Annual Reports

 
Quarterly Reports

 
8-K

 
Other

Allegheny Energy 10-K 2007
Form 10-K

LOGO

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


FORM 10-K

 


FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

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

OR

 

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

 

Commission

File Number

  

Registrant;

State of Incorporation;

Address; and Telephone Number

 

I.R.S. Employer

Identification Number

1-267

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

1-5164

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

0-14688

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

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

 

Allegheny Energy, Inc.

   Yes  x    No  ¨

Monongahela Power Company

   Yes  ¨    No  x

Allegheny Generating Company

   Yes  ¨    No  x


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

 

Allegheny Energy, Inc.

   ¨  

Monongahela Power Company

   ¨  

Allegheny Generating Company

   ¨  

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

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

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

 

     Large accelerated filer    Accelerated filer    Non-accelerated filer

Allegheny Energy, Inc.  

   x    ¨    ¨

Monongahela Power Company

   ¨    ¨    x

Allegheny Generating Company

   ¨    ¨    x

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

 

Allegheny Energy, Inc.

   Yes  ¨    No  x

Monongahela Power Company

   Yes  ¨    No  x

Allegheny Generating Company

   Yes  ¨    No  x

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

 

Registrant

  

Title of each class

  

Name of each exchange

on which registered

Allegheny Energy, Inc.

  

Common Stock,
$1.25 par value

   New York Stock Exchange
Chicago Stock Exchange

Monongahela Power Company

  

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

   American Stock Exchange
American Stock Exchange

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

Allegheny Generating Company

  

Common Stock,
$1.00 par value

   None

 


     

Aggregate market value of

voting and non-voting common

equity held by nonaffiliates of

the registrants at June 30, 2006

  

Number of shares of common stock

of the registrants outstanding at

February 20, 2007

Allegheny Energy, Inc.  

   $6,095,989,273    164,445,354 ($1.25 par value)

Monongahela Power Company

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

Allegheny Generating Company

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

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

Documents Incorporated by Reference

Portions of the Allegheny Energy, Inc. definitive Proxy Statement for its 2007 Annual Meeting of Stockholders are incorporated by reference to Part III of this Annual Report on Form 10-K.

 



GLOSSARY

 

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

 

ACC

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

AE

   Allegheny Energy, Inc., a diversified utility holding company

AESC

   Allegheny Energy Service Corporation, a subsidiary of AE

AE Solutions

   Allegheny Energy Solutions, Inc., a subsidiary of Allegheny Ventures

AE Supply

   Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE

AGC

   Allegheny Generating Company, an unregulated generation subsidiary of AE Supply and Monongahela

Allegheny

   Allegheny Energy, Inc., together with its consolidated subsidiaries

Allegheny Ventures

   Allegheny Ventures, Inc., a nonutility, unregulated subsidiary of AE

Distribution Companies

   Collectively, Monongahela, Potomac Edison and West Penn, which do business as Allegheny Power

Green Valley Hydro

   Green Valley Hydro, LLC, a subsidiary of AE

Monongahela

   Monongahela Power Company, a regulated subsidiary of AE

Potomac Edison

   The Potomac Edison Company, a regulated subsidiary of AE

Registrants

   Collectively, AE, Monongahela and AGC

TrAIL Company

   Trans-Allegheny Interstate Line Company

West Penn

   West Penn Power Company, a regulated subsidiary of AE

 

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

 

BTU

   British Thermal Unit

CDD

   Cooling Degree-Days

CDWR

   California Department of Water Resources

Clean Air Act

   Clean Air Act of 1970

DOE

   United States Department of Energy

EPA

   United States Environmental Protection Agency

Energy Policy Act

   Energy Policy Act of 2005

Exchange Act

   Securities Exchange Act of 1934, as amended

FERC

   Federal Energy Regulatory Commission, an independent commission within the DOE

FPA

   Federal Power Act

GAAP

   Generally accepted accounting principles used in the United States of America

HDD

   Heating Degree-Days

KW

   Kilowatt, which is equal to 1,000 watts

kWh

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

Maryland PSC

   Maryland Public Service Commission

MW

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

MWh

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

NSR

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

OVEC

   Ohio Valley Electric Corporation

Pennsylvania PUC

   Pennsylvania Public Utility Commission

PJM

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

PLR

   Provider-of-last-resort

PURPA

   Public Utility Regulatory Policies Act of 1978

RTO

   Regional Transmission Organization

SEC

   Securities and Exchange Commission

SOS

   Standard Offer Service

T&D

   Transmission and distribution

Virginia SCC

   Virginia State Corporate Commission

West Virginia PSC

   Public Service Commission of West Virginia


LOGO


CONTENTS

 

Item 1.

 

Business

  6
 

Overview

  6
 

Special Note Regarding Forward-Looking Statements

  14
 

Allegheny’s Sales And Revenues

  16
 

Capital Expenditures

  17
 

Electric Facilities

  18
 

Fuel, Power And Resource Supply

  23
 

Regulatory Framework Affecting Allegheny

  26
 

Federal Regulation And Rate Matters

  26
 

Environmental Matters

  36
 

Employees

  41
 

Executive Officers Of The Registrants

  42

Item 1A.

 

Risk Factors

  43

Item 2.

 

Properties

  53

Item 3.

 

Legal Proceedings

  54

Item 4.

 

Submission Of Matters To A Vote Of Security Holders

  56

Item 5.

 

Market For The Registrants’ Common Equity And Related Stockholder Matters

  57

Item 6.

 

Selected Financial Data

  59

Item 7.

 

Management’s Discussion And Analysis Of Financial Condition And Results Of Operations

  62

Item 7A.

 

Quantitative And Qualitative Disclosures About Market Risk

  122

Item 8.

 

Financial Statements And Supplementary Data

  125

Item 9.

 

Changes In And Disagreements With Accountants On Accounting And Financial Disclosure

  243

Item 9A.

 

Controls And Procedures

  243

Item 9B.

 

Other Information

  244

Item 10.

 

Directors And Executive Officers Of The Registrants

  245

Item 11.

 

Executive Compensation

  245

Item 12.

 

Security Ownership Of Certain Beneficial Owners And Management And Related Stockholder Matters

  245

Item 13.

 

Certain Relationships And Related Transactions

  245

Item 14.

 

Principal Accountant Fees And Services

  245

Item 15.

 

Exhibits And Financial Statement Schedules

  246

Supplemental Information To Be Furnished With Reports Filed Pursuant To Section 15(d) Of The Exchange Act By Registrants Which Have Not Registered Securities Pursuant To Section 12 Of The Exchange Act

  246

Signatures

  247


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

PART I

ITEM 1.    BUSINESS

OVERVIEW

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

Allegheny has two business segments:

 

   

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

 

   

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

The Delivery and Services Segment

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

 

   

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

 

   

Monongahela was incorporated in Ohio in 1924. It conducts an electric T&D business that serves approximately 375,000 customers in northern West Virginia in a service area of approximately 12,400 square miles with a population of approximately 776,000. Monongahela’s Delivery and Services segment had operating revenues of $674.9 million and sold 10,351 million kWhs of electricity to retail customers in 2006. Monongahela also owns generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below. Monongahela conducted electric T&D operations in Ohio and natural gas T&D operations in West Virginia until it sold the assets related to these operations on December 31, 2005 and September 30, 2005, respectively. Monongahela agreed to sell power at a fixed price to Columbus Southern Power Company (“Columbus Southern”), the purchaser of its electric T&D operations in Ohio, to serve Monongahela’s former Ohio customers until May 31, 2007. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Asset Sales” below.

 

   

Potomac Edison was incorporated in Maryland in 1923 and was also incorporated in Virginia in 1974. It operates an electric T&D system in portions of West Virginia, Maryland and Virginia. Potomac Edison serves approximately 466,600 customers in a service area of about 7,300 square miles with a population of approximately 1.02 million. Potomac Edison had total operating revenues of $856.0 million and sold 12,902 million kWhs of electricity to retail customers in 2006.

 

   

West Penn was incorporated in Pennsylvania in 1916. It operates an electric T&D system in southwestern, south-central and northern Pennsylvania. West Penn serves approximately 707,000

 

6


 

customers in a service area of about 9,900 square miles with a population of approximately 1.5 million. West Penn had total operating revenues of $1,210.5 million and sold 19,926 million kWhs of electricity to retail customers in 2006.

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

 

   

TrAIL Company was incorporated in Maryland and Virginia in 2006 following PJM’s approval of a regional transmission expansion plan designed to maintain the reliability of the transmission grid in the Mid-Atlantic region. The transmission expansion plan includes a new, 240-mile 500 kV transmission line, 210 miles of which is to be located in the Distribution Companies’ PJM zone. PJM designated Allegheny to construct the portion of the line that will be located in the Distribution Companies’ PJM zone. TrAIL Company was formed in connection with the management and financing of transmission expansion projects, including this project (the “TrAIL Project”), and will own and operate the new transmission line.

 

   

Allegheny Ventures is a nonutility, unregulated subsidiary of AE that was incorporated in Delaware in 1994. Allegheny Ventures engages in telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal wholly-owned subsidiaries, ACC and AE Solutions. Both ACC and AE Solutions are Delaware corporations. ACC develops fiber-optic projects, including fiber and data services. AE Solutions manages energy-related projects. Allegheny Ventures had total operating revenues of $6.6 million in 2006.

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

The Generation and Marketing Segment

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

 

   

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

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

 

   

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

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

 

7


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

 

   

AGC was incorporated in Virginia in 1981. As of December 31, 2006, AGC was owned approximately 77% by AE Supply and approximately 23% by Monongahela. As a result of the Asset Swap, AGC currently is owned approximately 59% by AE Supply and approximately 41% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,035 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC had total operating revenues of $65.3 million in 2006. See “Electric Facilities” below.

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

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

Intersegment Services

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

The Distribution Companies’ Obligations and the PJM Market

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

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

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

 

   

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

 

8


 

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

 

   

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

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

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

All of Allegheny’s generation facilities are located within the PJM market, and all of the power that the Generation and Marketing segment generates is sold into the PJM market. To facilitate the economic dispatch of generation, AE Supply and Monongahela sell the power that they generate into the PJM market and purchase from the PJM market the power necessary to meet their obligations to supply power.

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

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

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

Initiatives and Achievements

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

Significant initiatives and recent achievements include:

 

   

Pursuing Transmission Expansion.  In June 2006, PJM approved a regional transmission expansion plan designed to maintain the reliability of the transmission grid in the Mid-Atlantic region that includes

 

9


 

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

 

   

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

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

 

   

Managing Transition to Market-based Rates.  In 2005, Allegheny successfully implemented a plan to transition Pennsylvania customers to generation rates based on market prices through increases in applicable rate caps in 2007, 2009 and 2010 and a two-year extension of the applicable transition period. Together with previously approved rate cap increases for 2006 and 2008, these increases will gradually move generation rates in Pennsylvania closer to market prices.

