Annual Reports

 
Quarterly Reports

 
8-K

 
Other

Allegheny Energy 10-K 2010
Form 10-K
Table of Contents

 

 

LOGO

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

  x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) of the SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009

OR

 

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

Commission file number 1-00267

 

 

ALLEGHENY ENERGY, INC.

(Name of Registrant)

 

 

 

Maryland   13-5531602

(State of Incorporation)

800 Cabin Hill Drive, Greensburg,

Pennsylvania

  (IRS Employer Identification Number)
  15601
(Address of Principal Executive Offices)   (Zip Code)

(724) 837-3000

(Telephone Number)

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, par value $1.25 per share   New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a small reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one).

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer     ¨    Smaller reporting company   ¨
(Do not check if a smaller reporting company)     

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

As of December 31, 2009, 169,569,604 shares of the common stock, par value of $1.25 per share, of the registrant were outstanding.

Documents Incorporated by Reference

Portions of the Allegheny Energy, Inc. definitive Proxy Statement for its 2010 Annual Meeting of Stockholders are incorporated by reference to Part III of this Annual Report on Form 10-K.

 

 

 


Table of Contents

GLOSSARY

 

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

 

AE    Allegheny Energy, Inc., a diversified utility holding company
AESC    Allegheny Energy Service Corporation, a subsidiary of AE
AE Supply    Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AGC    Allegheny Generating Company, a generation subsidiary of AE Supply and Monongahela
Allegheny    Allegheny Energy, Inc., together with its consolidated subsidiaries
Distribution Companies    Monongahela, Potomac Edison and West Penn, which collectively do business as Allegheny Power
Monongahela    Monongahela Power Company, a regulated subsidiary of AE
PATH, LLC    Potomac-Appalachian Transmission Highline, LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc.
PATH-Allegheny    PATH Allegheny Transmission Company, LLC
PATH-Allegheny MD    PATH-Allegheny Maryland Transmission Company, LLC
PATH-Allegheny VA    PATH-Allegheny Virginia Transmission Corporation
PATH-WV    PATH West Virginia Transmission Company, LLC
Potomac Edison    The Potomac Edison Company, a regulated subsidiary of AE
TrAIL Company    Trans-Allegheny Interstate Line Company
West Penn    West Penn Power Company, a regulated subsidiary of AE

 

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

 

CDD    Cooling Degree-Days
Clean Air Act    Clean Air Act of 1970
CO2    Carbon dioxide
DOE    United States Department of Energy
EPA    United States Environmental Protection Agency
Exchange Act    Securities Exchange Act of 1934, as amended
FERC    Federal Energy Regulatory Commission, an independent commission within the DOE
FirstEnergy    FirstEnergy Corp.
FPA    Federal Power Act
FTRs    Financial Transmission Rights
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, 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, a unit of electric energy equivalent to one MW operating for one hour
NERC    North American Electric Reliability Corporation
NOx    Nitrogen Oxide
NSR    The New Source Performance Review Standards, or “New Source Review,” applicable to facilities deemed “new” sources of emissions by the EPA
OVEC    Ohio Valley Electric Corporation
PATH    Potomac-Appalachian Transmission Highline
Pennsylvania PUC    Pennsylvania Public Utility Commission
PJM    PJM Interconnection, L.L.C., a regional transmission organization
PLR    Provider-of-last-resort
PURPA    Public Utility Regulatory Policies Act of 1978
RPM    Reliability Pricing Model, which is PJM’s capacity market
RTEP    Regional Transmission Expansion Plan, the process by which PJM identifies transmission system upgrades and enhancements to provide for the operational, economic and reliability requirements of PJM customers.
RTO    Regional Transmission Organization
Scrubbers    Flue-gas desulfurization equipment
SEC    Securities and Exchange Commission
SO2    Sulfur dioxide
SOS    Standard Offer Service
T&D    Transmission and distribution
TrAIL    Trans-Allegheny Interstate Line
Virginia SCC    Virginia State Corporate Commission
West Virginia PSC    Public Service Commission of West Virginia

 

i


Table of Contents

LOGO

 

ii


Table of Contents

CONTENTS

 

Item 1.

  

Business

   1
  

Overview

   1
  

Special Note Regarding Forward-Looking Statements

   9
  

Allegheny’s Sales And Revenues

   11
  

Capital Expenditures

   12
  

Electric Facilities

   13
  

Fuel, Power And Resource Supply

   17
  

Competition

   19
  

Regulatory Framework Affecting Allegheny

   20
  

Environmental Matters

   35
  

Employees

   41
  

Executive Officers

   42

Item 1A.

  

Risk Factors

   43

Item 1B.

  

Unresolved Staff Comments

   55

Item 2.

  

Properties

   56

Item 3.

  

Legal Proceedings

   56

Item 4.

  

Reserved

   58

Item 5.

  

Market For The Registrant’s Common Equity and Related Stockholder Matters

   59

Item 6.

  

Selected Financial Data

   60

Item 7.

  

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

   61

Item 7A.

  

Quantitative And Qualitative Disclosures About Market Risk

   97

Item 8.

  

Financial Statements And Supplementary Data

   98

Item 9.

  

Changes In And Disagreements With Accountants On Accounting And Financial Disclosure

   186

Item 9A.

  

Controls And Procedures

   186

Item 9B.

  

Other Information

   187

Item 10.

  

Directors And Executive Officers

   188

Item 11.

  

Executive Compensation

   188

Item 12.

  

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

   188

Item 13.

  

Certain Relationships And Related Transactions

   188

Item 14.

  

Principal Accountant Fees And Services

   188

Item 15.

  

Exhibits And Financial Statement Schedules

   189

Signatures

   190

 

iii


Table of Contents

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’s operations are organized into two business segments:

 

   

The Merchant Generation segment includes Allegheny’s merchant power generation operations, including the operations of AE Supply and AGC.

 

   

The Regulated Operations segment includes all of Allegheny’s regulated operations, including its electric T&D operations and transmission expansion projects, as well as Monongahela’s power generation operations.

Allegheny changed the composition of its business segments during the fourth quarter of 2009. Prior to the fourth quarter of 2009, Allegheny’s business was comprised of the Generation and Marketing segment and the Delivery and Services segment. The Generation and Marketing segment included the operations of AE Supply and Monongahela’s generating assets. The Delivery and Services segment included the operations of Potomac Edison, West Penn, TrAIL Company, PATH, LLC and Monongahela’s electric T&D business.

The changes in Allegheny’s reportable segments during 2009 consisted primarily of the following:

 

   

Monongahela’s regulated generation operations were moved from the Generation and Marketing segment to the Delivery and Services segment.

 

   

The Generation and Marketing segment was renamed the Merchant Generation segment.

 

   

The Delivery and Services segment was renamed the Regulated Operations segment.

See consolidated financial statement Note 1, “Business, Basis of Presentation and Significant Accounting Policies” and Note 12, “Segment Information.”

Proposed Merger with FirstEnergy

On February 10, 2010, AE, FirstEnergy, and Element Merger Sub, Inc., a direct wholly-owned subsidiary of FirstEnergy (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, and subject to certain terms and conditions, Merger Sub will merge with and into Allegheny (the “Merger”), with Allegheny continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. The merger agreement has been unanimously approved by the boards of directors of both Allegheny and FirstEnergy, but completion of the merger is contingent upon, among other things, the approval of the transaction by shareholders of both companies, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and the receipt of required regulatory approvals. See “Risk Factors” and consolidated financial statement Note 27, “Subsequent Event – Merger Agreement.”

 

1


Table of Contents

The Merchant Generation Segment

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

 

   

AE Supply was formed in Delaware in 1999. AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities. As of December 31, 2009, AE Supply owned or contractually controlled 7,015 MWs of generation capacity. See “Electric Facilities.”

AE Supply markets its electric generation capacity to various customers and markets, including certain of its affiliates, and uses both derivative and nonderivative contracts to manage its portfolio of contracts. AE Supply’s portfolio management and trading activities involve the use of physical commodity inventories and a variety of instruments, such as forward contracts, futures contracts, swap agreements and similar instruments. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated financial statement Note 13, “Fair Value Measurements, Derivative Instruments and Hedging Activities.”

AE Supply currently is contractually obligated to provide West Penn with most of the power that it needs to meet its PLR obligations in Pennsylvania through the end of 2010 and has contracts of varying length with West Penn to serve a portion of its load beyond 2010. In addition, AE Supply has contracts with Potomac Edison to supply most of the power necessary to serve Potomac Edison’s Virginia customers through mid-2011 and is serving a portion of Potomac Edison’s customer load in Maryland pursuant to contracts that range in length from three to 29 months. Together, these contracts currently comprise a majority of AE Supply’s normal operating capacity. AE Supply had total operating revenues of $1.6 billion in 2009.

 

   

AGC was incorporated in Virginia in 1981. As of December 31, 2009, AGC was owned approximately 59% by AE Supply and approximately 41% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC had total operating revenues of $65.8 million in 2009. See “Electric Facilities.”

All of Allegheny’s generation facilities are located within PJM’s competitive wholesale market. AE Supply and Monongahela sell into the PJM market the power that they generate and purchase from the PJM market the power necessary to meet their contractual obligations to supply power. See “Fuel, Power and Resource Supply” and “Regulatory Framework Affecting Allegheny.”

During 2009, the Merchant Generation segment had total operating revenues of $1.6 billion and net income of $234.0 million. As of December 31, 2009, the Merchant Generation segment held approximately $4.3 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated financial statement Note 12, “Segment Information.”

The Regulated Operations Segment

The principal companies and operations in Allegheny’s Regulated Operation’s segment include the following:

 

   

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

 

2


Table of Contents
   

Monongahela was incorporated in Ohio in 1924. It conducts an electric T&D business that serves approximately 383,600 customers in northern West Virginia in a service area of approximately 13,000 square miles with a population of approximately 779,000. Monongahela sold 10 million MWhs of electricity to retail customers in 2009.

Monongahela also owns generation assets, which are included in the Regulated Operations segment. As of December 31, 2009, Monongahela owned or contractually controlled 2,741 MWs of generation capacity. Monongahela’s generation capacity supplies its electric T&D business. In addition, Monongahela is contractually obligated to provide Potomac Edison with the power that it needs to meet its load obligations in West Virginia. Monongahela had total operating revenues of $695.2 million in 2009. See “Electric Facilities.”

 

   

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 483,400 customers in a service area of about 7,500 square miles with a population of approximately 1.06 million. Potomac Edison had total operating revenues of $832.6 million and sold 12.8 million MWhs of electricity to retail customers in 2009. In May 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative for cash proceeds of approximately $340 million, subject to certain closing conditions. Allegheny serves approximately 102,000 customers in northern Virginia. See “Regulatory Framework Affecting Allegheny,” “Risk Factors” and consolidated financial statement Note 3, “Assets Held for Sale.”

 

   

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 714,900 customers in a service area of about 10,400 square miles with a population of approximately 1.6 million. West Penn had total operating revenues of $1.4 billion and sold 19.2 million MWhs of electricity to retail customers in 2009.

 

   

TrAIL Company was incorporated in Maryland and Virginia in 2006. In June 2006, PJM, which manages a regional planning process for transmission expansion, approved an RTEP designed to maintain the reliability of the transmission grid in the mid-Atlantic region. The transmission expansion plan includes TrAIL, a new 500 kV transmission line that will extend from southwestern Pennsylvania through West Virginia to a point of interconnection with Virginia Electric and Power Company, a subsidiary of Dominion Resources, in northern Virginia. 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 build, own and operate the new transmission line. TrAIL Company currently expects to complete construction of the new line in 2011. See “Capital Expenditures” and “Regulatory Framework Affecting Allegheny.”

 

   

PATH, LLC was formed in Delaware in 2007 following PJM approval of PATH. As currently proposed, PATH is a new, 765 kV transmission line that will extend from a substation owned by American Electric Power Company (“AEP”) near St. Albans, West Virginia, to a new substation near Kemptown, Maryland. PATH, LLC, which was formed in connection with the management and financing of this project (the “PATH Project”), is a series limited liability company. The “West Virginia Series” is owned equally by Allegheny and a subsidiary of AEP. The “Allegheny Series” is 100% owned by Allegheny. Each Series will, through an operating subsidiary, build, own and operate a portion of the line. Construction of the line remains subject to siting approval by the relevant state utility commissions, among other matters. In December 2009, PJM conducted certain sensitivity analyses that suggest that PATH may not be required by June 2014, as had been anticipated, to address congestion and reliability concerns and, therefore, will be considered in its 2010 RTEP. See “Capital Expenditures” and “Regulatory Framework Affecting Allegheny.”

 

3


Table of Contents

During 2009, the Regulated Operations segment had operating revenues of $3.1 billion and net income of $157.9 million. As of December 31, 2009, the Regulated Operations segment held approximately $7.3 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated financial statement Note 12, “Segment Information.”

Shared Services

AESC was incorporated in Maryland in 1963 and is a service company for Allegheny. AESC employs substantially all of the Allegheny personnel who provide services to AE and its subsidiaries, including among others, AE Supply, AGC, the Distribution Companies, TrAIL Company, PATH, LLC and their respective subsidiaries. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had 4,383 employees as of December 31, 2009.

