legislation. In January 2000, the W.Va. PSC submitted a restructuring plan to the Legislature for approval that would open full retail competition on January 1, 2001. On March 11, 2000, the West Virginia Legislature approved the W.Va. PSC's plan, but assigned the tax issues surrounding the plan to the 2000 Legislative Interim Committees to recommend the necessary tax changes involved and come back to the Legislature in 2001 for approval of those changes and authority to implement the plan. The start date of competition is contingent upon the necessary tax changes being made and approved by the Legislature. The W.Va. PSC is currently in the process of developing the rules under which competition will occur.

 

The W.Va. PSC approved Potomac Edison's request to transfer its generating assets to Allegheny Energy Supply on or after July 1, 2000, and established a process for obtaining approval to transfer the Company's assets on or before the starting date for customer choice. In accordance with the restructuring agreement, Potomac Edison and the Company implemented a commercial and industrial rate reduction program on July 1, 2000.

 

The status of electric energy competition in Virginia, Maryland, and Pennsylvania in which affiliates of the Company serve are as follows:

 

Virginia Activities

 

The Virginia Electric Utility Restructuring Act (Restructuring Act) became law on March 25, 1999. All state utilities were required to submit a restructuring plan by January 1, 2001, to be effective on January 1, 2002. Accordingly, Potomac Edison filed Phase II of the Functional Separation Plan on December 19, 2000. Customer choice will be phased in beginning on January 1, 2002, with full customer choice by January 1, 2004.

 

The Restructuring Act was amended during the 2000 General Assembly legislative session to direct the Virginia State Corporation Commission (Virginia SCC) to prepare for legislative approval a plan for competitive metering and billing and to authorize the Virginia SCC to implement a consumer education program on electric choice, funded through its regulatory tax.

 

On July 11, 2000, the Virginia SCC issued an order approving Potomac Edison's separation plan, permitting the transfer of Potomac Edison's generating assets and the provisions of the Phase I application.

 

Various rulemaking proceedings to implement customer choice are ongoing before the Virginia SCC.

 

Maryland Activities

 

On June 7, 2000, the Maryland Public Service Commission (Maryland PSC) approved the transfer of the generating assets of Potomac Edison to Allegheny Energy Supply. The transfer was made in August 2000. Maryland customers of Potomac Edison had the right to choose an alternative electric provider on July 1, 2000, although the Maryland PSC has not yet finalized all of the rules that will govern customer choice in the state.

 

On July 1, 2000, the Maryland PSC issued a restrictive order imposing standards of conduct for transactions between Maryland utilities and their affiliates. Among other things, the order:

- restricts sharing of employees between utilities and affiliates;

- announces the Maryland PSC's intent to impose a royalty fee to compensate the utility for the use by an affiliate of the utility's name and/or logo and for other "intangible or unqualified benefits; " and

- requires asymmetric pricing for asset transfers between utilities and their affiliates (excluding the transfer of Potomac Edison's Maryland jurisdictional generating assets to Allegheny Energy Supply). Asymmetric pricing requires that transfers of assets from the regulated utility to an affiliate be recorded at the greater of book cost or market value while transfers of assets from the affiliate to the regulated utility be recorded at the lesser of book costs or market value.

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Potomac Edison, along with substantially all of Maryland's gas and electric utilities, filed a Circuit Court petition for judicial review and a motion for stay of the order. The Circuit Court has granted a partial stay of the Maryland PSC's Code of Conduct/Affiliated Transactions Order. The Judge granted a stay on the issues of employee sharing, royalties for the use of the name and logo and for certain intangibles, and on the requirement to use a disclaimer on advertising for non-core services.

 

Pennsylvania Activities

 

Two-thirds of West Penn's customers in Pennsylvania were able to choose their electricity supplier effective January 2, 1999. As of January 2, 2000, all of West Penn's electricity customers in Pennsylvania had the right to choose their electric suppliers. The Company has retained more than 99 percent of its Pennsylvania customers as of December 31, 2000.