Allegheny is actively working to effectively manage a similar transition in Maryland. In December 2006, Allegheny filed a proposal with the Maryland PSC to transition residential customers from capped generation rates to generation rates based on market prices beginning in 2007 and ending in 2010. Under the proposed plan, residential customers would pay a distribution surcharge beginning on March 31, 2007. The proposed plan, including the application of the surcharge, would result in an overall rate increase of approximately 15% annually from 2007 to 2010. With the expiration of the residential generation rate caps and the move to generation rates based on market prices on January 1, 2009, the surcharge would convert to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, would be returned to customers as a credit on their electric bills, thereby reducing the effect of the rate cap expiration. The credit would continue, with adjustments, to maintain rate stability until December 31, 2010. Following public hearings, Allegheny filed an alternate proposal that would, among other things, provide customers with the ability to opt out of the surcharge. See “Regulatory Framework Affecting Allegheny” and “Fuel, Power and Resource Supply” below.

 

   

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

 

10


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

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

 

   

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

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

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

Additionally, Allegheny has entered into various coal supply contracts in an effort to ensure a consistent supply of coal at predictable prices, and currently has contracts in place for the delivery of approximately 96% of its expected coal needs for 2007. See “Fuel, Power and Resource Supply” below.

 

   

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

 

   

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

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

 

   

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

 

   

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

 

11


 

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

 

   

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

 

   

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

 

   

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

 

   

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

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

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

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

 

12


Where You Can Find More Information

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

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

 

13


SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

 

   

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

 

   

financing plans;

 

   

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

 

   

PLR and power supply contracts;

 

   

results of litigation;

 

   

results of operations;

 

   

internal controls and procedures;

 

   

capital expenditures;

 

   

status and condition of plants and equipment;

 

   

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

 

   

work stoppages by Allegheny’s unionized employees;

 

   

capacity purchase commitments; and

 

   

regulatory matters.

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

 

   

plant performance and unplanned outages;

 

   

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

 

   

general economic and business conditions;

 

   

changes in access to capital markets;

 

   

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

 

   

environmental regulations;

 

   

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

 

   

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

 

   

changes in the weather and other natural phenomena;

 

   

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

 

   

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

 

   

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

 

14


   

the loss of any significant customers or suppliers;

 

   

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

 

   

inflationary and interest rate trends;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

the continuing effects of global instability, terrorism and war.

 

15


ALLEGHENY’S SALES AND REVENUES

Generation and Marketing

The Generation and Marketing segment had operating revenues of $1,834.4 million and $1,703.3 million in 2006 and 2005, respectively. For more information regarding the Generation and Marketing segment’s operating revenues, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below and Note 9, “Business Segments,” to the Consolidated Financial Statements.

Delivery and Services

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

 

Revenues (in millions):

   2006    2005

Retail electric:

     

Generation

   $ 1,688.0    $ 1,783.9

Transmission

     160.3      176.0

Distribution

     682.8      711.0
             

Subtotal retail

   $ 2,531.1    $ 2,670.9
             

Transmission services and bulk power

     150.7      115.9

Other affiliated and nonaffiliated energy services

     35.9      58.7
             

Total Delivery and Services revenues

   $ 2,717.7    $ 2,845.5
             

Allegheny had operating revenues from discontinued operations of $218.5 million for the year ended December 31, 2005. These revenues primarily related to its natural gas T&D business in West Virginia, which was sold on September 30, 2005. Allegheny did not have any operating revenues from discontinued operations in 2006. For more information regarding the Delivery and Services segment’s revenues, see “Management’s Discussion and Analysis of Financial Condition and Operating Results” below and Note 9, “Business Segments,” to the Consolidated Financial Statements.

 

16


CAPITAL EXPENDITURES

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

Allegheny Consolidated Totals

 

     Actual    Projected

(In millions)

       2006        2007    2008

Transmission and distribution facilities:

        

Transmission expansion (a)

     3      90      240

Other transmission and distribution facilities

     197      215      215

Environmental:

        

Fort Martin Scrubbers (b)

     9      150      260

Hatfield Scrubbers (c)

     64      390      285

Other

     65      75      75

Other generation facilities

     71      90      40

Other capital expenditures

     38      20      5
                    

Total capital expenditures

   $ 447    $ 1,030    $ 1,120
                    

AFUDC and capitalized interest included above

   $ 12    $ 30    $ 50
                    

Monongahela

 

     Actual    Projected

(In millions)

   2006    2007    2008

Transmission and distribution facilities

   $ 50    $ 55    $ 60

Environmental:

        

Fort Martin Scrubbers (b)

     9      150      260

Other

     14      20      15

Other generation facilities

     15      30      20

Other capital expenditures

     3      5      —  
                    

Total capital expenditures

   $ 91    $ 260    $ 355
                    

AFUDC and capitalized interest included above

   $ 2    $ 5    $ 5
                    

AGC

 

     Actual    Projected

(In millions)

   2006    2007    2008

Generation facilities and other

   $ 4    $ 7    $ 5
                    

(a) Includes construction of the TrAIL Project, which has a target completion date of 2011 and estimated total cost of approximately $820 million, as well as other transmission projects requested by PJM.
(b) Construction of Scrubbers at the Fort Martin generation facility is expected to be completed during 2009 at an estimated total cost of approximately $550 million, excluding AFUDC of $5 million. Allegheny plans to fund $450 million of these costs through securitization of an environmental control surcharge to be collected from the West Virginia customers of Monongahela and Potomac Edison.
(c) Construction of Scrubbers at the Hatfield’s Ferry generating facility is expected to be completed during 2009 at an estimated total cost of approximately $725 million, excluding capitalized interest of $60 million.

 

17


ELECTRIC FACILITIES

Generation Capacity

All of Allegheny’s owned or controlled generation capacity is part of the Generation and Marketing segment. Allegheny’s owned and controlled capacity as of January 1, 2007 was 9,670 MWs, of which 7,604 MWs (78.6%) were coal-fired, 891 MWs (9.2%) were natural gas-fired, 1,093 MWs (11.3%) were pumped-storage and hydroelectric and 82 MWs (0.8%) were oil-fired. The Distribution Companies are obligated to purchase 479 MWs of power through state utility commission-approved arrangements pursuant to PURPA. This PURPA capacity is part of the Delivery and Services segment, except that, effective January 1, 2007, the PURPA capacity for which Monongahela contracts is part of the Generation and Marketing segment. Allegheny’s generation capacity is more fully described in the tables titled “Nominal Maximum Operational Generation Capacity” and “PURPA Capacity” below.

2006 Capacity Acquisitions and Dispositions

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

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

Asset Swap and Proposed Securitization

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

As a result of the Asset Swap, Monongahela also owns 100% of the Albright, Rivesville and Willow Island generation facilities in West Virginia. In addition, Monongahela is contractually entitled to a greater proportion of the generation (189 additional MWs) from the Bath County, Virginia generation facility. Also as a result of the Asset Swap, AE Supply owns 100% of the Hatfield’s Ferry generation facility in Pennsylvania, which prior to the Asset Swap was jointly owned by AE Supply and Monongahela, and has a greater ownership interest in the Harrison and Pleasants generation facilities in West Virginia, for an additional 13 MWs and 176 MWs, respectively. AE Supply also has contractual rights to a greater amount of generation from OVEC. In addition, AE Supply assigned to Monongahela the obligation to supply the generation to meet Potomac Edison’s load obligations in West Virginia.

 

18


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

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

Nominal Maximum Operational Generation Capacity (MW)

 

     Units   

Project

Total

   Regulated    Unregulated   

Service

Commencement

Dates (a)

Stations

         Monongahela    AE Supply and Other   

Coal Fired-Supercritical (Steam):

              

Harrison (Haywood, WV)

   3    1,972    405    1,567    1972-74

Hatfield’s Ferry (Masontown, PA)

   3    1,710       1,710    1969-71

Pleasants (Willow Island, WV)

   2    1,300    100    1,200    1979-80

Fort Martin (Maidsville, WV)

   2    1,107    1,107       1967-68

Coal Fired-Other (Steam):

              

Armstrong (Adrian, PA)

   2    356       356    1958-59

Albright (Albright, WV)

   3    292    292       1952-54

Mitchell (Courtney, PA)

   1    288       288    1963

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

   11    78    78      

Willow Island (Willow Island, WV)

   2    243    243       1949-60

Rivesville (Rivesville, WV)

   2    142    142       1943-51

R. Paul Smith (Williamsport, MD)

   2    116       116    1947-58

Pumped-Storage and Hydro:

              

Bath County (Warm Springs, VA) (c)

   6    1,035    427    608    1985; 2001

Lake Lynn (Lake Lynn, PA) (d)

   4    52       52    1926

Green Valley Hydro (e)

   21    6       6    Various

Gas-Fired:

              

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

   3    540       540    2003

AE Nos. 1 & 2 (Springdale, PA)

   2    88       88    1999

AE Nos. 8 & 9 (Gans, PA)

   2    88       88    2000

AE Nos. 12 & 13 (Chambersburg, PA)

   2    88       88    2001

Buchanan (Oakwood, VA) (f)

   2    43       43    2002

Hunlock CT (Hunlock Creek, PA)

   1    44       44    2000

Oil-Fired (Steam):

              

Mitchell (Courtney, PA)

   1    82       82    1949
                    

Total Capacity

      9,670    2,794    6,876   
                    

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

This figure represents capacity entitlement through AE’s ownership of OVEC shares. AE holds a 3.5% equity stake in, and is a sponsoring company of, OVEC. OVEC supplies power to its sponsoring companies under an intercompany power agreement. Currently, as a result of AE’s equity interest, Monongahela is

 

19


 

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

(c) This figure represents capacity entitlement through ownership of AGC.
(d) AE Supply has a license for Lake Lynn through 2024.
(e) Green Valley Hydro’s license for hydroelectric facilities Dam No. 4 and Dam No. 5, located in West Virginia and Maryland will expire November 30, 2024. Potomac Edison has licenses through 2024 for the Shenandoah, Warren, Luray and Newport projects located in Virginia.
(f) Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply (“Buchanan”), is part-owner of Buchanan Generation LLC (“Buchanan Generation”). CNX Gas Corporation and Buchanan have equal ownership interests in Buchanan Generation. AE Supply operates and dispatches 100% of Buchanan Generation’s 86 MWs.