Certain Recent Initiatives and Developments

Throughout 2009, Allegheny’s strategy has been to focus on its core generation and expanding transmission business, which management believes is enabling Allegheny to take advantage of its regional presence, operational expertise and knowledge of its markets to add shareholder value, despite challenging regulatory, market and overall economic conditions. Significant initiatives and developments include, among others:

 

   

Transmission Expansion. In June 2006, PJM approved an RTEP designed to maintain the reliability of the transmission grid in the mid-Atlantic region that included TrAIL, and in June 2007, PJM authorized the construction of PATH. Although PJM currently is reevaluating the date by which PATH may be required to address NERC reliability requirements, in general these lines are intended to alleviate future reliability concerns and increase the west to east transmission capability of the PJM system. PJM designated Allegheny to construct the portion of TrAIL that is located in the Distribution Companies’ PJM zone, and Allegheny and a subsidiary of AEP formed PATH, LLC to construct PATH. FERC, which has jurisdiction over rates for the transmission of electric power, has approved incentive rate treatment for both TrAIL and PATH, including incentive rates of return on equity, returns on construction work in progress and recovery of prudently incurred development and construction costs in the event that construction of either line is abandoned for reasons beyond Allegheny’s control.

Primary jurisdiction for approval of the siting and construction of transmission lines lies with the state public utility commission in the states in which the lines are proposed to be located. Applications for approval of PATH are pending in West Virginia and Maryland, but a similar request in Virginia was recently withdrawn on the basis of certain PJM analyses suggesting that PATH may not be required until some time beyond the originally anticipated 2014 target completion date. TrAIL Company received the requisite state utility commission approvals to construct TrAIL in Pennsylvania, West Virginia and Virginia in 2008, and construction of TrAIL is currently underway. At this time, overall TrAIL-related substation work is nearly 90% complete and tower construction is underway. TrAIL Company has obtained nearly 80% of the rights-of-way necessary to construct TrAIL and all significant construction and material contracts necessary to complete TrAIL.

Allegheny has also taken steps in recent years to enhance the performance and reliability of its transmission system. For example, in 2007, Trail Company completed the installation of a new static volt-ampere reactive power compensator at the Black Oak substation (the “Black Oak SVC”) that is designed to enhance the reliability of Allegheny’s high-voltage Black Oak-Beddington transmission line, which is one of the most congested lines in the PJM region, and increase transmission capacity across the PJM region. TrAIL Company was granted an incentive rate of return on equity by FERC for the Black Oak SVC. TrAIL Company has also undertaken upgrades or replacements of transformers, buses or both at seven other substations and is constructing a new transmission operations center in West Virginia that it expects to complete during 2010. Allegheny has also identified various other transmission enhancement opportunities, some of which may be subject to PJM’s RTEP process. See

 

4


Table of Contents

“Capital Expenditures,” “Regulatory Framework Affecting Allegheny,” “Risk Factors,” and consolidated financial statement Note 5, “Transmission Expansion.”

 

   

Liquidity Enhancement, Investment Grade Status and Reinstatement of Common Stock Dividend. In 2007, following a period of financial difficulty and recovery, Allegheny achieved a significant milestone with the upgrade to investment grade status of its corporate credit ratings by all three major credit rating agencies and the reinstatement of AE’s common stock dividend, as well as subsequent upgrades to investment grade status of the unsecured debt ratings of AE Supply and Monongahela. Additionally, TrAIL Company received inaugural investment grade ratings for its unsecured debt from all three major rating agencies.

As widely reported, the financial markets and overall economies in the United States and abroad are currently experiencing a period of significant uncertainty that began in mid to late 2008 and has negatively affected overall market liquidity and access to credit. In spite of these prevailing economic conditions, Allegheny has maintained its investment grade credit ratings and has succeeded in enhancing its overall liquidity. During 2009 and the first part of 2010, Allegheny refinanced and extended the maturities of certain existing debt, while also obtaining favorable transmission-related financing.

Specifically, in the third quarter of 2009, AE Supply issued $600 million aggregate principal amount of senior unsecured notes, consisting of $350 million of 5.75% Notes due 2019 and $250 million of 6.75% Notes due 2039, and obtained a new $1 billion senior secured revolving credit facility that matures in 2012. The new revolving credit facility replaced AE Supply’s previous $400 million revolving credit facility that would have matured in 2011 and, in combination with the proceeds of the note offering, allowed AE Supply to repay its existing $447 million term loan, which also would have matured in 2011, and to complete tender offers for a total of $249.5 million in 7.8% Medium Term Notes due 2011 and $146.8 million of 8.25% Medium Term Notes due 2012.

Also in 2009, AE Supply, in conjunction with the Pennsylvania Economic Development Authority, completed a tax exempt transaction that resulted in proceeds of approximately $235 million to finance a portion of the costs to install the Scrubbers at the Hatfield’s Ferry generating facility. Additionally, in December 2009, subsidiaries of Monongahela and Potomac Edison completed an $86 million securitization transaction to finance the remaining costs to complete the installation of the Scrubbers at the Fort Martin generating facility, and Monongahela entered into a new, $110 million senior unsecured revolving credit facility. Finally, in January 2010, TrAIL Company refinanced its existing construction loan through the issuance of $450 million aggregate principal amount of 4.0% senior unsecured notes due 2015 and obtained a new, $350 million unsecured revolving credit facility that matures in 2013.

In addition to these transactions, Allegheny continues to take other steps, such as proactively managing and controlling operations and maintenance expense and otherwise prudently managing cash, to maintain and improve its liquidity position. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and consolidated financial statement Note 8, “Capitalization and Debt.”

 

   

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

During the latter part of 2009, Allegheny completed a significant, multi-year effort to install Scrubbers at its Fort Martin and Hatfield’s Ferry generating facilities. Now in-service, the Scrubbers will reduce overall SO2 emissions at these two facilities by more than 95%. In addition to this initiative, Allegheny completed the elimination of a partial Scrubber bypass at its Pleasants generating facility in 2007 and is currently evaluating pollution control projects at other facilities. Although applicable environmental regulations and initiatives, including but not limited to air and water quality issues and climate change concerns, continue to present Allegheny with significant challenges, all of Allegheny’s supercritical coal

 

5


Table of Contents

generating units are scrubbed and a significant amount of SO2 and mercury emissions have been eliminated. See “Risk Factors,” “Capital Expenditures” and “Environmental Matters.”

 

   

Energy Efficiency and Conservation. Through its Watt Watchers program introduced in 2007, Allegheny has implemented a number of programs to encourage energy efficiency and conservation among its customers, in addition to its long-standing portfolio of existing energy conservation programs.

Recently, Allegheny has undertaken initiatives in response to Pennsylvania’s Act 129 and Maryland’s EmPOWER Maryland program, both of which establish demand-side reduction goals and required, among other things, that affected utilities file with the relevant state utility commissions specific plans describing the demand-side management programs that they propose to implement in order to reach those goals, as well as separate plans for the implementation of advanced, or “smart,” metering. During 2009, the Maryland PSC approved and provided for cost recovery with respect to, Potomac Edison’s proposed demand-side management programs in Maryland, and the Pennsylvania PUC largely approved West Penn’s proposed portfolio of energy efficiency and conservation programs. In both Maryland and Pennsylvania, Allegheny’s proposed advanced infrastructure and metering proposals remain subject to regulatory review.

Other conservation initiatives include, for example, Allegheny’s partnership with Energy Star®, the EPA’s voluntary market-based program to reduce greenhouse gasses through energy efficiency and its proposal to offer a voluntary wind energy program to customers in Pennsylvania. Allegheny continues to explore other programs through which customers can purchase electricity from renewable sources, and in December 2009, purchased an additional 13 MW of hydroelectric generation. Allegheny is also developing a number of other new programs for customers that it believes can help drive energy efficiency and conservation, such as opportunities for home energy audits. See “Regulatory Matters Affecting Allegheny.”

 

   

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

In 2005, Allegheny 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. Although the Pennsylvania state legislature has, at times, debated their extension, the rate caps applicable to Allegheny’s Pennsylvania customers remain scheduled to expire at the end of 2010. West Penn conducted auctions in April, June and October 2009 and in January 2010 to purchase a portion of the power required to serve its customers in Pennsylvania beginning on January 1, 2011. West Penn now has contracts for approximately 67% of the power needed to serve its residential customers, and nearly half of the power needed to serve its small and mid-sized nonresidential customers, in 2011, resulting in only modest expected increases in customer bills. Assuming that average prices for the remaining auctions remain the same as the average of the first four auctions, the result would be an increase in the typical West Penn residential customer’s bill of 8.5%, assuming usage of 1,000 kWh per month, and increases of only 0.6% and 2.0% for small and mid-sized nonresidential customers, respectively, in 2011 as compared to 2010.

Potomac Edison’s Maryland residential customers currently can participate in a Maryland PSC-approved transition plan. Residential customers who did not opt out of the plan began paying a surcharge in June 2007 that, with the expiration of residential rate caps and the move to market-based rates on January 1, 2009, converted to a credit on customers’ bills, such that funds collected via the surcharge in 2007 and 2008 are being returned to customers to mitigate the effect of the rate cap

 

6


Table of Contents

expiration until December 2010 or such time as all amounts collected through the surcharge, plus interest, are returned to customers.

AE Supply is serving a portion of Potomac Edison’s Maryland customers pursuant to contracts that range in length from three to 29 months. Potomac Edison also has contracts with AE Supply to supply most of the power necessary to serve Potomac Edison’s Virginia customers through mid-2011. These contracts were awarded to AE Supply as a result of competitive bidding processes in both Virginia and Maryland. Suppliers that are not affiliated with Potomac Edison also were awarded contracts for portions of Potomac Edison’s Virginia and Maryland load pursuant to the competitive bidding process. In Maryland, Potomac Edison will conduct rolling auctions to procure its power supply. The arrangements to serve Potomac Edison’s load obligations in Virginia after July 1, 2011 are still under development. See “Competition,” “Regulatory Matters Affecting Allegheny,” “Risk Factors” and consolidated financial statement Note 4, “Rates and Regulation.”

 

   

Cost Recovery. In addition to its efforts to manage the transition to market-based generation rates, Allegheny is working to achieve full recovery of its costs and a reasonable rate of return through the traditional rate-making process. In November 2008, following a protracted dispute over Potomac Edison’s ability to recover purchased power costs, the Virginia SCC approved a settlement allowing Potomac Edison to transition all of its Virginia customers to rates that would allow for full recovery of purchased power costs no later than July 2011, and the Virginia SCC separately approved a transmission rate adjustment related to third party transmission costs and a rate increase to recover purchased power costs in 2009.

In West Virginia, a base rate case by which Monongahela and Potomac Edison propose to increase retail rates by approximately $106 million beginning in June 2010 is under review by the West Virginia PSC. Additionally, in December 2009, the West Virginia PSC approved a settlement with respect to annual fuel adjustments for Monongahela and Potomac Edison providing for an aggregate increase of $118 million, effective January 1, 2010, plus deferred recovery of an additional $23.1 million. See “Regulatory Matters Affecting Allegheny,” “Risk Factors” and consolidated financial statement Note 4, “Rates and Regulation.”

 

   

Customer Satisfaction. Allegheny continues to see high levels of satisfaction among its customers. For example, a leading independent survey firm has ranked Allegheny first in commercial and industrial satisfaction in the northeastern United States for the last five consecutive years, and another firm ranked Allegheny in the top quartile nationally for residential customer satisfaction.

 

   

Virginia Asset Sale. On May 4, 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative (together, the “Cooperatives”) for cash proceeds of approximately $340 million, subject to state and federal regulatory approval, certain third-party consents and applicable price adjustments. On September 15, 2009, Potomac Edison and the Cooperatives filed with the Virginia SCC a joint request for approval of the transaction. The Virginia SCC issued a procedural order scheduling an evidentiary hearing on the matter for March 2, 2010. See “Regulatory Matters Affecting Allegheny” and consolidated financial statement Note 3, “Assets Held for Sale.”

 

7


Table of Contents

Where You Can Find More Information

AE files or furnishes Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and other information with or to the SEC. You may read and copy any document that AE files with the SEC at the SEC’s public reference room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. These SEC filings are also available to the public from the SEC’s website 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 files with or furnishes 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. AE’s website and the information contained therein are not incorporated into this report.

 

8


Table of Contents

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. Forward-looking information often may be identified by the use of 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. However, the absence of these or similar words does not mean that any particular statement is not forward-looking. Forward-looking statements herein may relate to, among other matters:

 

   

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

 

   

financing plans;

 

   

market demand and prices for energy, capacity, coal and natural gas;

 

   

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

 

   

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

 

   

Allegheny’s proposed merger with FirstEnergy.

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:

 

   

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

 

   

plant performance and unplanned outages;

 

   

volatility and changes in the price and demand for energy and capacity and changes in the value of FTRs;

 

   

volatility and changes in the price of coal, natural gas and other energy-related commodities, as well as transportation costs;

 

   

Allegheny’s ability to enter into, modify and enforce long term fuel purchase agreements;

 

   

the effectiveness of Allegheny’s risk management policies and procedures;

 

   

the ability and willingness of counterparties to satisfy their financial and performance obligations;

 

   

changes in the weather and other natural phenomena;

 

   

changes in Allegheny’s requirements for, and the availability and price of, emission allowances;

 

   

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

 

   

changes in market rules, including changes to PJM’s participant rules and tariffs, and defaults by other market participants;

 

9


Table of Contents
   

the loss of any significant customers or suppliers;

 

   

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

 

   

the impact of government-mandated energy consumption initiatives, as well as general trends in resource conservation;

 

   

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

 

   

the reliability of Allegheny’s own system and its ongoing compliance with NERC reliability standards;

 

   

environmental regulations;

 

   

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

 

   

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

 

   

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

 

   

entry into, any failure to consummate, or any delay in the consummation of, contemplated asset sales or other strategic transactions;

 

   

the likelihood and timing of the completion of the proposed merger with FirstEnergy, the terms and conditions of any required regulatory approvals of the proposed merger, the impact of the proposed merger on Allegheny’s employees and potential diversion of management’s time and attention from ongoing business during this time period;

 

   

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

 

   

recent and any future disruptions in the financial markets and changes in access to capital markets;

 

   

the availability of credit;

 

   

actions of rating agencies;

 

   

inflationary or deflationary trends and interest rate trends;

 

   

general economic and business conditions, including the effects of the current recession; and

 

   

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

For a more detailed discussion of certain risk factors affecting Allegheny’s risk profile, see “Risk Factors.”