Accounting for the Effects of Price Deregulation 

 

In accordance with the guidance of EITF Issue No. 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statement Nos. 71 and 101," the Company has discontinued the application of SFAS No. 71 to its electric generation business in all of the states in which the Company provides utility service. See Note C to the consolidated financial statements for additional information.

 

Environmental Issues

 

The Environmental Protection Agency (EPA) nitrogen oxides (NOX) State Implementation Plan (SIP) call regulation has been under litigation. On March 3, 2000, the District of Columbia Circuit Court of Appeals issued a decision that basically upheld the regulation. However, state and industry litigants filed an appeal of that decision in April 2000. On June 23, 2000, the Court denied the request for the appeal. Although the Court did issue an order to delay the compliance date from May 1, 2003, until May 31, 2004, both the Maryland and Pennsylvania state rules to implement the EPA NOX SIP call regulation still require compliance by May 1, 2003. West Virginia has issued a proposed rule that would postpone compliance until May 1, 2005. However, the EPA Section 126 petition regulation also requires the same level of NOX reductions as the EPA NOX SIP call regulation with a May 1, 2003, compliance date. The EPA Section 126 petition rule is also under litigation in the District Court of Columbia Circuit Court of Appeals, with a decision expected in early 2001. The Company's compliance with such stringent regulations will require the installation of expensive post-combustion control technologies on most of its power stations. The Company's construction forecast includes the expenditure of $103.6 million of capital costs during the 2001 through 2004 period to comply with these regulations. Approximately $16.8 million was spent in 2000.

 

On August 2, 2000, the Company received a letter from the EPA requiring it to provide certain information on the following 10 electric generating stations: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith, and Willow Island. Allegheny Energy Supply and the Company now own these electric generating stations. The letter requested information under Section 114 of the federal Clean Air Act to determine compliance with federal and state implementation plan requirements, including potential application of federal New Source Performance Standards. In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing facility. The Company submitted these records in January 2001. The eventual outcome of the EPA investigation is unknown.

 

Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings being brought in many cases. The Company believes its generating facilities have been operating in accordance with the Clean Air Act and the rules implementing the Act. The experience of other utilities, however, suggests that, in recent years, the EPA may well have revised its interpretation of the rules regarding the determination of whether an action at a facility constitutes routine maintenance, which would not trigger the requirements of the New Source Performance Standards, or a major modification of the facility, which would require compliance with the New Source Performance Standards. If federal New Source Performance Standards were to be applied to these generating stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. In connection with the deregulation of generation, the Company has agreed to rate caps in each of its jurisdictions, and there are no provisions under those arrangements to increase rates to cover such expenditures.

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In December 2000, the EPA issued a decision to regulate coal- and oil-fired electric utility mercury emissions under Title III, Section 112 of the 1990 Clean Air Act Amendments. The EPA plans to issue a proposed regulation by December 2003 and a final regulation by December 2004. The timing and level of required mercury emission reductions are unknown at this time.

Derivative Instruments and Hedging Activities

 

In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 was subsequently 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," and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities an amendment of FASB Statement No. 133." Effective January 1, 2001, the Company implemented the requirements of these accounting standards.

 

These Statements establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. They require that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The Statements require that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement or other comprehensive income, and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Based on the Company's current activities, SFAS No. 133 is not expected to create a significant increase in the volatility of reported earnings and other comprehensive income.

 

The Company has completed an inventory of financial instruments, commodity contracts, and other commitments for the purpose of identifying and assessing all of the Company's derivatives. From this inventory, the Company determined that it had no financial instruments, commodity contracts, or other commitments that required recognition as assets or liabilities on the balance sheet at fair value under the provisions of SFAS 133.

 

New Accounting Standard

 

In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities." The Statement provides accounting and reporting standards for transfers and servicing of financial assets and extinguishment of liabilities and is effective for transfers occurring after March 31, 2001. The Statement is not expected to have a material impact on the Company.