PURPA Capacity

The following table shows additional generation capacity available to the Distribution Companies through state utility commission-approved arrangements pursuant to PURPA. PURPA requires electric utility companies, such as the Distribution Companies, to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities. The amounts shown in this table are included in the Delivery and Services segment, except that, effective January 1, 2007, the PURPA generation for which Monongahela contracts is part of the Generation and Marketing segment.

 

PURPA Stations

  

Project

Total

   Monongahela   

Potomac

Edison

  

West

Penn

  

PURPA

Contract

Termination

Date

Coal-Fired: Steam

              

AES Warrior Run (Cumberland, MD) (a)

   180       180       02/10/2030

AES Beaver Valley (Monaca, PA)

   125          125    12/31/2016

Grant Town (Grant Town, WV)

   80    80          05/28/2036

West Virginia University (Morgantown, WV)

   50    50          04/17/2027

Hydro:

              

Hannibal Lock and Dam (New Martinsville, WV)

   31    31          06/01/2034

Allegheny Lock and Dam 6 (Freeport, PA)

   7          7    06/30/2034

Allegheny Lock and Dam 5 (Freeport, PA)

   6          6    09/30/2034
                      

Total PURPA Capacity

   479    161    180    138   
                      

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

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

 

20


The following table sets forth the existing miles of T&D lines and the number of substations of the Distribution Companies and AGC as of December 31, 2006:

 

     Underground   

Above-

Ground

  

Total

Miles

  

Total Miles

Consisting of

500-Kilovolt

(kV) Lines

  

Number of

Transmission and

Distribution
Substations

Monongahela

   758    22,312    23,070    246    343

Potomac Edison

   4,983    18,098    23,081    178    188

West Penn

   2,782    24,198    26,980    276    595

AGC (a)

   0    87    87    87    1
                        

Total

   8,523    64,695    73,218    787    1,127
                        

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

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

 

21


LOGO

 

22


FUEL, POWER AND RESOURCE SUPPLY

Generation and Marketing Segment

Coal Supply

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

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

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

Natural Gas Supply

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

Natural Gas Transportation Contracts

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

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

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

 

23


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

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

The Delivery and Services Segment

Electric Power

Allegheny reorganized its corporate structure in response to electric utility deregulation within its service area between 1999 and 2001. The Distribution Companies, with the exception of Monongahela and its West Virginia generation assets, do not produce their own power. Potomac Edison transferred all of its generation assets to AE Supply in 2000. West Penn transferred all of its generation assets to AE Supply in 1999. Monongahela transferred the portion of its generation assets dedicated to its previously-owned Ohio service territory to AE Supply in 2001. The Asset Swap realigned ownership of certain generation facilities between Monongahela and AE Supply, effective as of January 1, 2007. See “Electric Facilities” above.

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

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

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

When existing power sales agreements terminate, Potomac Edison and West Penn will be unable to rely on the previously dedicated supply of power at specified contract prices to meet their respective power supply requirements. The arrangements to serve the applicable PLR obligations following the expiration of these

 

24


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

 

Distribution

Company

   State   

Expiration Date of

Power Sale Agreement(a)

Potomac Edison

   Maryland    December 31, 2008

Potomac Edison

   Virginia    June 30, 2007

Potomac Edison

   West Virginia    January 1, 2027

West Penn

   Pennsylvania    December 31, 2010

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

To facilitate the economic dispatch of its generation, Monongahela sells the power that it generates from its West Virginia jurisdictional assets into the PJM market and purchases from the PJM market the power necessary to meet its West Virginia jurisdictional customer load and contractual obligations to provide power.

 

25


REGULATORY FRAMEWORK AFFECTING ALLEGHENY

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

Federal Regulation and Rate Matters

FERC, Competition and RTOs

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

FERC Authority Under the Federal Power Act

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

 

   

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

 

   

the development, operation and maintenance of hydroelectricity projects;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

the reliability of the transmission grid;

 

   

the siting of certain transmission facilities;

 

   

the allocation of transmission rights;

 

   

the types of incentives available to encourage new transmission investment;

 

   

the transparency of power sales prices and market manipulation;

 

   

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

 

   

the holding of interlocking positions by directors and officers of public utilities.

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

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

 

26


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

Competition and RTOs

Over the past decade, FERC has taken a number of steps to foster increased competition within the electric industry. Among other things, FERC requires public utilities that own transmission facilities to offer non-discriminatory, open-access transmission services. In addition, FERC has imposed standards of conduct governing communications between employees conducting transmission functions and employees engaged in wholesale power sale activities. These standards of conduct are intended to prevent transmission-owning utilities from giving their power marketing businesses preferential access to the transmission system and transmission information. FERC also has taken steps to encourage utilities to participate in RTOs, such as PJM, by transferring functional control over their transmission assets to RTOs.

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

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

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

FERC actions with respect to the transmission rate design within PJM may impact the Distribution Companies. Beginning in July 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for these regions. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others. FERC concluded that neither the rate design proposals, nor the existing PJM rate design, had been shown to be just and reasonable. However, FERC ordered the continuation of the existing PJM rate design and the implementation of a transition charge for these regions through March 31, 2006 through filings made by transmission owners in both regions. In February 2005, FERC accepted these transition charges, effective December 1, 2004, subject to an evidentiary hearing. FERC’s February 2005 order remains subject to multiple rehearing requests and, potentially, appellate review. Allegheny cannot predict the outcome of these proceedings or whether they will have a material impact on its business or financial position.

During the now-expired transition period, the Distribution Companies were both payers and payees of transition charges. These charges resulted in the payment by the Distribution Companies of $13.7 million, and

 

27


payments to the Distribution Companies of $4.8 million, for the 16-month period ended March 31, 2006. Following the evidentiary hearing, on August 10, 2006, an administrative law judge issued an initial decision that generally found fault with the methodologies used to develop the transition charges. That decision is now subject to review by FERC. The order that will be issued by FERC on review of the initial decision may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of increases in the transition charges previously billed to them, or they may receive refunds of transition charges previously billed. Allegheny cannot predict the outcome of these proceedings. The Distribution Companies have entered into nine partial settlements with regard to the transition charges, and may enter into additional settlements in the future. FERC has approved two of these settlements, and approval is pending for the remaining partial settlements.

In a May 2005 order, FERC again determined that the existing PJM rate design may not be just and reasonable. On September 30, 2005, the Distribution Companies, together with another PJM transmission owner, filed a proposed rate design with FERC to replace the existing rate design within PJM, effective April 1, 2006. Two other PJM transmission owners also filed a separate proposed rate design. A hearing was held in April 2006 to determine whether the rate design is unjust and unreasonable and whether it should be replaced by either of the proposed rate designs. An initial decision was issued on July 13, 2006 by an administrative law judge, finding that the existing PJM rate design for existing transmission facilities is not just and reasonable. The administrative law judge found that the rate design for existing transmission facilities proposed by Allegheny is just and reasonable, but ruled that the rate design proposed by FERC staff is also just and reasonable, is superior and should be made effective as of April 1, 2006. The initial decision also found that the Distribution Companies’ proposal for rate recovery for new transmission facilities had not demonstrated that the existing rate recovery mechanism for such facilities is unjust and unreasonable but adopted the Distribution Companies’ position that the implementation of a new rate design does not necessitate a change in the allocation of auction revenue rights and financial transmission rights. The initial decision will not become effective until acted upon by FERC, which may accept, modify or reject the initial decision.

In August 2005, PJM filed at FERC to replace the current capacity market with a new Reliability Pricing Model (“RPM”) to address reliability concerns. On April 20, 2006, FERC issued an initial order that found PJM’s current capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that must be analyzed further before it can determine whether the RPM is a just and reasonable capacity market process. FERC ordered the implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies participated in a settlement agreement that was filed with the FERC on September 29, 2006. The settlement agreement would create a locational capacity market in PJM, in which PJM would procure needed capacity resources through auctions held three years in advance at prices and in quantities determined by an administratively established demand curve. Under the settlement agreement, capacity needs in PJM will be met either through purchases made in the proposed auctions or though commitments by load serving entities to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which will begin with the 2007-2008 PJM planning year.

On July 3, 2006, PJM filed at FERC a proposal to implement a process for allocating long-term transmission rights (“LTTRs”). The PJM proposal would allocate a ten-year financial transmission right to PJM load serving entities (“LSEs”) based on the LSEs’ zonal base load. The PJM proposal created a link between PJM’s long-term transmission planning process and the LTTR allocation process to ensure that the transmission system is being upgraded as necessary to maintain the availability of the LTTRs that PJM will allocate. On November 22, 2006, FERC issued an Order accepting PJM’s proposal, subject to modifications. On January 22, 2007, PJM filed a related settlement agreement, as well as a proposal to allocate any costs to fund LTTRs fully to holders of financial transmission rights on a pro-rata basis. PJM recommended the creation of a new stakeholder process to determine whether this full funding mechanism should be changed subsequent to the 2007-2008 PJM planning year.

 

28


Transmission Expansion

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

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

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

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

PURPA

The Energy Policy Act amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contract obligation to purchase energy from a qualifying facility if FERC finds that the facility has non-discriminatory access to a functioning wholesale market and open access transmission. In February 2006, FERC finalized regulations that eliminate ownership restrictions for both new and existing facilities. A qualifying facility may now be owned by a traditional utility. The new rule also ensures that the thermal output of cogeneration facilities is used in a productive and beneficial manner.

 

29


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

State Rate Regulation

Pennsylvania

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

Joint Petition and Extension of Generation Rate Caps

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

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

Stranded Cost Securitizations

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

Power Purchase Agreement

West Penn has long-term power purchase agreements with AE Supply to provide West Penn with the amount of electricity necessary to meet the majority of its PLR retail obligations during the Pennsylvania transition period. According to the terms of the amended Joint Petition described above, a Request for Proposal for full requirements wholesale electric power supply to serve load in 2009 and 2010 was issued May 31, 2005. AE Supply was the successful bidder and was awarded the contract on July 21, 2005. AE Supply filed a request with the FERC for authority to make these wholesale power sales, which FERC granted on October 25, 2005.

 

30


Other Pennsylvania PUC Matters

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

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

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

In May 2004, the Pennsylvania PUC modified its utility specific benchmarks and performance standards for electric distribution system reliability. The benchmarks were set too low for West Penn, resulting in required reliability levels that were unattainable. West Penn appealed the benchmarks to the Pennsylvania PUC. In 2005, the parties to the proceeding, including the Consumer Advocate, the Utility Workers Union of America Local 102, and the Rural Electric Association entered into an agreement settling the proceeding and providing West Penn with attainable reliability benchmarks. The Pennsylvania PUC approved the settlement in an Order issued July 27, 2006.