 

10


Table of Contents

ALLEGHENY’S SALES AND REVENUES

Merchant Generation

The Merchant Generation segment generated 26,004 million kWhs and 34,464 million kWhs of electricity in 2009 and 2008, respectively. The segment’s revenues were composed of the following:

 

Revenues (in millions)

   2009    2008  

PJM energy revenue

   $ 936.5    $ 1,913.1   

PJM capacity revenue

     356.2      195.2   

Power hedge revenues

     213.5      (363.8

Other

     102.4      48.4   
               

Total operating revenues

   $ 1,608.6    $ 1,792.9   
               

Regulated Operations

The Regulated Operations segment sold 42,040 million kWhs and 44,192 million kWhs of electricity to retail customers in 2009 and 2008, respectively. The segment’s operating revenues were composed of the following:

 

Revenues (in millions)

   2009     2008  

Retail electric:

    

Generation and ancillary

   $ 2,280.0      $ 1,902.7   

Transmission

     118.6        124.2   

Distribution

     661.7        675.1   
                

Total retail electric

     3,060.3        2,702.0   

Transmission services and bulk power:

    

PJM revenue, net

     (198.8     (34.2

Warrior Run generation revenue

     52.7        86.0   

Transmission and other

     100.1        73.3   
                

Total transmission Services and bulk power

     (46.0     125.1   

Other

     36.9        28.2   
                

Total operating revenues

   $ 3,051.2      $ 2,855.3   
                

For more information regarding each segment’s revenues and operating results, as well as intersegment revenues and costs eliminated in Allegheny’s consolidated financial statements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated financial statement Note 12, “Segment Information.”

 

11


Table of Contents

CAPITAL EXPENDITURES

Actual capital expenditures for 2009 and estimated capital expenditures for 2010 and 2011 are shown on a cash basis in the following table. The amounts and timing of capital expenditures are subject to continuing review and adjustment, and actual capital expenditures may vary from these estimates.

 

     Actual    Projected

(in millions)

   2009 (a)    2010    2011

Transmission and distribution facilities:

        

TrAIL and related transmission expansion (b)

   $ 455.4    $ 358.9    $ 95.4

PATH Project (c)

     43.7      21.3      23.8

Other transmission and distribution facilities

     216.1      402.7      340.7
                    

Total transmission and distribution facilities

     715.2      782.9      459.9

Environmental:

        

Fort Martin Scrubbers (d)

     160.7      34.0      —  

Hatfield Scrubbers (d)

     135.2      21.0      —  

Other

     39.0      97.0      158.5
                    

Total environmental

     334.9      152.0      158.5

Other generation facilities

     81.6      100.0      58.7

Other capital expenditures

     20.5      46.0      19.1
                    

Total capital expenditures

   $ 1,152.2    $ 1,080.9    $ 696.2
                    

 

(a) For more information, see consolidated financial statement Note 12, “Segment Information.”
(b) TrAIL has a target completion date of 2011 and an estimated cost of approximately $850 million. TrAIL Company is also engaged in other transmission projects.
(c) Excludes capital expenditures related to AEP’s portion of the West Virginia Series of PATH, LLC, which were $14.1 million in 2009. Allegheny’s share of the total cost of the project is estimated at $1.2 billion. The revised in-service date for PATH is expected to be determined in PJM’s 2010 RTEP.
(d) The installation of Scrubbers at both the Fort Martin and Hatfield’s Ferry generating stations was completed in 2009.

The foregoing table does not include certain other potential capital projects the need or regulatory mandate for which currently may be uncertain, including but not limited to additional transmission investment opportunities, some of which will be subject to the PJM RTEP process, and costs that Allegheny could incur in connection with the installation of certain additional pollution control equipment at its generating facilities.

 

12


Table of Contents

ELECTRIC FACILITIES

Generation Capacity

Allegheny’s owned or controlled generation capacity, other than the capacity owned and controlled by Monongahela, is included in the Merchant Generation segment. Monongahela’s generation is included in the Regulated Operations segment.

Nominal Maximum Operational Generation Capacity

 

Stations

  Units   Total
MW
  Merchant Generation
Segment (MW)
  Regulated Operations
Segment (MW)
  Commencement
Dates (a)

Supercritical Coal Fired (Steam):

         

Harrison (Haywood, WV)

  3   1,983   1,576   407   1972-74

Hatfield’s Ferry (Masontown, PA)

  3   1,710   1,710     1969-71

Pleasants (Willow Island, WV)

  2   1,300   1,200   100   1979-80

Fort Martin (Maidsville, WV)

  2   1,107     1,107   1967-68

Other Coal Fired (Steam):

         

Armstrong (Adrian, PA)

  2   356   356     1958-59

Albright (Albright, WV)

  3   292     292   1952-54

Mitchell (Courtney, PA)

  1   288   288     1963

Willow Island (Willow Island, WV)

  2   243     243   1949-60

Rivesville (Rivesville, WV)

  2   130     130   1943-51

R. Paul Smith (Williamsport, MD)

  2   116   116     1947-58

OVEC (Chelsea, OH) (Madison, IN) (b)

  11   78   67   11  

Pumped-Storage and Hydro:

         

Bath County (Warm Springs, VA) (c)

  6   1,109   658   451   1985; 2001

Lake Lynn (Lake Lynn, PA) (d)

  4   52   52     1926

Allegheny Lock & Dam 5 (Freeport, PA) (e)

  2   6   6     1987

Allegheny Lock & Dam 6 (Freeport, PA) (e)

  2   7   7     1989

Green Vally Hydro (f)

  21   6   6     Various

Gas Fired:

         

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

  3   540   540     2003

AE Nos. 1 & 2 (Springdale, PA)

  2   88   88     1999

AE Nos. 8 & 9 (Gans, PA)

  2   88   88     2000

AE Nos. 12 & 13 (Chambersburg, PA)

  2   88   88     2001

Buchanan (Oakwood, VA) (g)

  2   43   43     2002

Hunlock CT (Hunlock Creek, PA)

  1   44   44     2000

Oil-Fired (Steam):

         

Mitchell (Courtney, PA)

  1   82   82     1949
               

Total Capacity

    9,756   7,015   2,741  
               

 

(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) The amount attributed to OVEC represents capacity entitlement through AE’s ownership of OVEC shares. AE holds a 3.5% equity stake in, and is a sponsoring company of, OVEC. OVEC supplies power to its sponsoring companies under an intercompany power agreement.

 

13


Table of Contents
(c) This figure represents capacity entitlement through ownership of AGC.
(d) AE Supply has a license for Lake Lynn through 2024.
(e) AE Supply purchased hydroelectric generation facilities at Allegheny Lock and Dam Nos. 5 & 6 in December 2009. See consolidated financial statement Note 14, “Purchase of Hydroelectric Generation Facilities.”
(f) The licenses for Green Valley hydroelectric facilities Dam No. 4 and Dam No. 5, located in West Virginia and Maryland, will expire in November 2024. The licenses for the Shenandoah, Warren, Luray and Newport projects located in Virginia run through 2024.
(g) Buchanan Energy Company of Virginia, LLC (“Buchanan”) is a subsidiary of AE Supply. CNX Gas Corporation and Buchanan have equal ownership interests in Buchanan Generation LLC (“Buchanan Generation”). AE Supply operates and dispatches 100% of Buchanan Generation’s 86 MWs.

PURPA Capacity

The following table shows generation capacity, in addition to that reflected in the table above, that is 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, although 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. The capacity purchases reflected in this table are reflected in the results of the Regulated Operations segment.

 

     PURPA Capacity (MW)     

PURPA Stations (a)

   Project
Total
   Monongahela    Potomac
Edison
   West
Penn
   Contract
Termination
Date

Coal Fired (Steam)

              

AES Warrior Run (Cumberland, MD) (b)

   180       180       2030

AES Beaver Valley (Monaca, PA)

   125          125    2016

Grant Town (Grant Town, WV)

   80    80          2036

West Virginia University (Morgantown, WV)

   50    50          2027

Hydro:

              

Hannibal Lock and Dam (New Martinsville, WV)

   31    31          2034
                      

Total PURPA Capacity

   466    161    180    125   
                      

 

(a) AE Supply purchased hydroelectric generating facilities at Allegheny Lock and Dam Nos. 5 & 6, previously PURPA stations with generating capacity of 13 MW, in December 2009.
(b) As required under the terms of a Maryland restructuring settlement, Potomac Edison offers the 180 MW output of the AES Warrior Run project to the wholesale market and will continue to do so for the term of the AES Warrior Run contract, which ends on February 10, 2030. Revenue received from the sale reduces the AES Warrior Run surcharge paid by Maryland customers.

 

14


Table of Contents

Transmission and Distribution Facilities

The following table sets forth the existing miles of T&D lines and the number of substations of the Distribution Companies and AGC as of December 31, 2009:

 

     Underground    Above-
Ground
   Total
Miles
   Total Miles
Consisting of
500-Kilovolt
(kV) Lines
   Number of
Transmission and
Distribution
Substations

Monongahela

   923    24,244    25,167    250    242

Potomac Edison

   5,443    19,671    25,114    176    225

West Penn

   3,047    25,927    28,974    276    507

AGC (a)

   —      87    87    87    1
                        

Total

   9,413    69,929    79,342    789    975
                        

 

(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.

 

15


Table of Contents

LOGO

 

16


Table of Contents

FUEL, POWER AND RESOURCE SUPPLY

Coal Supply

Allegheny primarily uses Northern Appalachian coal at its coal-fired generating facilities. Most of Allegheny’s coal purchase agreements contain specified prices and include price adjustment provisions related to changes in specified cost indices, as well as to specific events, such as changes in regulations that affect the coal industry.

Developments and operational factors affecting Allegheny’s coal suppliers, including increased costs, transportation constraints, safety issues and operational difficulties, may have negative effects on coal supplier performance. Additionally, Allegheny has experienced, and may continue to experience, increases in other fuel-related costs, such as its fuel handling and transportation costs and its costs to procure lime, urea and other materials necessary to the operation of its pollution control equipment. Furthermore, while the longer-term contracts that AE Supply and Monongahela have in place are intended to partially mitigate Allegheny’s exposure to negative fluctuations in coal prices, in some cases, those contracts may require that AE Supply and Monongahela purchase a minimum volume of coal over a given time period. During 2009, as a result of falling demand and market prices for power, Allegheny’s coal consumption decreased significantly, and it was required at times to purchase coal in excess of immediate needs, resulting in coal inventories at some of its facilities that exceed what it considers to be optimal levels. See “Risk Factors.”

Merchant Generation. AE Supply consumed approximately 10.1 million tons of coal in 2009 at an average price of approximately $54.87 per ton delivered. Allegheny purchased these fuels primarily from mines in Pennsylvania, West Virginia and Ohio. However, Allegheny also purchases coal from other regions, and blends coal from the Powder River Basin with eastern bituminous coal at one of its generating facilities.

Historically, AE Supply has purchased a majority of its coal from a limited number of suppliers. Of AE Supply’s coal purchases in 2009, 67% came from subsidiaries of four companies, the largest of which represented 24% of the total tons purchased.

As of February 19, 2010, AE Supply had commitments for the delivery of more than 98% of the coal that AE Supply expects to consume in 2010. Excluding volumes that are priced annually based on market conditions, AE Supply also had commitments for the delivery of approximately 65% of its anticipated coal needs for 2011 and for approximately 59%, 54% and 50% of its anticipated coal needs for 2012, 2013 and 2014, respectively.

Regulated Operations. Monongahela consumed approximately 3.1 million tons of coal in 2009 at an average price of approximately $60.91 per ton delivered. Monongahela purchased these fuels primarily from mines in Pennsylvania, West Virginia and Ohio. However, Monongahela also purchases coal from other regions, and blends coal from the Powder River Basin with eastern bituminous coal at several generating facilities.

Historically, Monongahela has purchased a majority of its coal from a limited number of suppliers. Of Monongahela’s coal purchases in 2009, 76% came from subsidiaries of three companies, the largest of which represented 28% of the total tons purchased.

As of February 19, 2010, Monongahela had commitments for the delivery of more than 98% of the coal that Monongahela expects to consume in 2010. Excluding volumes that are priced annually based on market conditions, Monongahela also had commitments for the delivery of approximately 58% of its anticipated coal needs for 2011 and for approximately 46%, 44% and 41% of its anticipated coal needs for 2012, 2013 and 2014, respectively.

Natural Gas Supply

AE Supply purchases natural gas to supply its natural gas-fired generation facilities. In 2009, AE Supply purchased its natural gas requirements principally in the spot market.

 

17


Table of Contents

AE Supply has an agreement under a FERC-approved tariff with Kern River Gas Transmission Company for the firm transportation of 45,122 decatherms of natural gas per day from Opal, Wyoming to southern California. The transportation agreement runs through April 30, 2018. AE Supply is managing this obligation through monthly financial basis swaps and the concomitant purchase and sale of physical natural gas.