M-34

The Potomac Edison Company

and Subsidiaries

 

MANAGEMENT'S DISCUSSION AND

ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

 

FACTORS THAT MAY AFFECT FUTURE RESULTS

 

Certain statements within constitute forward-looking statements with respect to The Potomac Edison Company and its subsidiaries (collectively, the Company). Such forward-looking statements include statements with respect to deregulated activities and movements towards competition in the states served by the Company, markets, products, services, prices, results of operations, capital expenditures, regulatory matters, liquidity and capital resources, resolution and impact of litigation, and accounting matters. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results of the Company will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations.

 

Factors that could cause actual results of the Company to differ materially include, among others, the following: general and economic and business conditions; industry capacity; changes in technology; changes in political, social and economic conditions; changes in the price of power and fuel for electric generation; changes in laws and regulations applicable to the Company; litigation involving the Company; environmental regulations; the loss of any significant customers and suppliers; and changes in business strategy, operations, or development plans.

 

BUSINESS STRATEGY

 

In December 1999, the Maryland Public Service Commission (Maryland PSC) approved a settlement agreement, which allowed nearly all Maryland customers of the Company to choose their generation supplier beginning July 1, 2000. In June 2000, the Maryland PSC authorized the Company to transfer the Maryland portion of its generating assets to Allegheny Energy Supply Company, LLC (Allegheny Energy Supply), an affiliate of the Company, on or after July 1, 2000. The Company also obtained the necessary approvals from the Virginia State Corporation Commission (Virginia SCC) and the Public Service Commission of West Virginia (W.Va. PSC) to transfer the Virginia and West Virginia portions of its generating assets to Allegheny Energy Supply in conjunction with the transfer of the Maryland portion of those assets. In August 2000, the Company transferred approximately 2,100 megawatts (MW) of generating assets to Allegheny Energy Supply.

 

SIGNIFICANT EVENTS IN 2000, 1999, AND 1998

 

Transfer of Generating Assets 

 

In August 2000, the Company transferred approximately 2,100 MW of its Maryland, Virginia, and West Virginia jurisdictional generating assets to Allegheny Energy Supply at net book value. State utility commissions in Maryland, Virginia, and West Virginia approved the transfer of these assets as part of deregulation proceedings in those states. The Federal Energy Regulatory Commission (FERC) and the Securities and Exchange Commission (SEC) also approved these transfers.

 

Under the terms of the deregulation plans approved in Maryland, the Company retains the obligation to provide electricity to customers that do not choose an alternative electricity supplier during a transition period. For the Company, the Standard Offer Service (provider of last resort) will be provided to Maryland residential customers during a transition period from July 1, 2000, to December 31, 2008, and to all other Maryland customers during a transition period of July 1, 2000, to December 31, 2004. See Note B to the consolidated financial statements for details regarding the deregulation plans approved in Maryland.

 

Pursuant to contracts, Allegheny Energy Supply provides the Company with power during the Maryland transition periods. Allegheny Energy Supply also provides power pursuant to contracts to cover the retail load of the Company in Virginia and West Virginia prior to and throughout the ensuing period of any retail choice programs that may be implemented in those states. Under these contracts, Allegheny Energy Supply provides the Company with the amount of electricity, up to their retail load, that they may demand.

 

On May 25, 2000, the Company filed an application with the Virginia SCC to separate its 380 MW of Virginia jurisdictional generating assets, excluding the hydroelectric assets located within the state of Virginia, from its transmission and distribution (T&D) assets, effective July 1, 2000. On July 11, 2000, the Virginia SCC issued an order approving the Company's separation plan that provided for the transfer of its Virginia jurisdictional generating assets to Allegheny Energy Supply in exchange for the aforementioned contractual commitment from Allegheny Energy Supply to provide power.

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On August 10, 2000, the Company applied to the Virginia SCC to transfer the five MW of hydroelectric assets located within the state of Virginia to Green Valley Hydro, LLC (a subsidiary of the Company). On December 14, 2000, the Virginia SCC approved the transfer. The Company anticipates the transfer to Allegheny Energy Supply will occur during the first quarter of 2001, after receiving final approval from the SEC.