West Virginia

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

Proposed Securitization and Scrubber Project

On May 4, 2005, the state of West Virginia adopted legislation permitting securitization financing for the construction of certain types of pollution control equipment at facilities owned by public utilities that are regulated by the West Virginia PSC, subject to the satisfaction of certain criteria. In April 2006, the West

 

31


Virginia PSC approved a settlement agreement among Monongahela, Potomac Edison and certain other interested parties relating to Allegheny’s plans to construct Scrubbers at the Fort Martin generation facility in West Virginia. Concurrently, the West Virginia PSC granted Monongahela and Potomac Edison a certificate of public convenience and necessity authorizing the construction and operation of the Scrubbers, approved a proposed restructuring of the ownership of certain of Allegheny’s generation assets, and issued a related financing order (the “Financing Order”) approving a proposal by Monongahela and Potomac Edison to finance $338 million of project costs using the securitization mechanism provided for by the legislation adopted in May 2005. Specifically, Monongahela and Potomac Edison received approval to issue environmental control bonds secured by the right to collect a surcharge from West Virginia retail customers that will be dedicated to the repayment of the bonds.

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

On October 3, 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a Petition to Reopen Proceedings and to Amend Financing Order (“Petition”), informing the West Virginia PSC that the current estimate for constructing the Scrubbers at Fort Martin had increased from $338 million to an amount up to $550 million. The Petition requested that the West Virginia PSC reopen the Financing Order proceedings for the purposes of amending the Financing Order to increase the securitization financing authority for construction related costs to an amount up to $550 million and reduce the maximum amount of upfront financing costs (exclusive of costs for the West Virginia PSC’s financial advisor) that may be recovered from environmental control bond proceeds from $27 million to $23 million. In addition, Monongahela and Potomac Edison indicated in the Petition that a complete review and value engineering process was being performed on the Fort Martin Scrubbers project and that a supplement to the Petition updating and further refining the current project cost estimate would be submitted to the West Virginia PSC within 45 days. On November 13, 2006, Allegheny filed a Supplement to the Petition with the West Virginia PSC that detailed the construction cost estimate of $550 million.

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

Rate Case

On July 26, 2006, Monongahela and Potomac Edison filed a request with the West Virginia PSC to increase their West Virginia retail rates by approximately $99.8 million annually, effective on August 25, 2006. The request includes a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a cost recovery clause, adjustable annually, to reflect upward or downward changes in the cost of fuel and purchased power, and a $26.2 million decrease in base rates. The rate increase request is subject to approval by the West Virginia PSC. On August 22, 2006, the West Virginia PSC issued an Order suspending Monongahela’s and Potomac Edison’s proposed new rates until May 23, 2007 and establishing a procedural schedule for the proceeding. Consistent with the procedural schedule, Monongahela and Potomac Edison filed

 

32


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

Maryland

Maryland adopted electric industry restructuring legislation in 1999, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation suppliers. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply but remained obligated to provide standard offer generation service, or “SOS,” at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, will expire on December 31, 2008. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates for all customers were capped through 2004 and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates).

In 2003, the Maryland PSC approved two statewide settlements relating to the future of PLR and SOS. The settlement extended Potomac Edison’s obligation to provide SOS after the expiration of the current generation rate cap periods. The settlement provided that, after expiration of the generation rate caps, SOS would be provided through 2012 for residential customers, through 2008 for smaller commercial and industrial customers and through 2006 for Potomac Edison’s medium-sized commercial customers. Potomac Edison’s obligation to provide SOS for its largest industrial customers expired at the end of 2005. A 2005 settlement extended Potomac Edison’s SOS obligations to its medium-sized commercial customers through May 2007, and a further order of the Maryland PSC issued on August 28, 2006 extended that obligation through at least the end of May 2009. The Maryland PSC issued an order on November 8, 2006, and a report to the Maryland legislature on December 31, 2006, that would continue SOS to small and medium-sized commercial customers with changes in procurement durations. These actions also would alter the procurement for residential customers of other Maryland electric utilities, but not necessarily for customers of Potomac Edison. The November 8, 2006 order is subject to a motion for rehearing filed by the Maryland Office of People’s Counsel, and neither the Maryland PSC nor the Maryland Legislature has taken further action on the subject of the December 31, 2006 report to the Maryland legislature. Allegheny cannot predict when a final resolution of these matters will be forthcoming.

Power Purchase Agreement

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

Rate Stabilization

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

 

33


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

On December 29, 2006, Allegheny filed its proposed Rate Stabilization Ramp-Up Transition Plan with the Maryland PSC, which is designed to transition residential customers from capped rates to rates based on market prices beginning in 2007 and ending in 2010. Under the plan as originally proposed, residential customers would pay a distribution surcharge beginning in early 2007. The application of the surcharge would result in an overall rate increase of approximately 15% annually from 2007 through 2010. With the expiration of the residential generation rate caps and the move to generation rates based on market prices on January 1, 2009, the surcharge would convert to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, would be returned to customers as a credit on their electric bills, thereby reducing the effect of the rate cap expiration. The credit would continue, with adjustments, to maintain rate stability until December 31, 2010. On January 31, 2007, after a series of public hearings on the Ramp-Up Transition Plan, Allegheny filed supplemental testimony setting forth an alternative to its original proposal. The alternative proposal would allow customers the ability to opt out of participating in the plan and contains other adjustments to address points raised in the public hearings. On February 2, 2007, all 21 members of the western Maryland delegation to the Maryland legislature sent a letter to the Maryland PSC publicly endorsing Allegheny’s alternative plan and urging its prompt approval by the Maryland PSC. The Maryland PSC has scheduled an evidentiary hearing on the proposed plans for March 15, 2007.

Renewable Energy Portfolio Standard

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

Virginia

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

Specifically, Allegheny believes that, based on the 2001 Amendment and the 2004 Amendment, the generation rates that Potomac Edison will be able to charge its Virginia customers beginning on July 1, 2007 will be based on its cost of purchased power. However, based on a memorandum of understanding (“MOU”) between the Virginia State Corporation Commission (the “Virginia SCC”) and Potomac Edison entered into at the time of the transfer of Potomac Edison’s generation facilities to AE Supply in 2000, the Virginia SCC may find that the generation rates Potomac Edison is able to charge for a certain portion of the power it purchases, currently

 

34


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

Potomac Edison’s T&D rates in Virginia are capped through 2010, subject to certain exceptions. Prior to 2010, Potomac Edison has two opportunities to petition the Virginia SCC for changes to its T&D rates: the first prior to June 30, 2007, and the second after July 1, 2007. Furthermore, the Restructuring Act requires the Virginia SCC to adjust Potomac Edison’s capped T&D rates not more than once annually for the timely recovery of costs prudently incurred after July 1, 2004 for T&D system reliability or to comply with state or federal environmental laws or regulations.

 

35


ENVIRONMENTAL MATTERS

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

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

Global Climate Change

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

 

 

 

developing an accurate CO2 emissions inventory;

 

   

improving the efficiency of its coal-burning fleet;

 

 

 

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

 

   

following developing technologies for carbon sequestration;

 

   

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

 

   

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

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

Air Standards

Clean Air Act Compliance.  Allegheny currently meets applicable standards for particulate matter emissions at its generation facilities through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and, at times, through other means. From time to time, minor excursions of stack emission opacity that are normal to fossil fuel operations are experienced and are accommodated by the regulatory process. Allegheny meets current emission standards for SO2 by using

 

36


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

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

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

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

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

On March 15, 2005, the EPA issued the Clean Air Mercury Rule (“CAMR”) establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants in two phases during 2010 and 2018. This rule will be implemented through state implementation plans currently under development. The rule has been challenged by several parties. Allegheny is currently assessing CAMR and its strategy for compliance. The Pennsylvania Department of Environmental Protection (the “PA DEP”) proposed a more aggressive mercury control rule on June 24, 2006, which is going through the regulatory review process and which is expected to be finalized in the first quarter of 2007. Allegheny is assessing the proposed Pennsylvania rule to determine what, if any, effect it would have on Allegheny’s Pennsylvania operations. Pennsylvania’s proposed shortened compliance schedule and more aggressive emissions limits might result in the installation of additional emission controls at any of Allegheny’s three Pennsylvania coal-fired facilities or in a change in fuel specifications. Controls might include Scrubbers, activated carbon injection, selective catalytic reduction or other, currently emerging technologies.

 

37


Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO2 and NOX, requires that greater reductions in mercury emissions be made more quickly than would be required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative and participate in that coalition’s regional efforts to reduce CO2 emission. The Act does provide a conditional exemption for the R. Paul Smith power station, provided that PJM declares the station vital to reliability in the Baltimore/Washington DC metropolitan area. In response to Allegheny’s request and after conducting a reliability evaluation, PJM, by letter dated November 8, 2006, determined that R. Paul Smith is vital to the regional reliability of power flow. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) will now create specific regulations for R. Paul Smith by June 2007 to comply with both the Healthy Air Act and the federal CAIR. Allegheny is assessing the new legislation and upcoming implementing regulations to determine the full extent of the impacts on Allegheny’s Maryland operations and will work with the MDE on the R. Paul Smith-specific regulations.

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

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

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

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

 

38


On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Distribution Companies in the United States District Court for the Western District of Pennsylvania (the “PA Enforcement Action”). This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the federal District Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On February 17, 2006, Allegheny filed a motion to dismiss the amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss. On June 30, 2006, Allegheny filed an answer to the plaintiff’s first amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies, and the liability phase of discovery should be completed by June 30, 2007.

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

Other Environmental Litigation

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

Global Warming Class Action:  On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. On December 6, 2006, AE filed a motion to dismiss plaintiffs’ complaint on jurisdictional grounds and joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. These motions remain pending. AE intends to vigorously defend against this action but cannot predict its outcome.

Claims Related to Alleged Asbestos Exposure:  The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their

 

39


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

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

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

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

Pending Initiatives

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

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

 

40


EMPLOYEES

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

On September 19, 2005, AE entered into a Professional Services Agreement with a service provider under which, on November 1, 2005, the service provider assumed responsibility for many of Allegheny’s information technology functions. Unless extended by AE, the Professional Services Agreement will expire on December 31, 2012. Most of the AESC employees performing Allegheny’s information technology functions were offered employment with the service provider.