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. Effective as of January 1, 2007, Monongahela and AE Supply completed an intra-company transfer of assets that realigned generation ownership and contractual obligations within the Allegheny system (the “Asset Swap”). See “Regulatory Framework Affecting Allegheny.”

Pennsylvania instituted retail customer choice in 1996 and is transitioning to market-based, rather than cost-based pricing for generation. West Penn is the PLR for those Pennsylvania customers who do not choose an alternate supplier or whose alternate supplier does not deliver or who choose to return to West Penn service, in each case at rates that are capped at various levels through the end of the transition period. Currently, West Penn’s transition period will end on December 31, 2010. AE Supply is contractually obligated to provide West Penn with most of the power that it needs to meet its PLR obligations in Pennsylvania through the end of the transition period. In July 2008, the Pennsylvania PUC approved West Penn’s proposed power procurement plan pursuant to which West Penn has begun to procure its post-transition period power requirements through a combination of competitively bid contracts and spot market purchases.

Potomac Edison has contracts with AE Supply to supply most of the power necessary to serve Potomac Edison’s Virginia customers through mid-2011. AE Supply also is serving a portion of Potomac Edison’s Maryland customers pursuant to contracts that range in length from three to 29 months. These contracts were awarded to AE Supply as a result of competitive bidding processes in both Virginia and Maryland. Suppliers that are not affiliated with Potomac Edison also were awarded contracts for portions of Potomac Edison’s Virginia and Maryland load pursuant to the competitive bidding process. In Maryland, Potomac Edison will conduct rolling auctions to procure its power supply. In May 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative, subject to certain closing conditions. See “Business – Overview,” “Risk Factors,” and consolidated financial statement Note 3, “Assets Held for Sale.”

Prior to January 1, 2007, AE Supply 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 through 2027. 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, including its obligations to supply power to Potomac Edison.

 

18


Table of Contents

COMPETITION

Each of the states in Allegheny’s service territory, other than West Virginia has, to some extent, taken steps to deregulate its electric utility industry, although Virginia has essentially reversed deregulation plans. Pennsylvania and Maryland instituted customer choice and are transitioning to market-based, rather than cost-based pricing for generation. Virginia undertook to deregulate the provision of generation services beginning in 1999, but subsequent legislation resulted in the re-regulation of these services in January 2009 for most customers.

In 2005, Allegheny 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. Although the Pennsylvania state legislature has, at times, debated their extension, the rate caps applicable to Allegheny’s Pennsylvania customers remain scheduled to expire at the end of 2010. West Penn conducted auctions in April, June and October 2009 and January 2010 to purchase a portion of the power required to serve its customers in Pennsylvania beginning on January 1, 2011. In the April 2009 auction, AE Supply was awarded 17-month and 29-month residential contracts representing approximately 2 million megawatt-hours of generation supply. In the June 2009 auction, AE Supply was awarded two non-residential contracts to deliver a total of approximately 700,000 megawatt-hours of generation supply over a 17-month period. In the October 2009 auction, AE Supply was awarded 17-month and 29-month residential contracts and three 17-month non-residential contracts to deliver a total of 1.8 million megawatt-hours of generation supply.

AE Supply is serving a portion of Potomac Edison’s Maryland customers pursuant to contracts that range in length from three to 29 months. Potomac Edison also has contracts with AE Supply to supply most of the power necessary to serve Potomac Edison’s Virginia customers through mid-2011. These contracts were awarded to AE Supply as a result of competitive bidding processes in both Virginia and Maryland. Suppliers that are not affiliated with Potomac Edison also were awarded contracts for portions of Potomac Edison’s Virginia and Maryland load pursuant to the competitive bidding process. In Maryland, Potomac Edison will conduct rolling auctions to procure its power supply. The arrangements to serve Potomac Edison’s load obligations in Virginia after July 1, 2011 are still under development. In May 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia for cash proceeds of approximately $340 million, subject to state and federal regulatory approval, certain third-party consents and applicable price adjustments. See “Regulatory Framework Affecting Allegheny,” “Risk Factors,” consolidated financial statement Note 3, “Assets Held for Sale” and Note 4, “Rates and Regulation.”

 

19


Table of Contents

REGULATORY FRAMEWORK AFFECTING ALLEGHENY

The interstate transmission services and wholesale power sales of the Distribution Companies, TrAIL Company, PATH, LLC, 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. In addition, Allegheny is subject to numerous other local, state and federal laws, regulations and rules. See “Risk Factors.”

Federal Regulation and Rate Matters

FERC, Competition and RTOs

Allegheny’s generation and transmission businesses are significantly influenced by the actions of FERC through policies, regulations and orders issued pursuant to the FPA. The FPA gives FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales and transmission of electricity in interstate commerce. Entities, such as the Distribution Companies, TrAIL Company, the operating subsidiaries of PATH, LLC, AE Supply and AGC, that sell electricity at wholesale or own transmission facilities are subject to FERC jurisdiction and must file their rates, terms and conditions for such sales with FERC. Rates for wholesale sales of electricity may be either cost-based or market-based. Rates for use of transmission facilities are determined on a cost basis.

FERC’s authority under the FPA, as it pertains to Allegheny’s generation and transmission businesses, also includes, but is not limited to: licensing of hydroelectricity projects; transmission interconnections with other electric facilities; transfers of public utility property; mergers, acquisitions and consolidation of public utility systems and companies; issuance of certain securities and assumption of certain liabilities; accounting and methods of depreciation; transmission reliability; siting of certain transmission facilities; allocation of transmission rights; relationships between holding companies and their public utility affiliates; availability of books and records; and holding of a director or officer position at more than one public utility or specified company.

FERC’s policies, regulations and orders encourage competition among wholesale sellers of electricity. To support competition, FERC requires public utilities that own transmission facilities to make such facilities available on a non-discriminatory, open-access basis and to comply with standards of conduct that prevent transmission-owning utilities from giving their affiliated sellers of electricity preferential access to the transmission system and transmission information. To further competition, FERC encourages transmission-owning utilities to participate in regional transmission organizations (“RTOs”) such as PJM, by transferring functional control over their transmission facilities to RTOs.

All of Allegheny’s generation assets and power supply obligations are located within the PJM market, and PJM maintains functional control over the transmission facilities owned by the Distribution Companies and TrAIL Company. PJM operates a competitive wholesale electricity market and coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PJM is also responsible for developing and implementing the RTEP for the PJM region to ensure reliability of the electric grid and promote market efficiency. In addition, PJM determines the requirements for, and manages the process of, interconnecting new and expanded generation facilities to the grid. Changes in the PJM tariff, operating agreement, policies and/or market rules could adversely affect Allegheny’s financial results. See “Risk Factors.”

Transmission Rate Design.  FERC actions with respect to the transmission rate design within PJM may impact the Distribution Companies. Beginning in July 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator (“MISO”) regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for these regions. In November 2004, FERC rejected long-term

 

20


Table of Contents

regional rate proposals, concluding that neither the rate design proposals nor the existing PJM rate design had been shown to be just and reasonable. FERC ordered the continuation of the existing PJM zonal “license plate” rate design and the implementation of a transition charge for these regions during a 16-month transition period commencing on December 1, 2004 and ending on March 31, 2006. Subsequently, transition charge proposals were submitted by transmission owners and accepted by FERC subject to an evidentiary hearing to determine if the amount of the charges was just and reasonable. Rehearing of the November 2004 order is pending before FERC and will be subject to possible judicial review. Allegheny cannot predict the outcome of this proceeding or whether it 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 $13.3 million and payments to the Distribution Companies of $3.5 million during the transition period. Following the evidentiary hearing, an administrative law judge issued an initial decision finding the methodologies used to develop the transition charges to be deficient. The initial decision is now before FERC for review and may be accepted, rejected or modified by FERC. Based on its review of the initial decision, FERC may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of 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 this proceeding or whether it will have a material impact on its business or financial position.

The Distribution Companies have entered into nine partial settlements with regard to the transition charges. FERC has approved eight of these settlements. FERC action is pending for the remaining partial settlement.

In April 2007, FERC issued an order addressing transmission rate design within the PJM region. In the order, FERC directed the continuation of the zonal “license plate” rate design for all existing transmission facilities within the PJM region, the allocation of costs of new, centrally-planned transmission facilities operating at or above 500 kV on a region-wide “postage stamp” or “socialized” basis, and the development of a detailed “beneficiary pays” methodology for the allocation of costs of new transmission facilities below 500 kV. Subsequently, FERC approved a detailed “beneficiary pays” methodology developed through settlement discussions among several parties to the underlying FERC proceedings. On August 6, 2009, the U. S. Court of Appeals for the Seventh Circuit remanded this decision to FERC for further justification with regard to the allocation of costs for new 500 kV and above transmission facilities but denied petitions for review relating to FERC’s decision with regard to the pricing of existing transmission facilities. On January 21, 2010, FERC issued an order establishing a paper hearing in response to the Seventh Circuit’s remand.

Under the zonal “license plate” rate design for existing transmission facilities, costs associated with such facilities are allocated on a load ratio share basis to load serving entities, such as local distribution utilities, located within the transmission owner’s PJM transmission zone. As a result of this rate design, the load serving entity does not pay for the cost of transmission facilities located in other PJM transmission zones even if the load serving entity engages in transactions that rely on transmission facilities located in other zones. The region-wide “postage stamp” or “socialized” rate design for new, centrally-planned transmission facilities operating at or above 500 kV results in charging all load serving entities within the PJM region a uniform rate based on the aggregated costs of such transmission facilities within the PJM region irrespective of whether the transmission service provided to the load serving entity requires the actual use of such facilities. For the “beneficiary pays” methodology, the costs of new facilities under 500 kV are allocated to load serving entities based on a methodology that considers several factors but is not premised upon the proximity of the load serving entity to the new facilities or the zone in which the new facilities are located.

In January 2008, FERC accepted a compliance filing submitted by certain PJM and MISO transmission owners establishing the transmission pricing methodology for transactions involving transmission service originating in the PJM region or the MISO region and terminating in the other region. The methodology

 

21


Table of Contents

maintains the existing rate design for such transactions under which PJM and MISO treat transactions that source in one region and sink in the other region the same as transactions that source and sink entirely in one of the regions. These inter-regional transactions are assessed only the applicable zonal charge of the zone in which the transaction sinks and no charge is assessed in the zone of the region where the transaction originates. Judicial review of FERC’s order in this matter is pending. Allegheny cannot predict the outcome of these proceedings or whether they will have a material impact on its business or financial position.

Wholesale Markets.  In August 2005, PJM filed at FERC to replace its capacity market with a new Reliability Pricing Model, or “RPM,” to address reliability concerns. On April 20, 2006, FERC issued an initial order that found PJM’s capacity market to be unjust and unreasonable and set a process to resolve features of the RPM that needed to be analyzed further before it could determine whether the RPM is a just and reasonable capacity market process. FERC ordered the implementation of settlement procedures in this proceeding, and AE Supply and the Distribution Companies joined in a settlement agreement that was filed with the FERC on September 29, 2006. The settlement agreement created a locational capacity market in PJM, in which PJM procures needed capacity resources through auctions held three years in advance at prices and in quantities determined by an administratively established demand curve. Under the settlement agreement, capacity needs in PJM are met either through purchases made in the proposed auctions or through commitments by load serving entities (“LSEs”) to self-supply their capacity needs. On December 22, 2006, FERC conditionally approved the settlement agreement, the implementation of which began with the 2007-2008 PJM planning year. Base year capacity auctions were held in April, July and October of 2007, in January and May of 2008 and May of 2009. On June 25, 2007 and again on November 11, 2007, FERC issued orders denying pending requests for rehearing of the December 22, 2006 order and affirming its acceptance of the RPM settlement agreement. Several parties have appealed FERC’s orders approving the RPM settlement, and those appeals are currently pending at the United States Court of Appeals for the District of Columbia Circuit. On May 30, 2008, several parties naming themselves the “RPM Buyers” filed a complaint at FERC seeking a retroactive reduction in the RPM clearing prices for several RPM auctions that have already been conducted. On September 19, 2008, FERC issued an order denying the RPM Buyers’ complaint. In June 2009, FERC denied requests for rehearing of the September 19, 2008 order. The Maryland PSC and New Jersey Board of Public Utilities have appealed FERC’s order denying the RPM Buyers’ complaint to the United States Court of Appeals for the District of Columbia circuit, which appeal remains pending.

PJM Calculation Error.  In September 2009, PJM reported that it had discovered a modeling error in the market-to-market power flow calculations between PJM and MISO. The error, which dates back to April 2005, was a result of the incorrect modeling of certain generation resources that have an impact on power flows across the PJM/MISO border. Allegheny currently is participating in FERC settlement discussions on this issue. Although the amount of the error is subject to dispute, PJM estimated in September 2009 the magnitude of the error to be approximately $77 million. Should a payment by PJM to MISO relating to this modeling error be required, the method by which PJM would allocate any such payment to PJM participants, including Allegheny, is uncertain at this time.

Reliability Standards.  The Energy Policy Act amended the FPA to, among other matters, provide FERC with the authority to oversee the establishment and enforcement of mandatory reliability standards designed to assure the reliable operation of the bulk power system. FERC certified NERC as the Electric Reliability Organization responsible for developing and enforcing continent-wide reliability standards. NERC has established, and the FERC has approved, reliability standards that impose certain operating, record-keeping and reporting requirements on the Distribution Companies, TrAIL Company, PATH, LLC, AE Supply and AGC.