 

On June 23, 2000, the W.Va. PSC issued an order regarding the transfer of the 2,004 MW of West Virginia jurisdictional generating assets of Monongahela Power Company (Monongahela Power), an affiliate of the Company, as well as the generating assets of the Company that serve West Virginia. The Company was granted approval to transfer its assets to Allegheny Energy Supply to be consolidated with other generating assets of the Company so transferred. In part, Monongahela Power is required to file with the W.Va. PSC a petition seeking a Commission finding that a proposed transfer of generating assets complies with the conditions of the deregulation plan. The order also permits Monongahela Power to submit a petition to the Commission seeking approval to transfer its West Virginia jurisdictional generating assets prior to the implementation of the deregulation plan. Monongahela Power is required to make a filing before the implementation of the deregulation plan to include commitments to the consumer and other protections contained in the deregulation plan.

 

See Notes B and C to the consolidated financial statements for details of various state restructurings and information regarding the electric generation deregulation process.

 

Rate Matters 

 

The Company and its affiliates, Monongahela Power and West Penn Power Company (West Penn), collectively doing business as Allegheny Power, operate electric transmission and electric and natural gas distribution systems. Allegheny Power also generates electric energy in jurisdictions which have not yet deregulated electric generation. These subsidiaries are subject to federal and state regulation, including the Public Utility Holding Company Act of 1935 (PUHCA). Allegheny Power's markets for regulated electric and gas retail sales are in Maryland, Ohio, Pennsylvania, Virginia, and West Virginia.

 

In connection with regulatory proceedings of the Maryland PSC, the Company decreased the fuel portion of Maryland customers' bills by approximately $6.4 million annually, effective with bills rendered on or after December 7, 1999. A proposed order was issued on February 18, 2000, granting the requested decrease in the Company's fuel rate, and, on March 21, 2000, the proposed order became final. Effective July 1, 2000, coincident with customer choice in Maryland, the fuel rates were rolled into base rates.

 

On March 24, 2000, the Maryland PSC issued an order requiring the Company to refund the 1999 deferred fuel balance overrecovery of approximately $9.9 million to customers over a period of 12 months that began April 30, 2000. The refund of the overrecovered balance does not affect the Company's earnings since the overrecovered amounts had been deferred.

 

On October 4, 2000, the Maryland PSC approved the Company's filing, which represents the final reconciliation of its deferred fuel balance. The Company is refunding to customers a $3.2 million overrecovery balance existing in the Maryland deferred fuel account as of September 30, 2000. The deferred fuel credit to customers began in October 2000 and will be effective until the balance falls to zero, which is projected to take 12 months. The refund of the overrecovered balance does not affect the Company's earnings, since the overrecovered amounts had been deferred.

 

On June 23, 2000, the W.Va. PSC approved a Joint Stipulation and Agreement for Settlement, stating agreed-upon rates designed to make the rates of the Company and Monongahela Power consistent. Under the terms of the settlement, several tariff schedules, notably those available to residential and small commercial customers, will require several incremental steps to reach the agreed-upon rate level. The settlement rates resulted in a revenue increase for the Company of approximately $0.2 million for 2000, increasing over eight years to an annual increase of approximately $4.3 million. The settlement approved by the W.Va. PSC directs the Company to amortize the existing overcollected deferred fuel balance as of June 30, 2000 (approximately $10.0 million), as a reduction of expenses over a four-and-one-half year period beginning July 1, 2000. Also, effective July 1, 2000, the Company ceased their expanded net energy cost (fuel clause) as part of the settlement.

 

On November 29, 2000, the Maryland PSC approved a Power Sales Agreement between the Company and the winning bidder covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2001, through December 31, 2001. The AES Warrior Run cogeneration project was developed under the Public Utility Regulatory Policies Act of 1978 (PURPA) and achieved commercial operation on February 10, 2000. Under the terms of the Maryland deregulation plan approved in 1999, the revenues from the sale of the AES Warrior Run output are used to offset the capacity and energy costs the Company pays to the AES Warrior Run cogeneration project before determining amounts to be recovered from Maryland customers.