 

41


Executive Officers of the Registrants

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

 

Name

   Age   

AE

  

Monongahela

  

AGC

Paul J. Evanson (a)

   65   

Chairman, President,

Chief Executive Officer and Director

  

Chairman, Chief Executive Officer

and Director

   Chairman, Chief Executive Officer and Director

Edward Dudzinski (b)

   54    Vice President    Vice President   

David M. Feinberg (c)

   37    Vice President, General Counsel and Secretary    Vice President and Secretary    Vice President, Secretary and Director

David E. Flitman (d)

   42    Vice President    President and Director   

Thomas R. Gardner (e)

   49   

Vice President, Controller,

Chief Accounting Officer and

Chief Information Officer

   Controller    Vice President and Controller

Philip L. Goulding (f)

   47   

Senior Vice President and

Chief Financial Officer

   Vice President and Director    Vice President and Director

Joseph H. Richardson (g)

   57    Chief Operating Officer —Generation      

(a) Paul J. Evanson has been Chairman of the Board, President, Chief Executive Officer and a director of AE since June 2003. Mr. Evanson is the Chair of the Executive Committee. He has also been Chairman, Chief Executive Officer and a director of Monongahela and AGC since June 2003. Prior to joining Allegheny, Mr. Evanson was President of Florida Power & Light Company, the principal subsidiary of FPL Group, Inc., and a director of FPL Group, Inc. from 1995 to 2003.
(b) Edward Dudzinski has been Vice President, Human Resources, of AE since August 2004. He has also been a Vice President of Monongahela since August 2004. Prior to joining Allegheny, Mr. Dudzinski was Vice President, Human Resources for the Agriculture and Nutrition Platform and Pioneer Hi-Bred International, Inc. on behalf of E. I. DuPont de Nemours and Company (“DuPont”). Prior to that, he served in various other executive and leadership positions at DuPont.
(c) David M. Feinberg has been Vice President, General Counsel and Secretary of AE since October 2006. Mr. Feinberg joined Allegheny in August 2004 and served as Deputy General Counsel until October 2006. He has also been Vice President, General Counsel and Secretary of Monongahela and AGC since October 2006. Prior to joining Allegheny, Mr. Feinberg was a partner with the law firm of Jenner & Block LLP in its Chicago office.
(d) David E. Flitman has been President of Allegheny Power, which includes Monongahela, Potomac Edison and West Penn, since July 2006. Mr. Flitman joined Allegheny in February 2005 as Vice President, Distribution. Prior to joining Allegheny, Mr. Flitman was employed with DuPont, most recently as Global Business Director for the Nonwovens Business Group.
(e) Thomas R. Gardner has been Vice President, Controller and Chief Accounting Officer of AE since October 2003 and has been Chief Information Officer of AE since June 2005. He has also been the Controller of Monongahela and a Vice President and the Controller of AGC since October 2003. Prior to joining Allegheny, Mr. Gardner was employed with Deloitte & Touche LLP from 1997 to 2003, most recently as a partner.
(f) Philip L. Goulding has been Senior Vice President and Chief Financial Officer of AE since July 2006. He has also been Vice President of Monongahela and AGC since July 2006. Mr. Goulding joined Allegheny in October 2003 as Vice President, Strategic Planning and Chief Commercial Officer. Prior to joining Allegheny, Mr. Goulding led the North American energy practice of L.E.K. Consulting.
(g) Joseph. H. Richardson has been Chief Operating Officer—Generation of AE since July 2006. Mr. Richardson joined Allegheny in August 2003 as a Vice President of AE and as President and a director of Monongahela, Potomac Edison and West Penn. Prior to joining Allegheny, Mr. Richardson served as President and Chief Executive Officer and as a director of Global Energy Group from March 2002 to August 2003. Prior to that, he served as President and Chief Executive Officer and as a director of Florida Power Corporation.

 

42


ITEM 1A.    RISK FACTORS

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

Risks Relating to Regulation

Allegheny is subject to substantial governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits and certificates may result in substantial costs to Allegheny, and failure to obtain necessary regulatory approvals could have an adverse effect on its business.

Allegheny is subject to substantial regulation from federal, state and local regulatory agencies. Allegheny is required to comply with numerous laws and regulations and to obtain numerous authorizations, permits, approvals and certificates from governmental agencies. These agencies regulate various aspects of Allegheny’s business, including customer rates, services, retail service territories, generation plant operations, sales of securities, asset sales and accounting policies and practices. Although Allegheny believes the necessary authorizations, permits, approvals and certificates have been obtained for Allegheny’s existing operations and that Allegheny’s business is conducted in accordance with applicable laws, it cannot predict the impact of any future revisions or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to it. See “Regulatory Framework Affecting Allegheny” above.

Changes in regulations or the imposition of additional regulations could influence Allegheny’s operating environment and may result in substantial costs to Allegheny.

Allegheny’s costs to comply with environmental laws are significant. New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on Allegheny’s generation operations or require it to incur significant additional costs. The cost of compliance with present and future environmental laws could have an adverse effect on Allegheny’s business.

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

Allegheny’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install post-combustion control technologies on many of its generation facilities. The Clean Air Interstate Rule, or “CAIR,” promulgated by the EPA on March 10, 2005, may accelerate the need to install this equipment by phasing out a portion of currently available allowances. Allegheny continues to evaluate options for compliance, and current plans include the potential installation of Scrubbers at its Hatfield’s Ferry and Fort Martin generation facilities by 2009 and the elimination of a Scrubber bypass at its Pleasants generation facility by 2008. The installation of Scrubbers at the Hatfield’s Ferry and Fort Martin generation facilities will be subject to various implementation and financial risks. See “Capital Expenditures” and “Environmental Matters” above.

 

43


Carbon dioxide, or “CO2,” is one of the greenhouse gases implicated in global climate change. Allegheny’s generation facilities are primarily coal-fired facilities and, therefore, emit CO2 as coal is consumed. Federal legislation and implementing regulations addressing climate change may be adopted some time in the future, and such legislation may include limits on emissions of CO2. Allegheny can provide no assurance that such limits, if imposed, will be set at levels that can accommodate its generation facilities absent the installation of controls. Furthermore, there is no current technology that enables control of such emissions from existing pulverized, coal-fired power plants, which constitute the majority of Allegheny’s generation fleet. Such technology may not become available within a timeframe consistent with the implementation of any future climate control legislation or at all. To the extent that such technology does become available, Allegheny can provide no assurance that it will be suitable for installation at Allegheny’s generation facilities on a cost effective basis or at all. See “Environmental Matters” above.

In March 2005, the EPA issued the Clean Air Mercury Rule, or “CAMR,” establishing a cap and trade system designed to reduce mercury emissions from coal-fired power plants. In addition, the PA DEP proposed a more aggressive mercury control rule in June 2006. Allegheny is currently assessing the impact that these rules may have on its operations. Pennsylvania’s proposed shortened compliance schedule and more aggressive emissions limits might result in the installation of additional emission controls at any of Allegheny’s three Pennsylvania coal-fired facilities or in a change in fuel specifications. Controls might include Scrubbers, activated carbon injection, selective catalytic reduction or other currently emerging technologies. See “Environmental Matters” above.

Applicable standards under the EPA’s NSR initiatives remain in flux. Under the Clean Air Act, modification of Allegheny’s generation facilities in a manner that causes increased emissions could subject Allegheny’s existing facilities to the far more stringent NSR standards applicable to new facilities. The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work believed by the companies to be routine maintenance. If NSR requirements are imposed on Allegheny’s generation facilities, in addition to the possible imposition of fines, compliance would entail significant capital investments in pollution control technology. See “Environmental Matters” above.

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

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

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

 

44


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

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

Shifting state and federal regulatory policies impose risks on Allegheny’s operations. Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have an adverse effect on its business.

Allegheny’s operations are subject to evolving regulatory policies, including initiatives regarding deregulation and re-regulation of the production and sale of electricity and the restructuring of transmission regulation. Any new requirements arising from these actions could lead to increased operating expenses and capital expenditures, the amount of which cannot be predicted at this time.

Some deregulated electricity markets in which Allegheny operates have experienced price volatility. In some of these markets, government agencies and other interested parties have made proposals to delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect the deregulated electricity markets to remain competitive, other proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which we operate. Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have an adverse effect on its business, results of operations, cash flows and financial condition. At a minimum, these types of actions raise uncertainty concerning the continued development of competitive power markets. Given Allegheny’s multi-state operations and asset base, re-regulation of restructured obligations could prove intricate, time-consuming and costly to ongoing operations.

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

State rate regulation may delay or deny full recovery of costs and impose risks on Allegheny’s operations. Any denial of, or delay in, cost recovery could have an adverse effect on Allegheny’s business.

The retail rates in the states in which Allegheny operates are set by each state’s regulatory body. As a result, in certain states, Allegheny may not be able to recover increased, unexpected or necessary costs and, even if Allegheny is able to do so, there may be a significant delay between the time Allegheny incurs such costs and the time Allegheny is allowed to recover them. Any denial of, or delay in, cost recovery could have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Maryland

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

 

45


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

Virginia

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

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

West Virginia

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

On July 26, 2006, Potomac Edison and Monongahela filed a request with the West Virginia PSC to increase their West Virginia retail rates by approximately $99.8 million annually, effective on August 25, 2006. The request includes a $126 million increase in rates related to fuel and purchased power costs, including reinstatement of a cost recovery clause, adjustable annually, to reflect upward or downward changes in the cost of fuel and purchased power, and a $26 million decrease in transmission, distribution and generation (non-fuel) rates. The hearing in this matter was held the week of February 12, 2007. The new rates, as approved by the West Virginia PSC, will go into effect on May 23, 2007. Allegheny can provide no assurance that this rate increase request will be approved. Any failure to receive such an approval in whole or in part may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

 

46


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

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

Allegheny is from time to time subject to federal or state tax audits the resolution of which could have an adverse effect on Allegheny’s financial condition.

Allegheny is subject to periodic audits and examinations by the Internal Revenue Service (“IRS”) and other state and local taxing authorities. Determinations and expenses related to these audits and examinations and other proceedings by the IRS and other state and local taxing authorities could materially and adversely affect Allegheny's financial condition.

Risks Related to Allegheny’s Leverage and Financing Needs

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

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

 

   

borrow funds;

 

   

incur liens and guarantee debt;

 

   

enter into a merger or other change of control transaction;

 

   

make investments;

 

   

dispose of assets; and

 

   

pay dividends and other distributions on its equity securities.

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

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

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

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

 

   

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

 

47


   

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

 

   

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

 

   

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

 

   

limit Allegheny’s ability to borrow additional funds; and

 

   

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

Allegheny may be unable to engage in desired financing transactions.