While NERC is charged with establishing and enforcing appropriate reliability standards, it has delegated their day-to-day implementation and enforcement to eight regional oversight entities, including ReliabilityFirst Corporation (“ReliabilityFirst”). These regional oversight entities are responsible for developing regional reliability standards that are consistent with NERC’s standards. Each regional entity has its own compliance program designed to monitor, assess and enforce compliance with the applicable reliability standards through

 

22


Table of Contents

compliance audits, self-reporting and exception reporting mechanisms, self certifications, compliance violation investigations, periodic data submissions and complaint processes. Allegheny is a member of ReliabilityFirst, participates in the NERC and ReliabilityFirst stakeholder processes and monitors and manages its operations in response to the ongoing development, implementation and enforcement of relevant reliability standards. Allegheny has been, and will continue to be, subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirst is currently conducting several violation investigations that have been self-reported by Allegheny. The results of these proceedings and investigations have not had, and are not expected to have, any material impact on Allegheny’s operations or the results thereof. See “Risk Factors.”

Transmission Expansion

TrAIL Project.  TrAIL is a new, 500kV transmission line currently under construction that will extend from southwest Pennsylvania through West Virginia and into northern Virginia. TrAIL is scheduled to be completed and placed in service no later than June 2011. PJM, which is an RTO, directed the construction of TrAIL pursuant to its 2006 RTEP to assure the continued reliability of the transmission grid and reduce congestion in the PJM region. FERC has jurisdiction over the rates for transmission of electricity under the FPA. Rates for transmission service must be filed with and approved by FERC under Section 205 of the FPA. The Energy Policy Act of 2005 directed, among other things, that FERC develop incentive-based mechanisms to encourage new investment in electric transmission facilities that will improve electric reliability and lower costs for consumers. Pursuant to FERC rules implementing that directive and a settlement agreement resolving all outstanding issues regarding TrAIL Company’s formula rate filing, FERC approved certain rate incentives for TrAIL Company, including:

 

   

a 12.7% return on equity for TrAIL and the Black Oak SVC;

 

   

an 11.7% return on equity for all other TrAIL Company transmission projects for which an incentive rate of return is not requested;

 

   

a return on construction work in progress (“CWIP”) for most components of TrAIL prior to completion of construction and placement into service (while an Allowance of Funds Used During Construction (“AFUDC”) is applicable to certain other components and related facilities of TrAIL); and

 

   

recovery of prudently incurred development and construction costs if TrAIL is abandoned as a result of factors beyond TrAIL Company’s control.

PATH Project.  PJM authorized the construction of PATH in June 2007. Allegheny and a subsidiary of AEP formed PATH, LLC to build PATH, and in December 2007, PATH, LLC submitted a filing to FERC under Section 205 of the FPA to implement a formula rate tariff effective March 1, 2008. The filing also included a request for certain incentive rate treatments. In February 2008, FERC issued an order setting the cost of service formula rate to calculate annual revenue requirements for the project and granting the following incentives:

 

   

a return on equity of 14.3%;

 

   

a return on CWIP;

 

   

recovery of prudently incurred start-up business and administrative costs incurred prior to the time the rates go into effect; and

 

   

recovery of prudently incurred development and construction costs if PATH is abandoned as a result of factors beyond the control of PATH, LLC.

In December 2008, PATH submitted to FERC a settlement of the formula rate and protocols with the active parties. FERC approval of the settlement is pending. Rehearing of the February 29, 2008 order with respect to return on equity remains pending before FERC.

 

23


Table of Contents

In December 2009, PJM conducted certain sensitivity analyses as directed by a Virginia SCC Hearing Examiner and advised PATH-VA that these analyses suggest that the PATH Project appears not to be needed in June 2014 as a result of a reduction in the scope and severity of observed NERC reliability violations. PJM further advised that consistent with PJM processes, the PATH Project will be considered in the 2010 RTEP to determine when it will be needed to resolve NERC reliability violations.

National Interest Electric Transmission Corridor (“NIETC”).  In October 2007, the DOE issued a NIETC designation for the mid-Atlantic corridor that includes the areas in which TrAIL is being constructed and PATH is proposed to be sited. Challenges by several entities to the mid-Atlantic corridor designation are pending in the United States Court of Appeals for the Ninth Circuit. Briefing has concluded in this proceeding, in which AE and certain of its subsidiaries are intervenors. Allegheny cannot predict the outcome of this proceeding or whether it will have a material impact on its business or financial position.

In February 2009, the United States Circuit Court for the Fourth Circuit ruled on challenges to FERC rules promulgated for siting transmission lines within a NIETC. The Court held, among other things, that a state’s outright denial of a transmission siting application within one year does not constitute withholding of approval within one year, rejecting FERC’s interpretation of the relevant provision of the FPA. FERC, the Distribution Companies, TrAIL Company and other parties filed a petition for a writ of certiorari with the United States Supreme Court with respect to the Fourth Circuit’s decision, but that petition was denied.

PURPA

The Public Utility Regulatory Policies Act of 1978 (“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, although, as a result of changes in the FPA arising out of the Energy Policy Act, 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.

For 2009, the Distribution Companies committed to purchase 479 MWs of qualifying PURPA capacity, and PURPA expense pursuant to these contracts totaled approximately $230.6 million. The average cost to the Distribution Companies of these power purchases was 6.8 cents/kWh. In December 2009, AE Supply purchased Allegheny Lock and Dam Nos. 5 & 6, which together supply a total of 13 MW. Previously, the Distribution Companies had purchased power generated by these facilities pursuant to PURPA contracts. Consequently, the Distribution Companies have committed to purchase 466 MWs of qualifying PURPA capacity for 2010. 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

Pennsylvania’s Electricity Generation Customer Choice and Competition Act (the “Customer Choice Act”), which was enacted in 1996, gave all retail electricity customers in Pennsylvania the right to choose their electricity generation supplier as of January 2, 2000. Under the Customer Choice Act and a subsequent restructuring settlement (the “1998 Restructuring Settlement”) approved by the Pennsylvania PUC, West Penn transferred its generation assets to AE Supply. West Penn retained its T&D assets. Under the 1998 Restructuring Settlement, West Penn is the default provider for those customers who do not choose an alternate supplier, whose alternate supplier does not deliver, or who have chosen to return to West Penn service, in each case at rates that are capped at various levels during the applicable transition period. West Penn’s T&D assets are subject to traditional regulated utility ratemaking (i.e., cost-based rates).

 

24


Table of Contents

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

Default Service Regulations.  In May 2007, the Pennsylvania PUC entered a Final Rulemaking Order (the “May 2007 Order”) promulgating regulations defining the obligations of electric distribution companies (“EDCs”), such as West Penn, to provide generation default service to retail electric customers who do not or cannot choose service from a licensed electric generation supplier (“EGS”) at the conclusion of the EDCs’ restructuring transition periods. West Penn’s transition period will end for the majority of its customers on December 31, 2010, when its generation rate caps expire.

The regulations promulgated by the May 2007 Order provide that the incumbent EDC will be the default service provider (“DSP”) in its service territory, although the Pennsylvania PUC may reassign the default service obligation to one or more alternative DSPs when necessary for the accommodation, safety and convenience of the public. The DSP is required to file a default service plan not later than 12 months prior to the end of the applicable generation rate cap. The default service plan must identify the DSP’s generation supply acquisition strategy and include a rate design plan to recover all reasonable costs of default service. The default service plan must be designed to acquire generation supply at prevailing market prices to meet the DSP’s anticipated default service obligation at reasonable costs. A DSP’s affiliate generation supplier may participate in the DSP’s competitive bid solicitations for generation service. DSPs will use an automatic energy adjustment clause to recover all reasonable costs of obtaining alternative energy pursuant to the Alternative Energy Portfolio Standards Act, and the DSP may use an automatic adjustment clause to recover non-alternative energy default service costs. Automatic adjustment clauses will be subject to annual review and audit by the Pennsylvania PUC. Default service rates will be adjusted on a quarterly basis, or more frequently, for customer classes with a peak load up to 500 kW, and on a monthly basis, or more frequently, for customer classes with peak loads greater than 500 kW.

In October 2007, West Penn filed a default service plan with the Pennsylvania PUC. The Pennsylvania PUC administrative law judge entered a final order on July 25, 2008 that largely approved West Penn’s proposed default service plan, including its full requirements procurement approach and rate mitigation plan. West Penn filed tariff supplements implementing the default service plan in September 2008 and January 2009. On February 6, 2009, West Penn filed a petition with the Pennsylvania PUC requesting approval to advance the first series of default service procurements for residential customers from June 2009 to April 2009 to take advantage of a downturn in market prices for power. West Penn’s petition was approved by the Pennsylvania PUC in March 2009, and it began to conduct advanced procurements in April 2009. Also in April 2009, West Penn petitioned to Pennsylvania PUC for approval to further accelerate default service procurements increasing by 550 MW the amount of power that it planned to procure in June 2009. By Order entered May 14, 2009, the Pennsylvania PUC approved the request to advance the procurement of 550 MW, and the procurement occurred in June 2009.

Advanced Metering and Demand-Side Management Initiatives.  In October 2008, Pennsylvania adopted Act 129, which includes a number of measures relating to conservation, demand-side management and power procurement processes. Act 129 requires each EDC with more than 100,000 customers to adopt a plan, approved by the Pennsylvania PUC, to reduce, by May 31, 2011, electric consumption by at least one percent of its expected consumption for June 1, 2009 through May 31, 2010. By May 31, 2013, the total annual weather-

 

25


Table of Contents

normalized consumption is to be reduced by a minimum of three percent, and peak demand is to be reduced by a minimum of four and one-half percent of the EDC’s annual system peak demand. Act 129 also:

 

   

directed the Pennsylvania PUC to adopt an energy conservation and efficiency program to require EDCs to develop and file, by July 1, 2009, plans to reduce energy demand and consumption; and

 

   

required EDCs to file a plan for “smart meter” technology procurement and installation in August 2009.

West Penn expects to incur significant capital expenditures in 2010 and beyond to comply with these requirements.

Act 129 also requires EDCs to obtain energy through a prudent mix of contracts, with an emphasis on competitive procurement. The Act includes a “grandfather” provision for West Penn’s procurement and rate mitigation plan, which was previously approved by the Pennsylvania PUC.

On June 30, 2009 West Penn filed its Energy Efficiency and Conservation Plan containing 22 programs to meet its Act 129 demand and consumption reduction obligations. The proposed programs cover most energy-consuming devices of residential, commercial and industrial customers. The Plan also proposes a reconcilable surcharge mechanism to obtain full and current cost recovery of the Plan costs as provided in Act 129. The Plan projected an aggregated cost of the energy efficiency measures in the amount of approximately $94.3 million through mid 2013. A hearing concerning West Penn’s Energy Efficiency and Conservation Plan was held August 19, 2009.

The Pennsylvania PUC approved West Penn’s Energy Efficiency and Conservation Plan, in large part, by Opinion and Order entered October 23, 2009. The new programs approved by the Pennsylvania PUC include: rebates for customers who purchase high efficiency appliances, lighting and heating and cooling systems; residential home audits and rebates toward implementing audit recommendations; home audit, weatherization and air conditioner replacement programs for low-income customers; new rate options that will provide financial incentives for customers to lower their demand for electricity or shift their usage to lower-priced times; incentives for customers who install in-home devices that reduce electric usage when demand is highest; and various programs for commercial, industrial, government and non-profit customers to increase energy efficiency and conservation. The Pennsylvania PUC also approved West Penn’s proposal to recover its Energy Efficiency and Conservation Plan costs on a full and current basis via an automatic surcharge to customers’ bills, subject to an annual reconciliation mechanism.

The Pennsylvania PUC declined to approve West Penn’s proposed distributed generation program and West Penn’s proposed contract demand response program and encouraged West Penn to submit revisions to both programs. On December 21, 2009, West Penn filed an Amended Energy Efficiency and Conservation Plan as directed by the Pennsylvania PUC, in which it added a new customer resources demand response program intended to replace the previously proposed distributed generation and contract demand programs. The Pennsylvania PUC reviewed Allegheny’s amended Plan at its public meeting on February 11, 2010 and ordered Allegheny to file an amended plan within 60 days to include additional detail on the costs associated with the previously approved customer load response program and the new customer resources demand response program.

On August 14, 2009, West Penn filed its Smart Meter Technology Procurement and Installation Plan. The Plan provides for extensive deployment of smart meter infrastructure with replacement of all of West Penn’s approximately 725,000 meters by the end of 2014. To support two-way communications with the new meters, West Penn will build a new and secure telecommunications network. To support time of use and real time pricing as required by Act 129, West Penn will purchase and install a new customer information system. A hearing on West Penn’s smart meter Plan was held on November 8, 2009. On December 18, 2009, West Penn filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less rapid deployment of smart meters. On January 13, 2010, the Pennsylvania PUC granted the motion to reopen the record and remanded the proceeding to the ALJ. The Pennsylvania PUC also waived the late January 2010 deadline by which the ALJ’s recommended decision would have been required. On January 26, 2010, the ALJ set

 

26


Table of Contents

a hearing and briefing schedule for the reopened record, with a target deadline for the ALJ’s recommended decision of April 23, 2010.

West Penn estimates that the total cost of implementing smart metering infrastructure as proposed in the Plan as originally filed would be approximately $620 million; however, West Penn’s actual cost to implement smart meter infrastructure may vary from that estimate as a result of changes in its procurement and installation plan as ultimately approved by the Pennsylvania PUC and the timing of that approval, among other factors. In accordance with Act 129, West Penn’s Plan requests a cost recovery surcharge for the full and current recovery of the expenditures from customers.