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Effective with bills rendered on or after January 8, 2001, there was an increase in Maryland base rates as a result of the phase-in of the rate increase approved by the Maryland PSC on October 27, 1998. A settlement agreement, which includes recognition and dollar-for-dollar recovery of costs to be incurred from the AES Warrior Run project, was filed with the Maryland PSC on July 30, 1998, and approved by that Commission on October 27, 1998. The Maryland PSC approved rates for each customer class on December 22, 1998. Under the terms of the agreement, the Company increased its rates about four percent in each of the years 1999 and 2000, and will increase rates by about four percent in 2001 (a $79 million total revenue increase during 1999 through 2001). The increases are designed to recover additional costs of about $131 million over the period 1999-2001 for capacity purchases from the AES Warrior Run project net of alleged overearnings of $52 million for the same period. The agreement also requires that the Company share 50 percent of earnings above an 11.4 percent return on equity with customers for 1999 and 2000. As a result, 50 percent of the amount above the threshold earnings amount, or $9.7 million applicable to 1999, is being distributed to customers in the form of an Earnings Sharing Credit, effective June 7, 2000, through April 30, 2001. Any sharing of earnings required for 2000 will be reflected as a credit on customers' bills starting in May 2001 .

 

Regional Transmission Organization

 

In adopting its Rule 2000, the FERC defined requirements for transmission facility owners, such as Allegheny Power, to participate in some form of a regional transmission organization (RTO). Additionally, the state jurisdictions within which the Allegheny Power operates have, to different degrees, started to define their transition to a competitive generation marketplace. As part of this, they have identified transmission as a key link to making the electricity market efficient.

 

Allegheny Power announced on October 5, 2000, that it had signed a Memorandum of Agreement with PJM to develop a new transmission affiliation with Pennsylvania - New Jersey - Maryland Interconnection, LLC (PJM), referred to as PJM West. The Memorandum of Agreement was outlined in a filing submitted to the FERC on October 16, 2000, in order to meet the requirements of FERC's Order 2000.

 

FERC's Order 2000 required all electric utilities, not currently in an independent system operator (ISO), to file a plan on how they would participate in an RTO, those entities that oversee and control the power grid. Although PJM is an ISO, Allegheny Power will not join PJM, but will pursue the development of an affiliation with PJM, working within the PJM framework, which would also be available to other utilities.

 

Allegheny Power is leading the new initiative, known as PJM West, which will facilitate economic transmission service, while simultaneously expanding the PJM market.

 

In December 2000, Allegheny Power and PJM announced the execution of an agreement in principle to broaden PJM West that will further expand the PJM market into the Pittsburgh area. This agreement provides for Duquesne Light Company to join Allegheny Power in the development of PJM West by executing a similar joint agreement with PJM as did Allegheny Power.

 

Recapitalization

 

On September 30, 1999, the Company called $16.4 million of preferred stock. In April 2000, the Company's shareholders amended its Articles of Incorporation. Prior to the amendment and restatement, the Company was authorized to issue 23, 000,000 shares of common stock without par value and 5,378,611 shares of preferred stock with $100 par value per share. The Company now has authority to issue 26,000,000 shares of common stock with $.01 par value per share and 10,000,000 shares of preferred stock with $.01 par value per share. As a result of the change in par value, the Company's common stock was reduced and other paid-in capital was increased by $447.5 million.

 

PURPA Power Project Termination

 

In 1999, the Company settled for $2.7 million litigation by a developer alleging failure by the Company to comply with PURPA regulations.

 

Electric Industry Restructuring

 

See Electric Energy Competition on page 13 for more information regarding electric energy restructuring activities.

M-37

 

REVIEW OF OPERATIONS

Earnings Summary

 

Earnings

(Millions of Dollars)

2000

1999

1998

       

Operations

$ 84.4

$100.6

$101.5

Extraordinary charge, net (Notes B

     

and C to the consolidated financial

     

statements)

(13.9)

(17.0)

            

Consolidated Net Income

$ 70.5

$ 83.6

$101.5

Earnings for 2000, before the extraordinary charge, decreased by $16.2 million primarily due to the August 1, 2000, transfer of the Company's 2,100 MW of generating capacity at net book value to Allegheny Energy Supply, an unregulated who