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

 

   

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

 

   

its overall financial condition and results of its operations; and

 

   

volatility in the capital markets.

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

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

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

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

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

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

 

48


Allegheny’s credit ratings, could increase Allegheny’s cost of borrowing or could adversely affect its ability to access one or more financial markets. Causes of disruption to the capital markets could include, but are not limited to:

 

   

a recession or an economic slowdown;

 

   

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

 

   

significant increases in the prices for oil or other fuel;

 

   

a terrorist attack or threatened attacks;

 

   

a significant transmission failure; or

 

   

changes in technology.

Risks Relating to Allegheny’s Operations

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

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

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

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

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

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

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

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

 

49


insurance, if any, for repairs, which may adversely impact Allegheny’s results of operations and financial condition. Although Allegheny has taken, and will continue to take, reasonable precautions to safeguard these assets, Allegheny can make no assurance that its facilities will not face damage or disruptions or that it will have sufficient insurance, if any, to cover the cost of repairs. In addition, in the current geopolitical climate, enhanced concern regarding the risks of terrorism throughout the economy may impact Allegheny’s operations in unpredictable ways. Insurance coverage may not cover costs associated with any of these risks adequately or at all. While T&D losses may be recoverable through regulatory proceedings, the delay and uncertainty of any such recovery could have a material adverse effect on Allegheny’s business, financial condition, cash flow and results of operations.

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

In connection with regulations governing the transition to market competition, Potomac Edison and West Penn are required to provide electricity at capped rates to certain retail customers who do not choose an alternate electricity generation supplier or who return to utility service from alternate suppliers. Potomac Edison and West Penn satisfy the majority of these obligations by purchasing power under contracts with external counterparties, or their affiliate, AE Supply. Those contracts provide for the supply of a significant portion of their energy needs at the mandated capped rates and for the supply of a specified remaining portion at rates based on market prices. The amount of energy priced at market rates increases over each contract term. The majority of AE Supply’s normal operating capacity is dedicated to these contracts.

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

Additionally, Potomac Edison has a power supply agreement with Monongahela under which Monongahela is required to supply to Potomac Edison the power necessary for Potomac Edison to serve its West Virginia customers. In West Virginia, the rates charged to retail customers are regulated by the West Virginia PSC and are determined through traditional, cost-based, regulated utility rate-making. Although Potomac Edison and Monongahela recently filed a request with the West Virginia PSC to increase their rates in West Virginia, it is possible that Potomac Edison may not be permitted to recover from its West Virginia customers the full cost of purchasing power under the terms of this agreement.

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

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

 

50


Based on current forecasts, Allegheny estimates that it may have exposure to the SO2 allowance market in 2007 of about 30,000 to 50,000 tons and may have exposure in 2008 of between 85,000 and 120,000 tons. The exposure of Monongahela is expected to be 70% and 50% of Allegheny’s exposure in 2007 and 2008, respectively. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Therefore, there can be no assurance that Allegheny’s need to purchase SO2 allowances for these periods will not vary from current estimates. Fluctuations in the availability or cost of emission allowances could have a material adverse effect on Allegheny’s business, financial condition, cash flows and results of operations. See “Environmental Matters” above.

Allegheny is currently involved in capital intensive projects that may involve various implementation and financial risks.

Allegheny currently is involved in a number of capital intensive projects, including the TrAIL Project and the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities. Allegheny’s ability to successfully and timely complete these projects within established budgets is contingent upon many variables. Failure to complete these projects as planned may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Additionally, Allegheny has contracted, or expects to contract, with specialized vendors to acquire some of the necessary materials and construction related services in order to accomplish the installation of Scrubbers at the Fort Martin and Hatfield’s Ferry generation facilities and may in the future enter into additional such contracts with respect to these and other capital projects, including the TrAIL Project. As such, Allegheny is exposed to the risk that these contractors may not perform as required under their contracts. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Furthermore, Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all.

Allegheny is currently involved in significant litigation that, if not decided favorably to Allegheny, could have a material adverse effect on its results of operations, cash flows and financial condition.

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

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

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

Adverse investment returns and other factors may increase Allegheny’s pension liability and pension funding requirements.

Substantially all of Allegheny’s employees are covered by a defined benefit pension plan. At present, the pension plan is underfunded in that the projected pension benefit obligation exceeds the aggregate fair value of plan assets. Under applicable law, Allegheny is required to make cash contributions to the extent necessary to

 

51


comply with minimum funding requirements imposed by regulatory requirements. The amount of such required cash contribution is based on an actuarial valuation of the plan. The funded status of the plan can be affected by investment returns on plan assets, discount rates, mortality rates of plan participants, pension reform legislation and a number of other factors. There can be no assurance that the value of Allegheny’s pension plan assets will be sufficient to cover future liabilities. It is possible that Allegheny could incur a significant pension liability adjustment, or could be required to make significant additional cash contributions to its plan, which would reduce the cash available for business and other needs.

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

Because Allegheny has transferred functional control of its transmission facilities to PJM and Allegheny is a load serving entity within the PJM Region and owns generation within the PJM Region, changes in PJM policies and/or market rules, including changes that are currently under consideration by FERC, could adversely affect Allegheny’s financial results. These matters include changes involving: the terms, conditions and pricing of transmission services; construction of transmission enhancements; auction of long-term financial transmission rights and the allocation mechanism for the auction revenues; changes in the locational marginal pricing mechanism; changes in transmission congestion patterns due to the proposed implementation of PJM’s regional transmission expansion planning protocol or other required transmission system upgrades; new generation retirement rules and reliability pricing issues. Furthermore, deterioration in the credit quality of other PJM members could negatively impact Allegheny’s performance.

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

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

Risks Relating to Operational Enhancements

Refocusing its business subjects Allegheny to risks and uncertainties.

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

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

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

 

52


ITEM 2.    PROPERTIES

Substantially all of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations. Substantially all of Monongahela’s, Potomac Edison’s and West Penn’s properties are held subject to the lien of indentures securing their first mortgage bonds. Certain of the properties and other assets owned by AE Supply and Monongahela that were financed by solid waste disposal and pollution control notes are subject to liens securing the obligations under those notes. In many cases, the properties of Monongahela, Potomac Edison, West Penn and other AE subsidiaries may be subject to certain reservations, minor encumbrances and title defects that do not materially interfere with their use. The indenture under which AGC’s unsecured debentures are issued prohibits AGC, with certain limited exceptions, from incurring or permitting liens to exist on any of its properties or assets unless the debentures are contemporaneously secured equally and ratably with all other debt secured by the lien. Most T&D lines, some substations and switching stations and some ancillary facilities at generation facilities are on lands of others, in some cases by sufferance but, in most instances, pursuant to leases, easements, rights-of-way, permits or other arrangements, many of which have not been recorded and some of which are not evidenced by formal grants. In some cases, no examination of titles has been made as to lands on which T&D lines and substations are located. Each of the Distribution Companies possesses the power of eminent domain with respect to its public utility operations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” below and Note 4, “Capitalization” to the Consolidated Financial Statements.

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

 

53


ITEM 3.    LEGAL PROCEEDINGS

Nevada Power Contracts

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

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

Sierra/Nevada

On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted claims against AE and AE Supply for: (a) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (b) conspiracy and (c) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada filed an amended complaint on May 30, 2003, which asserted a fourth cause of action against AE and AE Supply for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys’ fees and seeks in excess of $850 million under the RICO count. AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. Thereafter, plaintiffs filed a motion to stay the action, pending the outcome of certain state court proceedings in which they are seeking to reverse the Nevada PUC’s disallowance of expenses. On April 4, 2005, the District Court granted the stay motion, and the action is currently stayed. On July 20, 2006, the Nevada Supreme Court reversed the Nevada PUC’s disallowance of the $180 million in deferred energy expenses, which formed the basis of the plaintiffs’ claims.

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

Claim by California Parties

On October 5, 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (“CDWR”) during 2001. The settlement demand to AE Supply in the amount of approximately $190 million was made in the context of mediation efforts by FERC and the U.S. Court of Appeals for the Ninth Circuit to resolve all outstanding claims

 

54


of alleged price manipulation in the California energy markets during 2000 and 2001. No complaint has been filed against Allegheny. Allegheny believes that all issues in connection with AE Supply sales to CDWR were resolved by a settlement in 2003 and otherwise believes that the California parties’ demand is without merit. Allegheny intends to vigorously defend against this claim but cannot predict its outcome.

Litigation Involving Merrill Lynch

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

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

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

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

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

Putative Benefit Plan Class Actions

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

 

55


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

Suits Related to the Gleason Generation Facility

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

Harrison Fuel Litigation

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

ICG Litigation

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

Ordinary Course of Business

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

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

No matters were submitted to a vote of security holders of AE, Monongahela or AGC during the fourth quarter of 2006.

 

56


PART II

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

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

AE

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

 

     2006    2005
     High    Low    High    Low

1st Quarter

   $ 36.46    $ 31.33    $ 21.28    $ 18.25

2nd Quarter

   $ 37.61    $ 33.01    $ 25.85    $ 20.28

3rd Quarter

   $ 42.50    $ 36.97    $ 31.35    $ 25.25

4th Quarter

   $ 46.25    $ 39.93    $ 32.32    $ 26.40

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

Monongahela

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

AGC

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

 

57


Performance Graph

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

LOGO

 

     Cumulative Total Return
     12/01    12/02    12/03    12/04    12/05    12/06

Allegheny Energy, Inc.  

   100.00    21.96    37.07    57.26    91.95    133.38

S & P 500

   100.00    77.90    100.24    111.15    116.61    135.03

Dow Jones U.S. Electricity

   100.00    77.33    96.72    120.28    140.57    169.88

 

58


ITEM 6.    SELECTED FINANCIAL DATA

 

     Page No.