Transmission Expansion.  By order entered on December 12, 2008, the Pennsylvania PUC authorized TrAIL Company to construct a 1.2 mile portion of TrAIL in Pennsylvania from the proposed 502 Junction Substation in Greene County to the Pennsylvania-West Virginia state line. In the same order, the Pennsylvania PUC also approved an agreement among TrAIL Company, West Penn and Greene County, Pennsylvania in which, among other provisions, TrAIL Company agreed to engage in a collaborative process to identify possible solutions to reliability problems in the Washington County, Pennsylvania area in lieu of the Prexy Facilities that had been a part of the original TrAIL proposal. Judicial review is pending in the Commonwealth Court of Pennsylvania with regard to the authorization to construct the 1.2 mile portion of TrAIL. A proposed settlement and an amendment to the application based on a consensus of participants in the collaborative process are pending before the Pennsylvania PUC for approval.

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

Reliability Benchmarks.  In May 2004, the Pennsylvania PUC modified its utility specific benchmarks and performance standards for electric distribution system reliability. The benchmarks were set too low for West Penn, resulting in required reliability levels that were unattainable. West Penn appealed the benchmarks to the Pennsylvania PUC. In 2005, the parties to the proceeding, including the Consumer Advocate, the Utility Workers Union of America Local 102, and the Rural Electric Association entered into an agreement settling the proceeding and providing West Penn with attainable reliability benchmarks. The Pennsylvania PUC approved the settlement in an Order issued July 27, 2006. According to the Pennsylvania PUC’s Electric Service Reliability in Pennsylvania 2008 report, Allegheny’s overall performance in 2008 was substantially better than its performance during 2007. In 2007 and 2008, Allegheny’s System Average Interruption Frequency Index, Customer Average Interruption Duration Index and System Average Interruption Duration Index values were better than the applicable standards. As of July 2009, West Penn is satisfying all of the reliability benchmarks and standards approved by the Pennsylvania PUC in its July 2006 order.

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

 

27


Table of Contents

that clarified the jurisdiction of the West Virginia PSC over electric generation facilities. In 2000, Potomac Edison received approval to transfer its West Virginia generation assets to AE Supply. However, the West Virginia PSC never acted on a similar petition by Monongahela, and Monongahela agreed to withdraw its petition. Based on these actions, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West Virginia.

Rate Case.  On August 13, 2009, Monongahela and Potomac Edison filed with the West Virginia PSC a request to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. On January 12, 2010, Monongahela and Potomac Edison filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement that is approximately $7.7 million lower than the requirement included in the original filing. In addition, in December 2009, subsidiaries of Monongahela and Potomac Edison completed a securitization transaction to finance certain costs associated with the installation of Scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently, Monongahela and Potomac Edison now are requesting to increase retail rates by approximately $106 million, rather than $122.1 million, annually. Additionally, the parties to the case agreed to toll the effectiveness of the new rates until June 29, 2010. An evidentiary hearing on this matter is scheduled to begin April 5, 2010.

Annual Adjustment of Fuel and Purchased Power Cost Rates.  On August 29, 2008, Monongahela and Potomac Edison filed with the West Virginia PSC a request to increase retail rates by approximately $173 million annually to reflect expected increases in fuel and purchased power costs during 2009 and under-recovery of past costs through June 2008. The new rates, proposed to become effective January 1, 2009, were submitted pursuant to the schedule for annual fuel and purchased power cost reviews that was approved by the West Virginia PSC when it reinstated a fuel and purchased power cost recovery clause in the rate case described above. On December 29, 2008, the West Virginia PSC issued an order approving a settlement agreement among Allegheny, the Consumer Advocate Division, the Staff of the West Virginia PSC and the West Virginia Energy Users Group, pursuant to which Allegheny’s rates in West Virginia were increased by $142.5 million annually beginning on January 1, 2009.

On September 1, 2009, Monongahela and Potomac Edison filed their annual fuel adjustment request with the West Virginia PSC, requesting a rate increase of $143.2 million to reflect increases in their unrecovered balances of fuel and purchased power costs that have accrued through June 2009 and projected increases through June 2010. The new rates were submitted pursuant to the schedule for annual fuel and purchased power cost reviews. On December 2, 2009, the parties to the proceeding filed a Joint Stipulation providing that Monongahela and Potomac Edison would receive an increase of $118 million, effective January 1, 2010, plus deferred recovery of an additional $23.1 million effective January 1, 2011, with carrying charges of 6% on the deferred amount. The West Virginia PSC approved the Joint Stipulation on December 29, 2009.

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

In October 2006, Monongahela and Potomac Edison filed with the West Virginia PSC a Petition to Reopen Proceedings and to Amend Financing Order (“Petition”), informing the West Virginia PSC that the current estimate for constructing the Scrubbers at Fort Martin had increased from $338 million to an amount up to $550

 

28


Table of Contents

million. In December 2006, Allegheny reached a settlement agreement with all parties in the reopened cases and filed the agreement with the West Virginia PSC. The West Virginia PSC approved the settlement agreement, authorizing Allegheny to securitize up to $450 million of the estimated construction costs, plus $16.5 million of upfront financing costs and certain other costs. On April 11, 2007, Allegheny completed the securitization with the sale by two indirect subsidiaries of an aggregate of $459.3 million in environmental control bonds.

On July 2, 2009, Monongahela and Potomac Edison requested authority from the West Virginia PSC to finance the remaining costs associated with the Fort Martin Scrubber project through the issuance of additional environmental control bonds. On September 30, 2009, the West Virginia PSC issued a financing order granting Monongahela and Potomac Edison the authority, subject to the terms and conditions of the financing order, to issue the bonds and impose the related environmental control charge. On December 23, 2009, MP Environmental Funding LLC, an indirect wholly owned subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect wholly owned subsidiary of Potomac Edison, issued $85,890,000 aggregate principal amount of Senior Secured ROC Bonds, Environmental Control Series B.

Transmission Expansion.  On May 15, 2009, PATH-WV, PATH-Allegheny and certain other related entities (the “PATH Entities”) filed an application with the West Virginia PSC for certificates of public convenience and necessity to construct portions of the PATH Project in West Virginia. On October 28, 2009, the Staff of the West Virginia PSC filed a motion to dismiss the application on the basis that, because there was no application pending at that time before any regulatory agency for approval of the Maryland portion of the PATH Project, there was no identified eastern terminus of the project. Other parties filed similar motions or statements in support of the Staff motion. The PATH Entities filed responses in which they opposed the Staff motion but agreed to toll the statutory decision due date in West Virginia until February 24, 2011, if the West Virginia PSC extended its current procedural schedule in the manner proposed by the PATH Entities. The West Virginia PSC denied the motions to dismiss and established a revised procedural schedule providing for an evidentiary hearing commencing in October 2010 and a final commission decision by February 24, 2011. The PATH Entities expect to supplement their pre-filed testimony on June 29, 2010 to reflect a new in-service date for the PATH Project based on PJM’s 2010 RTEP analysis.

On September 10, 2009, TrAIL Company filed a petition to amend its certificate for the TrAIL Project requesting authorization of the West Virginia PSC to make minor adjustments in the approved route in 21 locations. The West Virginia PSC authorized the adjustments and required the filing of property owner written consents. Subsequently, TrAIL Company determined that it had not obtained the written consent for two parcels as it had previously represented and filed a corrected petition to amend the certificate with respect to these parcels. The West Virginia PSC has not acted on the corrected petition. TrAIL Company has filed an additional petition to amend the certificate requesting authorization of the West Virginia PSC to approve five additional minor adjustments to the approved route. The West Virginia PSC has not acted on this additional petition.

On October 19, 2009, four individuals filed a complaint with the West Virginia PSC regarding TrAIL Company’s right-of-way clearing practices for the TrAIL Project that requested, among other things, a limit on right of way clearing for TrAIL. TrAIL Company responded to the complaint, denying each of its allegations. The West Virginia PSC has not acted on the complaint.

Purchase of Distribution Operations.  In connection with Potomac Edison’s agreement to sell its Virginia distribution assets, Allegheny will purchase certain West Virginia distribution operations from Shenandoah Valley Electric Cooperative for approximately $15 million.

Maryland

In 1999, Maryland adopted electric industry restructuring legislation, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation suppliers. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply but remained obligated to provide standard offer generation service (“SOS”) at capped rates to residential and non-residential customers for various periods. The longest such

 

29


Table of Contents

period, for residential customers, expired on December 31, 2008. As discussed below, Potomac Edison has implemented a rate stabilization plan to transition customers from capped generation rates to rates based on market prices. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates for all customers were capped through 2004 and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates).

Standard Offer Service.  In 2003, the Maryland PSC approved two state-wide settlements relating to the future of PLR and SOS. The settlements extended Potomac Edison’s obligation to provide SOS after the expiration of the generation rate cap periods established for Potomac Edison as part of the 1999 restructuring of Maryland’s electric market. The settlements 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. In another proceeding, the Maryland PSC ordered the utilities to issue an RFP for possible acquisition of demand response resources for the period from 2011 to 2016 and to participate in a working group on the development of distributed generation resources. The RFP was issued on January 16, 2009. The Maryland PSC issued an order on March 11, 2009 approving the purchase of most of the resources offered, and the utilities have made the purchases.

By statute enacted in 2007, the obligation of Maryland utilities to provide SOS to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the Maryland PSC to report to the legislature on the status of SOS. The other Maryland electric utilities providing SOS, all of whose initial settlement obligations have expired, continue to do so essentially in accordance with the terms of the 2003 settlements as modified by the Maryland PSC orders discussed immediately above, as does Potomac Edison. The terms on which Potomac Edison will provide SOS to residential customers after the settlement covering that initial obligation expires in 2012 depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible Maryland PSC decisions in the proceedings discussed below.

The Maryland PSC opened a new docket in August 2007 (Case No. 9117) to consider matters relating to possible “managed portfolio” approaches to SOS, the aggregation of low income SOS customers, and a retail supplier proposal for the utility “purchase” of all retailer receivables at no discount and with no recourse. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects are delayed or defeated. Hearings on Phase I and II were held in October and November 2007 and in January 2008. It is unclear when the Maryland PSC will issue its findings in this and other related pending proceedings discussed below.

On July 3, 2008, the Maryland PSC issued a further order requiring the utilities to prepare detailed studies of alternatives for possible managed portfolios, with a time horizon out to fifteen years, and to file those studies by October 1, 2008. The Maryland PSC expressly stated that the order, “should not be construed… as a decision to modify in any way, the current SOS procurement practice.” Potomac Edison filed its study with the Maryland PSC on October 1, 2008, and the Maryland PSC held hearings on the matter in December 2008. No order has been issued.

Also, on September 29, 2009, the Maryland PSC opened another new proceeding to receive and consider proposals for construction of new generation resources in Maryland. Proposals were initially due to be filed by December 16, 2009, but the Maryland PSC has indefinitely postponed that deadline while it considers recommendations as to what the filings should be required to contain. Also, on December 18, 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the Maryland PSC to use its existing authority to order the construction of new generation

 

30


Table of Contents

in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix.

In August 2007, Potomac Edison filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps on December 31, 2008. The Maryland PSC approved the plan in a series of orders issued between September 2007 and September 2008. Potomac Edison will continue to conduct rolling auctions to procure the power supply necessary to serve its customer load going forward.

Rate Stabilization.  In special session on June 23, 2006, the Maryland legislature passed emergency legislation, directing the Maryland PSC to, among other things, investigate options available to Potomac Edison to implement a rate mitigation or rate stabilization plan for SOS to protect its residential customers from rate shock when capped generation rates end on January 1, 2009.

In December 2006, Potomac Edison filed with the Maryland PSC a proposed Rate Stabilization Ramp-Up Transition Plan designed to transition residential customers from capped generation rates to rates based on market prices. Under the plan as approved by the Maryland PSC, residential customers who did not elect to opt out of the program began paying a surcharge in June 2007. The application of the surcharge resulted in an overall rate increase of approximately 15% in 2007 and 13% in 2008. 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 converted to a credit on customers’ bills. Funds collected through the surcharge during 2007 and 2008, plus interest, are being returned to customers as a credit on their electric bills, thereby reducing the effect of the rate cap expiration. The credit will continue, with adjustments, to maintain rate stability until December 31, 2010 or until all monies collected from customers plus interest are returned. The resulting rate increase in 2009 was 11.3%, and the rate change approved in 2009 for 2010 was actually a decrease of 2.5%. Of Potomac Edison’s approximately 219,000 residential customers in Maryland, as of December 31, 2009, approximately 32,400, or 14.7%, elected to opt-out of, or are not eligible for, Potomac Edison’s plan.

Advanced Metering and Demand Side Management Initiatives.  On June 8, 2007, the Maryland PSC established a new case to consider advanced meters and demand side management programs. The Staff of the Maryland PSC filed its report on these matters on July 6, 2007. On September 28, 2007, the Maryland PSC issued an order in this case that required the utilities to file detailed plans for how they will meet a proposal-“EmPOWER Maryland”-that in Maryland electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015. On October 26, 2007, Potomac Edison filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The Maryland PSC conducted hearings on Potomac Edison’s and other utilities’ plans in November 2007 and further hearings on May 7, 2008.

In a related development, the Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals and setting a deadline of September 1, 2008 for the utilities to file comprehensive plans for attempting to achieve those goals. Potomac Edison filed its proposals on August 29, 2008, asking the Maryland PSC to approve seven programs for residential customers, five programs for commercial, industrial, and governmental customers, a customer education program, and a pilot deployment of Advanced Utility Infrastructure (“AUI”) that Allegheny has previously been testing in West Virginia. On December 31, 2008, the Maryland PSC issued an order approving some of Potomac Edison’s programs and directing that others be redesigned. Potomac Edison filed its revised programs on March 31, 2009, with new cost and benefit information. The Maryland PSC approved the programs on August 6, 2009, and approved cost recovery for the programs on October 6, 2009. Expenditures are expected to be approximately $101 million and will be recovered over the next six years. Meanwhile, the AUI pilot is being examined on a separate track and is currently under discussion with the Staff of the Maryland PSC.

Renewable Energy Portfolio Standard.  Legislation enacted in 2004 (and supplemented with respect to solar power in 2007) requires the implementation of a renewable energy portfolio standard in Maryland. Beginning upon the later of the expiration of the transition period for any particular customer class served by a supplier or January 1, 2006, retail electricity suppliers in Maryland must obtain certain percentages of their

 

31


Table of Contents

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.

Moratorium on Service Terminations.  On March 11, 2009, the Maryland PSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The order directed the utilities and other interested parties to meet and devise proposals for offering payment plans to all residential customers, not just low-income customers. On April 1, 2009, the Staff of the Maryland PSC and utilities filed a plan providing for additional and longer payment plans and for a temporary suspension of requests to customers for increased deposits. The Maryland PSC held a hearing on the matter on April 7, 2009, and subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. Potomac Edison and several other utilities filed requests for reconsideration of various parts of the order on May 26, 2009, which motions were denied on September 23, 2009. Potomac Edison filed a notice of appeal of that order on October 23, 2009, but withdrew the appeal when the Maryland PSC issued a further order on November 23, 2009 that clarified the limited scope and duration of the rule changes. The Maryland PSC is continuing to conduct hearings on related issues, including a set of proposed regulations that would expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

Transmission Expansion.  On December 21, 2009, Potomac Edison filed a new application with the Maryland PSC for a certificate of public convenience and necessity to construct the Maryland portions of the PATH Project. The project in Maryland will be owned by PATH Allegheny MD, which is owned by Potomac Edison and PATH-Allegheny. The Maryland PSC has not made a decision whether to accept the application. If the application is accepted, Potomac Edison expects to supplement its pre-filed testimony on or about June 29, 2010 to reflect a new in-service date for the PATH Project based on PJM’s 2010 RTEP analysis. Potomac Edison has also agreed not to file an application with FERC pursuant to Section 216(b)(1) of the FPA prior to June 29, 2011 to construct the PATH Project in Maryland.

Virginia

Sale of Distribution Operations.  On May 4, 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative (together, the “Cooperatives”) for cash proceeds of approximately $340 million, subject to state and federal regulatory approval, certain third-party consents and applicable price adjustments. On September 15, 2009, Potomac Edison and the Cooperatives filed with the Virginia SCC a joint request for approval of the transaction. The Virginia SCC issued a procedural order scheduling an evidentiary hearing on the matter for March 2, 2010. On January 29, 2010, consultants retained by the Staff of the Virginia SCC filed testimony analyzing the transaction, asserting that current Virginia customers of Potomac Edison would pay $370 million more in rates over nine years if the Cooperatives take over service to those customers. Potomac Edison and the Cooperatives filed rebuttal testimony on February 12, 2010, which pointed to various flaws in the consultants’ analysis and concluded that current Virginia customers would see comparable or lower rates under Cooperative ownership as compared to future rates that Potomac Edison would need to charge. See “Risk Factors” and consolidated financial statement Note 3, “Assets Held for Sale.”

Purchased Power Cost Recovery.  Until July 1, 2007, Potomac Edison had a power purchase agreement with AE Supply to provide Potomac Edison with the power necessary to serve its retail customers in Virginia at rates that were consistent with generation rate caps in effect pursuant to the Virginia Electric Utility Restructuring Act of 1999 (the “Restructuring Act”). Effective with the expiration of that power purchase agreement on July 1, 2007, Potomac Edison began to purchase the power necessary to serve its Virginia customers through the wholesale market at market prices, through a competitive wholesale bidding process. In

 

32


Table of Contents

April 2007 and again in March 2008, Potomac Edison conducted a competitive bidding process to purchase power requirements from the wholesale market for its retail customer service in Virginia, and AE Supply was the successful bidder with respect to a substantial portion of these requirements.

The Restructuring Act initially capped generation rates until July 1, 2007. In 2004, it was amended to extend capped rates to 2010, but also provided that Virginia utilities that had divested their generation, such as Potomac Edison, could begin to recover purchased power costs on July 1, 2007. In 2007, the law was revised again to provide for generation rate caps to end on December 31, 2008. The market prices at which Potomac Edison has purchased power since the expiration in 2007 of its power purchase agreement with AE Supply were significantly higher than the capped generation rates initially set under the Restructuring Act.

Although the Restructuring Act does provide for generation rate caps through December 31, 2008, it was amended to provide, among other things, that Virginia utilities, such as Potomac Edison, could begin to recover purchased power costs, such that the rates a utility would be permitted to charge Virginia customers beginning on July 1, 2007 would be based on the utility’s cost of purchased power.

In an April 2007 filing with the Virginia SCC, Potomac Edison requested to adjust its fuel factor and to implement a rate stabilization plan, including an increase in retail rates of approximately $103 million to be phased in over three years beginning July 1, 2007, to offset the impact of increased purchased power costs. In June 2007, the Virginia SCC issued an order that denied Potomac Edison’s application and motion to establish interim rates, cancelled evidentiary hearings and dismissed the case, ruling that recovery was barred by a Memorandum of Understanding (the “MOU”) that Potomac Edison entered into with the Staff of the Virginia SCC in 2000 in connection with the transfer of its Virginia generating assets to AE Supply. Under the MOU, Potomac Edison agreed to forego fuel cost adjustments otherwise permitted under the Restructuring Act during the capped rate period, which, at the time that the MOU was entered into, was scheduled to expire as of July 1, 2007.

On December 20, 2007, the Virginia SCC granted Potomac Edison partial ($9.5 million) recovery of increased purchased power costs, following a second application by Potomac Edison for rate recovery of $42.3 million. On May 15, 2008, following a third application by Potomac Edison, the Virginia SCC issued an order allowing Potomac Edison to increase its rates effective July 1, 2008, on an interim basis subject to refund, to collect $73 million of purchased power costs. Revenues were recognized based on the method under which the rates were developed and not the amounts collected. As a result, a portion of the amounts collected from July 1, 2008 to December 31, 2008 was deferred as a regulatory liability and was recognized as revenue from January through June 2009.

On July 18, 2008, the Virginia SCC issued an order finding that the rate making provisions of the MOU would expire on December 31, 2008. On November 18, 2008, Potomac Edison filed with the Virginia SCC a comprehensive rate settlement agreed to with the Staff of the Virginia SCC, the Consumers Counsel of the Virginia Office of the Attorney General and a group of Potomac Edison’s industrial customers that transitions all customers to rates that allow for full recovery of purchased power costs no later than July 1, 2011. The Virginia SCC held a hearing on the settlement on November 18 and approved it without alteration or condition on November 26, 2008. Key provisions of the settlement include:

 

   

the $73 million rate increase approved on a temporary basis on May 15, 2008 will remain in effect through June 30, 2009;

 

   

for the period from July 1, 2009 through December 31, 2009, half of any further increase in purchased power costs for service to large non-residential customers will be forgone, up to $15 million;

 

   

for the period from July 1, 2009 through June 30, 2010, the total rate increase for all other customers will be capped at 15%; and

 

   

during the period from July 1, 2009 through June 30, 2011, 100 MW of the power procured by Potomac Edison will be deemed for rate purposes to have been procured at the lesser of actual cost or $55 per MWh.

 

33


Table of Contents

Potomac Edison successfully procured power in December 2008 to cover load for the settlement period through 2011, and AE Supply was the successful bidder with respect to a substantial portion of these requirements.

On June 5, 2009, Potomac Edison filed a request for a transmission rate adjustment clause to collect $1.0 million of third-party transmission costs that it expects to incur between January 1, 2009 and August 31, 2010, as permitted by the settlement. Potomac Edison has proposed to recover this amount from its retail customers over the rate period from September 1, 2009 through August 31, 2010. The Virginia SCC approved recovery of all but an insignificant portion of this amount in an order issued on August 28, 2009.

On May 15, 2009, the Virginia SCC issued an order concerning a request by Potomac Edison to recover purchased power costs to serve its Virginia customers. The Virginia SCC’s order granted an interim rate increase of approximately $19.4 million, subject to refund, effective July 1, 2009. In October 2009, Potomac Edison and the Staff of the Virginia SCC filed a joint stipulation, pursuant to which the rate increase would be reduced by $3.2 million to approximately $16.2 million. On October 30, 2009, the Virginia SCC issued an order that approved the joint stipulation.

Transmission Expansion.  On May 19, 2009, PATH-VA filed an application with the Virginia SCC for a certificate of public convenience and necessity to construct portions of the PATH Project in Virginia. The Virginia SCC established a procedural schedule that provided for an evidentiary hearing commencing on January 19, 2010. On December 21, 2009, PATH-VA filed a motion (as amended on December 29, 2009) to withdraw its application on the basis that certain sensitivity analyses conducted by PJM as directed by the Hearing Examiner suggested that the PATH Project appears not to be needed in June 2014 as a result of a reduction in the scope and severity of observed NERC reliability violations. PATH-VA further stated that, consistent with PJM processes, the PATH Project will be considered by PJM in its 2010 RTEP analysis to determine when it will be needed to resolve NERC reliability violations and that PATH-VA did not expect to file a new application prior to the third quarter of 2010. The Hearing Examiner suspended the procedural schedule and issued a report to the Virginia SCC recommending that the motion to withdraw be granted. On January 27, 2010, the Virginia SCC granted the motion to withdraw, and the application is no longer pending.

 

34


Table of Contents

ENVIRONMENTAL MATTERS

The operations of Allegheny’s owned facilities, including its generation facilities, are subject to various federal, state and local laws, rules and regulations as to air and water quality, hazardous and solid waste disposal and other environmental matters, some of which may be uncertain. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities.

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

Global Climate Change

The United States relies on coal-fired power plants for more than 48% of its energy. However, coal-fired power plants have come under scrutiny due to their emission of gases implicated in climate change, primarily carbon dioxide, or “CO2.”

Allegheny produces approximately 95% of its electricity at coal-fired facilities and currently produces approximately 45 million tons of CO2 annually through its energy production. While there are many unknowns concerning the final regulation of greenhouse gases in the United States, federal and/or state legislation and implementing regulations addressing climate change, including limits on emissions of CO2, likely will be adopted some time in the future. Thus, CO2 legislation and regulation, if not reasonably designed, could have a significant impact on Allegheny’s operations. On June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act. The U.S. Senate released its draft of the bill, the Clean Energy Jobs and American Power Act, on September 30, 2009. Additionally, on December 7, 2009, the EPA announced its Greenhouse Gas Endangerment Finding, stating that greenhouse gas emissions from cars and light trucks, when mixed in the atmosphere, endanger public health. The finding provides the EPA with a basis on which to regulate greenhouse gas emissions from vehicle tailpipes under the provisions of the Clean Air Act. Once a pollutant is regulated under the Clean Air Act for one source category, the EPA has authority to apply similar regulations to other source categories, and the EPA has announced its intention to do so. Hence, with the Endangerment Finding finalized, the EPA will have the authority to regulate greenhouse gas emissions from stationary sources such as electric generating units. Allegheny can provide no assurance that limits on CO2 emissions, if imposed by legislation or otherwise, will be set at levels that can accommodate its generation facilities absent the installation of controls.

Moreover, there is a gap between desired reduction levels in the current proposed legislation and the current capabilities of technology; no current commercial-scale technology exists to enable many of the reduction levels in national, regional and state proposals. Such technology may not become available within a timeframe consistent with the implementation of any future climate control legislation or at all. To the extent that such technology does become available, Allegheny can provide no assurance that it will be suitable for installation at Allegheny’s generation facilities on a cost effective basis or at all. Based on estimates from a 2007 DOE National Electric Technology Laboratory report and announced projects by other entities, it could cost as much as $5,500 per kW to replace existing coal-based power generation with fossil fuel stations capable of capturing and sequestering CO2 emissions. However, exact estimates are difficult because of the variance in the legislative proposals and the current lack of deployable technology.

Allegheny supports federal legislation and believes that the United States must commit to a response to climate change that both encourages the development of technology and creates a workable control system. Regardless of the eventual mechanism for limiting CO2 emissions, however, compliance will be a major and costly challenge for Allegheny, its customers and the region in which it operates. Most notable will be the potential impact on customer bills and disproportionate increases in energy cost in areas that have built their energy and industrial infrastructure over the past century based on coal-fired electric generation.

 

35


Table of Contents

Because the legislative process and applicable technology each is in its infancy, it is difficult for Allegheny to aggressively implement greenhouse gas emission expenditures until the exact nature and requirements of any regulation are known and the capabilities of control or reduction technologies are more fully understood. Allegheny’s current strategy in response to climate change initiatives focuses on six tasks:

 

   

maintaining an accurate CO2 emissions data base;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

improving demand-side efficiency programs, as evidenced by customer conservation outreach plans and Allegheny’s Watt Watchers initiatives.

Allegheny’s energy portfolio also includes approximately 1,180 MWs of renewable hydroelectric and pumped storage power generation. Allegheny obtained a permit to allow for a limited use of bio-mass (wood chips and saw dust) at one of its coal-fired power stations in West Virginia and currently has approval to use waste-tire derived fuel at another of its coal-based power stations in West Virginia.