Allegheny Energy, Inc. and Subsidiaries

   60

Monongahela Power Company and Subsidiaries

   61

Allegheny Generating Company

   61

 

59


ITEM 6.    SELECTED FINANCIAL DATA

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

 

Year ended December 31,

   2006    2005     2004     2003     2002  

(In millions, except per share data)

                             

Operating revenues

   $ 3,121.5    $ 3,037.9     $ 2,756.1     $ 2,182.3     $ 2,743.8  

Operating expenses

   $ 2,389.2    $ 2,501.1     $ 2,166.9     $ 2,378.7     $ 3,216.4  

Operating income (loss)

   $ 732.3    $ 536.8     $ 589.2     $ (196.4 )   $ (472.6 )

Income (loss) from continuing operations

   $ 318.7    $ 75.1     $ 129.7     $ (308.9 )   $ (465.8 )

Income (loss) from discontinued operations, net of tax

   $ 0.6    $ (6.1 )   $ (440.3 )   $ (25.3 )   $ (36.4 )

Net income (loss)

   $ 319.3    $ 63.1     $ (310.6 )   $ (355.0 )   $ (632.7 )

Earnings per share:

           

Income (loss) from continuing operations, net of tax

           

—basic

   $ 1.94    $ 0.48     $ 1.00     $ (2.44 )   $ (3.71 )

—diluted

   $ 1.89    $ 0.47     $ 0.99     $ (2.44 )   $ (3.71 )

Loss from discontinued operations, net of tax

           

—basic

   $ —      $ (0.04 )   $ (3.40 )   $ (0.20 )   $ (0.29 )

—diluted

   $ —      $ (0.04 )   $ (2.82 )   $ (0.20 )   $ (0.29 )

Net income (loss)

           

—basic

   $ 1.94    $ 0.40     $ (2.40 )   $ (2.80 )   $ (5.04 )

—diluted

   $ 1.89    $ 0.40     $ (1.83 )   $ (2.80 )   $ (5.04 )

Dividends declared per share

   $ —      $ —       $ —       $ —       $ 1.29  

Short-term debt

   $ —      $ —       $ —       $ 53.6     $ 1,132.0  

Long-term debt due within one year (a)

     201.2      477.2       385.1       544.9       257.2  

Debentures, notes and bonds (a)

     —        —         —         —         3,662.2  
                                       

Total short-term debt (a)

   $ 201.2    $ 477.2     $ 385.1     $ 598.5     $ 5,051.4  
                                       

Long-term debt (a)

   $ 3,384.0    $ 3,624.5     $ 4,540.8     $ 5,127.4     $ 115.9  

Capital leases

     26.0      16.4       23.8       32.5       39.1  
                                       

Total long-term obligations (a)

   $ 3,410.0    $ 3,640.9     $ 4,564.6     $ 5,159.9     $ 155.0  
                                       

Total assets

   $ 8,552.4    $ 8,558.8     $ 9,045.1     $ 10,171.9     $ 10,973.2  
                                       

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

 

60


MONONGAHELA POWER COMPANY AND SUBSIDIARIES

 

Year ended December 31,

  2006     2005   2004     2003   2002  

(In millions)

                         

Operating revenues

  $ 773.7     $ 789.9   $ 683.8     $ 718.9   $ 695.5  

Operating expenses

  $ 650.6     $ 765.0   $ 637.0     $ 633.8   $ 621.5  

Operating income

  $ 123.1     $ 24.9   $ 46.8     $ 85.1   $ 74.0  

Income from continuing operations

  $ 70.1     $ 9.2   $ 16.4     $ 72.0   $ 32.4  

Income (loss) from discontinued operations, net of tax

  $ (1.0 )   $ 1.0   $ (13.9 )   $ 9.2   $ 1.3  

Net income (loss)

  $ 69.1     $ 10.2   $ 2.5     $ 80.7   $ (81.7 )

Short-term debt

  $ —       $ —     $ —       $ 53.6   $ —    

Long-term debt due within one year (a)

    15.5       300.0     —         3.4     65.9  

Notes and bonds (a)

    —         —       —         —       690.1  
                                   

Total short-term debt (a)

  $ 15.5     $ 300.0   $ —       $ 57.0   $ 756.0  
                                   

Long-term debt (a)

  $ 519.1     $ 385.1   $ 684.0     $ 715.5   $ 28.5  

Capital leases

    7.4       5.6     8.7       12.2     14.3  
                                   

Total long-term obligations (a)

  $ 526.5     $ 390.7   $ 692.7     $ 727.7   $ 42.8  
                                   

Total assets

  $ 1,744.3     $ 1,859.2   $ 2,081.4     $ 2,073.1   $ 2,042.2  
                                   

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

ALLEGHENY GENERATING COMPANY

 

Year ended December 31,

   2006    2005    2004    2003    2002

(In millions)

                        

Operating revenues

   $ 65.3    $ 66.6    $ 69.2    $ 70.5    $ 64.1

Operating expenses

   $ 25.6    $ 24.8    $ 26.1    $ 25.4    $ 25.8

Operating income

   $ 39.7    $ 41.9    $ 43.1    $ 45.1    $ 38.3

Net income

   $ 24.8    $ 31.1    $ 27.4    $ 20.8    $ 18.6

Short-term debt

   $ —      $ —      $ —      $ —      $ 55.0

Long-term debt due within one year

     —        —        —        —        50.0

Debentures (a)

     —        —        —        —        99.3
                                  

Total short-term debt (a)

   $ —      $ —      $ —      $ —      $ 204.3
                                  

Long-term debt (a)

   $ 99.5    $ 99.4    $ 99.4    $ 99.4    $ —  

Long-term note payable to parent

     —        —        15.0      30.0      —  
                                  

Total long-term obligations (a)

   $ 99.5    $ 99.4    $ 114.4    $ 129.4    $ —  
                                  

Total assets

   $ 538.0    $ 550.2    $ 557.2    $ 562.4    $ 597.6
                                  

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

 

61


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

 

     Page No.

EXECUTIVE SUMMARY:

  

Business Overview

   63

Key Indicators and Performance Factors

   68

Operating Statistics

   70

Primary Factors Affecting Allegheny’s Performance

   70

Critical Accounting Policies and Estimates

   70

RESULTS OF OPERATIONS:

  

Allegheny Energy, Inc. and Subsidiaries

   74

Monongahela Power Company and Subsidiaries

   95

Allegheny Generating Company

   105

FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES:

  

Liquidity and Capital Requirements

   106

Asset Sales

   110

Dividends

   111

Other Matters Concerning Liquidity and Capital Requirements

   111

Cash Flows

   114

Financing

   119

Credit Ratings

   120

RECENT ACCOUNTING PRONOUNCEMENTS

   120

 

62


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

Overview

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

Allegheny has two business segments:

 

   

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

 

   

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

The Delivery and Services Segment

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

 

   

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

 

   

Monongahela conducts an electric T&D business in northern West Virginia. Monongahela also owns generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below.

Monongahela conducted electric T&D operations in Ohio and natural gas T&D operations in West Virginia until it sold the assets related to these operations on December 31, 2005 and September 30, 2005, respectively. Monongahela agreed to sell power at a fixed price to Columbus Southern, the purchaser of its electric T&D operations in Ohio, to serve Monongahela’s former Ohio service territory from January 1, 2006 until May 31, 2007. See “Liquidity and Capital Resources—Asset Sales” below.

 

   

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

 

   

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

 

   

TrAIL Company was formed in 2006 in connection with the management and financing of transmission expansion projects, including the TrAIL Project, and it will own and operate the new transmission line.

 

   

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

The Generation and Marketing Segment

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

 

   

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

 

63


 

various customers and markets. Currently, the majority of the Generation and Marketing segment’s normal operating capacity is committed to supplying certain obligations of the Distribution Companies, including their PLR obligations.

 

   

Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment. Monongahela’s Generation and Marketing segment’s normal operating capacity supplies Monongahela’s Delivery and Services segment. In addition, in connection with the Asset Swap, AE Supply assigned to Monongahela its obligation to supply generation to meet Potomac Edison’s load obligations in West Virginia.

 

   

AGC was owned approximately 77% by AE Supply and approximately 23% by Monongahela through December 31, 2006. As a result of the Asset Swap, AGC currently is owned approximately 59% by AE Supply and approximately 41% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,035 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela.

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

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

Intersegment Services

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

The Distribution Companies’ Obligations and the PJM Market

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

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

 

64


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

 

   

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

 

   

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

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

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

All of Allegheny’s generation facilities are located within the PJM market, and all of the power that the Generation and Marketing segment generates is sold into the PJM market. To facilitate the economic dispatch of generation, AE Supply and Monongahela sell the power that they generate into the PJM market and purchase from the PJM market the power necessary to meet their obligations to supply power.

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

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

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

 

65


Initiatives and Achievements

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

Significant initiatives and recent achievements include:

 

   

Pursuing Transmission Expansion.  In June 2006, PJM approved a regional transmission expansion plan designed to maintain the reliability of the transmission grid in the Mid-Atlantic region that includes a new, 240-mile extra high-voltage transmission line extending from southwestern Pennsylvania, through West Virginia and possibly Maryland to northern Virginia, 210 miles of which is to be located in the Distribution Companies’ PJM zone. The line is designed to alleviate future reliability concerns and increase the west to east transmission capability of the PJM transmission system. PJM designated Allegheny to construct the portion of the line that will be located in the Distribution Companies’ PJM zone. Additionally, FERC approved four incentive rate treatments, which are intended to promote the construction of transmission facilities, for the transmission line, and PJM has requested that the DOE designate the project as a National Interest Electric Transmission Corridor. Allegheny currently is in the process of siting the transmission line and will seek requisite permits and regulatory approvals. PJM is considering additional transmission expansion initiatives, a number of which, as contemplated, would pass through Allegheny’s service territory.

 

   

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

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

 

   

Managing Transition to Market-based Rates.  In 2005, Allegheny successfully implemented a plan to transition Pennsylvania customers to generation rates based on market prices through increases in applicable rate caps in 2007, 2009 and 2010 and a two-year extension of the applicable transition period. Together with previously approved rate cap increases for 2006 and 2008, these increases will gradually move generation rates in Pennsylvania closer to market prices.

Allegheny is actively working to effectively manage a similar transition in Maryland. In December 2006, Allegheny filed a proposal with the Maryland PSC to transition residential customers from capped generation rates to generation rates based on market prices beginning in 2007 and ending in 2010. Under the proposed plan, residential customers would to pay a distribution surcharge beginning on March 31, 2007. The proposed plan, including the application of the surcharge, would result in an overall rate increase of approximately 15% annually from 2007 through 2010. With the expiration of the residential generation rate caps and the move to generation rates based on market prices on January 1, 2009, the surcharge would convert to a credit on customers’ bills. Funds collected through the surcharge during

 

66


2007 and 2008, plus interest, would be returned to customers as a credit on their electric bills, thereby reducing the effect of the rate cap expiration. The credit would continue, with adjustments, to maintain rate stability until December 31, 2010. Following public hearings, Allegheny filed an alternate proposal that would, among other things, provide customers with the ability to opt out of the surcharge. See “Business—Regulatory Framework Affecting Allegheny” and “Business—Fuel, Power and Resource Supply” above.

 

   

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

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

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

 

   

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

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

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

Additionally, Allegheny has entered into various coal supply contracts in an effort to ensure a consistent supply of coal at predictable prices, and currently has contracts in place for the delivery of approximately 96% of its expected coal needs for 2007. See “Business—Fuel, Power and Resource Supply” above.

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

 

   

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

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

 

67


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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

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

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

Key Indicators and Performance Factors

The Delivery and Services Segment

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

Revenue per MWh sold.    This measure is calculated by dividing total revenues from retail sales of electricity by total MWhs sold to retail customers. Revenue per MWh sold in 2006, 2005 and 2004 was as follows:

 

     2006    2005    2004

Revenue per MWh sold

   $ 58.62    $ 55.32    $ 54.48

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

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

 

68


The Generation and Marketing Segment

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

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

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

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

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

 

     2006     2005     2004     2006
% Increase
(Decrease)
    2005
% Increase
(Decrease)
 

Supercritical Units:

          

EAF

     84.3 %     82.8 %     75.6 %   1.5 %   7.2 %

Station O&M (in millions):

          

Base operations (a)

   $ 99.2     $ 101.6     $ 102.4     (2.4 )%   (0.8 )%

Special

     79.2       95.1       99.5     (16.7 )%   (4.4 )%
                                    

Total Station O&M

   $ 178.4     $ 196.7     $ 201.9     (9.3 )%   (2.6 )%
                                    

All Generation Units:

          

kWhs generated (in millions)

     48,606       48,100       46,162     1.1 %   4.2 %

EAF

     86.9 %     85.4 %     82.4 %   1.5 %   3.0 %

Station O&M (in millions):

          

Base operations (a)

   $ 155.8     $ 167.6     $ 169.7     (7.0 )%   (1.2 )%

Special

     91.3       113.9       125.6     (19.8 )%   (9.3 )%
                                    

Total Station O&M

   $ 247.1     $ 281.5     $ 295.3     (12.2 )%   (4.7 )%
                                    

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

 

69


Operating Statistics

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

 

     2006    2005    2004    2006
% Change
    2005
% Change
 

Retail electricity sales (million kWhs)

   43,179    48,275    47,201    (10.6 )%   2.3 %

HDD (a)

   4,861    5,333    5,205    (8.9 )%   2.5 %

CDD (a)

   781    1,087    789    (28.2 )%   37.8 %

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

Primary Factors Affecting Allegheny’s Performance

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

 

   

changes in regulatory policies and rates,

 

   

changes in the competitive electricity marketplace,

 

   

coal plant availability,

 

   

weather conditions,

 

   

environmental compliance costs,

 

   

changes in the PJM market, rules and policies,

 

   

availability and access to liquidity and changes in interest rates,

 

   

cost of fuel (natural gas and coal),

 

   

wholesale commodity prices and

 

   

labor costs.

Critical Accounting Policies and Estimates

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

 

70


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

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

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

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

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

Revenue Recognition:  Allegheny follows the accrual method of accounting for revenues and recognizes revenue for electricity that has been delivered to customers but not yet billed through the end of its accounting period. Unbilled revenues are primarily associated with the Distribution Companies. Energy sales to individual customers are based on their meter readings, which are performed periodically on a systematic cycle basis. At the end of each month, the amount of energy delivered to each customer after the last meter reading is estimated, and the Distribution Companies recognize unbilled revenues related to these estimated amounts. The unbilled revenue estimates are based on daily generation, purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses and the most recent consumer rates. A change in these estimates and assumptions could have a significant effect on Allegheny’s consolidated results of operations and financial position. A provision for uncollectible amounts is recorded as a component of operations and maintenance expense.

 

71


Regulatory Accounting:  The Distribution Companies are subject to regulations that set the rates that they are permitted to charge customers. These rates are based on costs that the regulatory agencies determine the Distribution Companies are permitted to recover. At times, regulators permit the future, but not current, recovery through rates of costs that would otherwise be charged to expense by an unregulated company. Regulators may also require that amounts be refunded to customers for various reasons. Therefore, this ratemaking process often results in the recording of regulatory assets based on estimated future cash inflows and the recording of regulatory liabilities based on estimated future cash outflows.

Allegheny regularly reviews its regulatory assets and liabilities and the estimates and assumptions from which they were calculated to assess the ultimate recoverability of the assets and anticipated customer refunds within approved regulatory guidelines. A change in these estimates and assumptions could have a significant effect on Allegheny’s results of operations and financial position.

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

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

Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The following table shows the effect that a one percentage point increase or decrease in the 6.0% discount rate and the 8.25% expected rate of return, net of administrative expenses, on plan assets for 2007 would have on Allegheny’s pension and OPEB obligations and costs:

 

(In millions)

   1-Percentage-Point
Increase
   

1-Percentage-Point

Decrease

Change in the discount rate:

    

Pension and OPEB obligation

   $ (149.9 )   $ 182.9

Net periodic pension and OPEB cost

   $ (12.0 )   $ 14.2

Change in expected rate of return on plan assets:

    

Net periodic pension and OPEB cost

   $ (9.7 )   $ 9.7

Depreciation:  Depreciation expense is determined generally on a straight-line group method over the estimated service lives of depreciable assets for unregulated operations. For regulated utility operations, depreciation expense is determined using a straight-line group method consistent with the development of currently enacted regulatory rates. Under the straight-line group method, plant components are categorized as “retirement units” or “minor items of property.” As retirement units are replaced, the cost of the replacement is capitalized and the original component is retired, and no gain or loss is recognized. Replacements of minor items of property are expensed as maintenance.

 

72


With the assistance of an independent third party, Allegheny completed a review of the estimated remaining service lives and depreciation practices relating to its unregulated generation facilities during the first quarter of 2006. As a result of this review, effective January 1, 2006, Allegheny prospectively extended the depreciable lives of its unregulated coal-fired generation facilities for periods ranging from 5 to 15 years to match the estimated remaining economic lives of these generation facilities. The extension of estimated lives reflected a number of factors, including the physical condition of the facilities, current maintenance practices and planned investments in the facilities. Allegheny also updated its property unit catalog and retirement unit definitions. These changes were considered in estimating the revised depreciation rates.

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

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

 

73


ALLEGHENY ENERGY, INC.—RESULTS OF OPERATIONS

Income (Loss) Summary

 

(In millions)

   Delivery
and
Services
    Generation
and
Marketing
             

2006

       Eliminations     Total  

Operating revenues

   $ 2,717.7     $ 1,834.4     $ (1,430.6 )   $ 3,121.5  

Fuel

     —         842.7       —         842.7  

Purchased power and transmission

     1,773.0       33.2       (1,423.2 )     383.0  

Gain on sale of OVEC power agreement and shares

     —         (6.1 )     —         (6.1 )

Deferred energy costs, net

     7.6       —         —         7.6  

Operations and maintenance

     344.0       349.0       (7.4 )     685.6  

Depreciation and amortization

     151.3       121.8       —         273.1  

Taxes other than income taxes

     122.0       81.3       —         203.3  
                                

Total operating expenses

     2,397.9       1,421.9       (1,430.6 )     2,389.2  

Operating income

     319.8       412.5       —         732.3  

Other income and expenses, net

     22.2       14.8       (3.0 )     34.0  

Interest expense and preferred dividends

     81.4       193.1       (3.0 )     271.5  
                                

Income from continuing operations before income taxes and minority interest

     260.6       234.2       —         494.8  

Income tax expense from continuing operations

     80.2       93.3       —         173.5  

Minority interest in net income of subsidiaries

     —         2.6       —         2.6  
                                

Income from continuing operations

     180.4       138.3       —         318.7  

Income (loss) from discontinued operations, net of tax

     (1.0 )     1.6       —         0.6  
                                

Net income

   $ 179.4     $ 139.9     $ —       $ 319.3  
                                

2005

                        

Operating revenues

   $ 2,845.5     $ 1,703.3     $ (1,510.9 )   $ 3,037.9  

Fuel

     —         759.1       —         759.1  

Purchased power and transmission

     1,878.7       81.0       (1,501.4 )     458.3  

Loss on sale of Ohio T&D assets

     29.3       —         —         29.3  

Deferred energy costs, net

     (1.5 )     —         —         (1.5 )

Operations and maintenance

     388.5       356.2       (9.5 )     735.2  

Depreciation and amortization

     153.6       154.6       —         308.2  

Taxes other than income taxes

     130.4       82.1       —         212.5  
                                

Total operating expenses

     2,579.0       1,433.0       (1,510.9 )     2,501.1  

Operating income

     266.5       270.3       —         536.8  

Other income and expenses, net

     24.2       21.1       (1.1 )     44.2  

Interest expense and preferred dividends

     123.3       318.2       (1.0 )     440.5  
                                

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

     167.4       (26.8 )     (0.1 )     140.5  

Income tax expense from continuing operations

     55.2       9.6       —         64.8  

Minority interest in net income of subsidiaries

     —         0.6       —         0.6  
                                

Income (loss) from continuing operations

     112.2       (37.0 )     (0.1 )     75.1  

Income (loss) from discontinued operations, net of tax

     1.0       (7.2 )     0.1       (6.1 )

Cumulative effect of accounting change, net of tax

     —         (5.9 )     —         (5.9 )
                                

Net income (loss)

   $ 113.2     $ (50.1 )   $ —       $ 63.1  
                                

 

74


(In millions)

   Delivery
and
Services
    Generation
and
Marketing
             

2004

       Eliminations     Total  

Operating revenues

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

Fuel

     —         634.1       —         634.1  

Purchased power and transmission

     1,779.0       86.2       (1,536.8 )     328.4  

Gain on sale of OVEC power agreement and shares

     —         (94.8 )     —         (94.8 )

Deferred energy costs, net

     0.2       —         —         0.2  

Operations and maintenance

     404.3       404.4       (9.9 )     798.8  

Depreciation and amortization

     148.8       150.6       —         299.4  

Taxes other than income taxes

     128.5       72.3       —         200.8  
                                

Total operating expenses

     2,460.8       1,252.8       (1,546.7 )     2,166.9  

Operating income

     303.3       285.9       —         589.2  

Other income and expenses, net

     23.1       1.7       (0.3 )     24.5  

Interest expense and preferred dividends

     129.2       276.2       (0.2 )     405.2  
                                

Income from continuing operations before income taxes and minority interest

     197.2       11.4       (0.1 )     208.5  

Income tax expense (benefit) from continuing operations

     79.9       (0.2 )     —         79.7  

Minority interest in net loss of subsidiaries

     —         (0.9 )     —         (0.9 )
                                

Income from continuing operations

     117.3       12.5       (0.1 )     129.7  

Loss from discontinued operations, net of tax

     (14.0 )     (426.4 )     0.1       (440.3 )
                                

Net income (loss)

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