Allegheny intends to engage in the dialogue that will shape the regulatory landscape surrounding CO2 emissions. Additionally, Allegheny intends to pursue proven and cost-effective measures to manage its emissions while maintaining an affordable and reliable supply of electricity for its customers.

Clean Air Act Compliance

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

Allegheny’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install control technologies on many of its generation facilities at significant cost. 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 the currently available allowances. The EPA is revising certain portions of CAIR that were invalidated by the U.S. Court of Appeals for the District of Columbia Circuit. The EPA has cautioned that it is reviewing whether or not to have an annual NOx trading program (non-Ozone Season) beyond 2010.

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. On February 8, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the rule in its entirety. The State of West Virginia subsequently suspended its rule for implementing CAMR. Pennsylvania and Maryland, however, took the position that their mercury rules, which are discussed below, survived this ruling. In addition, the EPA has announced plans to propose a new maximum achievable control technology rule for hazardous air pollutant emissions from electric utility steam generating units. The EPA is expected to finalize the new rule by November 2011. Accordingly, Allegheny is monitoring the EPA’s efforts to promulgate hazardous air pollutant rules that will include, but will not be limited to, mercury limits. To establish these standards with respect to mercury, the EPA must identify the best performing 12% of sources in each source category and, to that end, has issued an information request to members of the fossil fuel-fired generating industry that includes a requirement to conduct extensive stack emissions testing on selected generating units. Allegheny is required to conduct stack testing for nine of its generating units. Depending on the final hazardous air pollution limits set by the EPA, Allegheny could incur significant costs for additional control equipment.

 

36


Table of Contents

The Pennsylvania Department of Environmental Protection (the “PA DEP”) promulgated a more aggressive mercury control rule on February 17, 2007. Pennsylvania’s proposed shortened compliance schedule and more aggressive emissions limits might result in the installation of additional emission controls at any of Allegheny’s three Pennsylvania coal-fired facilities or in a change in fuel specifications. Controls might include additional Scrubbers, activated carbon injection, selective catalytic reduction or other currently emerging technologies. On September 15, 2008, PPL Corporation filed a challenge to the PA DEP’s mercury rule in Pennsylvania Commonwealth Court. The Commonwealth Court overturned the Pennsylvania mercury rule on January 30, 2009. On December 23, 2009, the Pennsylvania Supreme Court affirmed the Commonwealth Court’s holding that the rule is invalid.

Additionally, Maryland passed the Healthy Air Act in early 2006. This legislation imposes state-wide emission caps on SO2 and NOx, requires greater reductions in mercury emissions more quickly than required by CAMR and mandates that Maryland join the Regional Greenhouse Gas Initiative (“RGGI”) and participate in that coalition’s regional efforts to reduce CO2 emissions. On April 20, 2007, Maryland’s governor signed on to RGGI, as a result of which Maryland became the 10th state to join the Northeast regional climate change and energy efficiency program. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NOx, SO2 and mercury, based on a PJM declaration that the station is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (the “MDE”) passed alternate NOx and SO2 limits for R. Paul Smith, which became effective in April 2009. The MDE still expects R. Paul Smith to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Among other things, under RGGI, the MDE now auctions 100% of CO2 allowances associated with Maryland’s power plants, and Allegheny is participating in RGGI auctions.

AE Supply and Monongahela comply with current SO2 emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Allegheny continues to evaluate and implement options for compliance. It completed the elimination of a partial bypass of Scrubbers at its Pleasants generation facility in December 2007 and the construction of Scrubbers at its Hatfield’s Ferry and Fort Martin generating facilities in 2009. Allegheny now has Scrubbers installed and operating on all 10 of the units at its four supercritical generating facilities and at Mitchell Unit 3.

Allegheny’s NOx compliance plan functions on a system-wide basis, similar to its 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 currently has installed selective non-catalytic reduction equipment at its Fort Martin and Hatfield’s Ferry generating stations and selective catalytic reduction equipment at its Harrison and Pleasants generating stations, together with other NOx controls at these supercritical generating facilities, as well as its other generating facilities.

On January 8, 2010, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Notice of Violation for opacity emissions at Allegheny’s Pleasants generating facility. Allegheny is evaluating certain control system options for opacity reduction. Although a system has not yet been selected, the cost to install any such system could be significant.

Clean Air Act Litigation

In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and/or Monongahela own these generation facilities. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the NSR standards of the Clean Air

 

37


Table of Contents

Act, which can require the installation of additional air emission 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 emission control technology.

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.

On June 28, 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Distribution Companies in the United States District Court for the Western District of Pennsylvania (the “PA Enforcement Action”). This action alleges NSR violations under the federal Clean Air Act and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. The PA Enforcement Action appears to raise the same issues regarding Allegheny’s Pennsylvania generation facilities that are before the federal District Court in the West Virginia DJ Action, except that the PA Enforcement Action also includes the PA DEP and the Maryland Attorney General. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. On May 30, 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. On July 26, 2006, at a status conference, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. On November 18, 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case and has since entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. A ruling on those issues is expected within the first quarter of 2010. Trial has been tentatively scheduled to begin on September 13, 2010.

In addition to this lawsuit, on September 21, 2007, Allegheny received a Notice of Violation (“NOV”) from the EPA alleging NSR and PSD violations under the federal Clean Air Act, as well as Pennsylvania and West Virginia state laws. The NOV was directed to AE, Monongahela and West Penn and alleges violations at the Hatfield’s Ferry and Armstrong generation facilities in Pennsylvania and the Fort Martin and Willow Island generation facilities in West Virginia. The projects identified in the NOV are essentially the same as the projects at issue for these four facilities in the May 20, 2004 Notice, the West Virginia DJ Action and the PA Enforcement Action.

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

 

38


Table of Contents

Clean Water Act Compliance

In 2004, the EPA issued a final rule requiring all existing power plants with once-through cooling water systems withdrawing more than 50 million gallons of water per day to meet certain standards to reduce mortality of aquatic organisms pinned against the water intake screens or, in some cases, drawn through the cooling water system. The standards varied based on the type and size of the water bodies from which the plants draw their cooling water.

In January 2007, the Second Circuit Court of Appeals issued a decision on appeal that remanded a significant portion of the rule to the EPA. As a result, the EPA suspended the rule, except for a requirement, which existed prior to the EPA’s adoption of the 2004 rule, that permitting agencies use best professional judgment (“BPJ”) to determine the best technology available for minimizing adverse environmental impacts for existing facility cooling water intakes. Pending re-issuance of the 2004 rule by the EPA, permitting agencies thus will rely on BPJ determinations during permit renewal at existing facilities.

On April 1, 2009, the U.S. Supreme Court reversed the appeals court decision and upheld EPA’s authority to use cost/benefit analysis. The EPA has indicated that it plans to issue a proposed rule addressing the issues remanded by the Court by mid-2010 and to issue a final rule in 2012. Depending on the standards set by the EPA when it reissues this rule, Allegheny could incur significant costs for additional control equipment.

Monongahela River Water Quality

In late 2008, the PA DEP imposed water quality criteria for certain effluents, including total dissolved solid and sulfate concentrations in the Monongahela River, on new and modified sources, including the Scrubber project at the Hatfield’s Ferry generation facility. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply has appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively impact its ability to operate the Scrubbers. Preliminary studies indicate an initial capital investment of approximately $62 million in order to install technology to meet the total dissolved solid and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council who seek to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. No hearing date has been set. AE Supply intends to vigorously pursue these issues but cannot predict the outcome of these appeals. On November 7, 2009, the PA DEP published proposed amendments to the PA Chapter 95 rules that include an end-of-pipe limit for total dissolved solids for new and modified sources. The PA DEP’s proposed rule was open for public comment until February 12, 2010.

In October, 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the Scrubber project, the Fort Martin permit imposes effluent limitations for total dissolved solid and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for Monongahela to meet certain of the effluent limits that are effective immediately under the terms of the permit. Monongahela has appealed the Fort Martin permit and the administrative order. The appeal includes a request to stay certain of the conditions of the permit and order while the appeal is pending. The request to stay has been granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated and a hearing is likely to be scheduled for May 2010. The current terms of the Fort Martin permit would require Monongahela to incur significant costs or negatively impact operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the total dissolved solid and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. Monongahela intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

 

39


Table of Contents

Solid Waste

The EPA is reviewing its waste regulations relating to coal combustion byproducts (“CCB”) partly in response to a Tennessee Valley Authority ash spill in Kingston, Tennessee on December 22, 2008. CCB includes bottom ash, boiler slag, fly ash and Scrubber byproducts including gypsum. CCB has historically been designated and managed as a non-hazardous waste and the EPA has twice determined it is not appropriate to regulate it as a hazardous waste under the Resource Conservation and Recovery Act (“RCRA”). The EPA is reconsidering those earlier determinations and intends to issue new regulations for the management and disposal of CCB. The EPA has not yet reached a final decision on whether to regulate CCB as hazardous (RCRA Title C) or non-hazardous (RCRA Title D) or as a hybrid, but hopes to reach that decision during the first quarter of 2010. Should the EPA elect to designate CCB as hazardous at any point in its generation, storage, transportation or disposal cycle, it could significantly increase Allegheny’s cost of managing CCB materials. In addition to potential additional management costs, CCB generators could expect to see a reduction in options for beneficial reuse of CCB in applications such as mine reclamation, cement manufacture and agriculture, further increasing costs, as such materials will then enter landfills rather than beneficial reuse. The EPA might also designate CCB as hazardous only when it is destined for wet storage impoundments, which would reduce Allegheny’s potential waste management exposure.

Global Warming Class Action

On April 9, 2006, AE, along with numerous other companies with coal-fired generation facilities and companies in other industries, was named as a defendant in a class action lawsuit in the United States District Court for the Southern District of Mississippi. On behalf of a purported class of residents and property owners in Mississippi who were harmed by Hurricane Katrina, the named plaintiffs allege that the emission of greenhouse gases by the defendants contributed to global warming, thereby causing Hurricane Katrina and plaintiffs’ damages. The plaintiffs seek unspecified damages. On December 6, 2006, AE filed a motion to dismiss plaintiffs’ complaint on jurisdictional grounds and then joined a motion filed by other defendants to dismiss the complaint for failure to state a claim. At a hearing on August 30, 2007, the Court granted the motion to dismiss that AE had joined and dismissed all of the plaintiffs’ claims against all defendants. Plaintiffs appealed that ruling to the United States Court of Appeals for the Fifth Circuit. On October 6, 2009, the assigned panel of the appellate court issued a written opinion that reversed the judgment entered by the District Court in favor of the defendants with respect to certain of the plaintiffs’ claims and remanded the case to the District Court for further proceedings. On November 25, 2009, AE and others filed a petition to have all of the judges of the Fifth Circuit rehear the issues addressed in the panel’s October 6, 2009 opinion. There has been no ruling on that petition. AE intends to vigorously defend against this action but cannot predict its outcome.

 

40


Table of Contents

EMPLOYEES

Substantially all of Allegheny’s officers and other personnel are employed by AESC. As of December 31, 2009, AESC employed 4,383 employees. Of these employees, 1,223 are subject to collective bargaining arrangements. Approximately 72% of the unionized employees are at the Distribution Companies and approximately 28% are at AE’s other subsidiaries. As of December 31, 2009, System Local 102 of the Utility Workers Union of America (the “UWUA”) represents 1,037 employees, and locals of the International Brotherhood of Electrical Workers (the “IBEW”) represent 186 employees. Collective bargaining arrangements with the IBEW and UWUA expire during 2010 and 2011, respectively. Members of IBEW Local 50, which includes 34 members, recently ratified a new five-year labor agreement that will extend from March 1, 2010 through February 28, 2015. Contract negotiations with IBEW Local 2357, which includes 123 members, with respect to its current agreement that expires on February 28, 2010, are still ongoing. The parties have agreed to extend the existing contract through March 31, 2010, and union members are expected to vote on a new agreement at the beginning of March 2010.

Allegheny believes that current relations between it and its unionized and non-unionized employees are satisfactory.

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

 

41


Table of Contents

Executive Officers

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

 

Name

   Age   

Title

Paul J. Evanson

   68    Chairman, President, Chief Executive Officer and Director

Curtis H. Davis

   57    Chief Operating Officer, Generation

Rodney L. Dickens

   52    Vice President

Edward Dudzinski

   57    Vice President

David M. Feinberg

   40    Vice President, General Counsel and Secretary

Eric S. Gleason

   43    Vice President, Corporate Development and Quality

Kirk R. Oliver

   52    Senior Vice President and Chief Financial Officer

William F. Wahl, III

   50    Vice President, Controller and Chief Accounting Officer

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. 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.

Curtis H. Davis has been Chief Operating Officer, Generation, of AE since March 2008. Prior to joining Allegheny, Mr. Davis served as Senior Vice President for Duke Energy Corporation’s non-regulated generation fleet from January 2003 to February 2008. Prior to that, he served in various senior operational positions at Duke Energy Corporation.

Rodney L. Dickens has been Vice President of AE since joining Allegheny in June 2009 and also serves as President of Allegheny’s transmission and distribution business. Prior to joining Allegheny, Mr. Dickens was most recently Vice President, Asset Management and Centralized Services with Public Service Electric & Gas Company, where he worked in various capacities for the preceding 32 years.

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

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

Eric S. Gleason has been Vice President, Corporate Development and Quality, of AE since October 2009. Mr. Gleason joined Allegheny in August 2008 and served as Vice President, Corporate Development until October 2009. Prior to joining Allegheny, Mr. Gleason was employed by JPMorgan Chase & Co. since 2002, and served as Executive Director, Natural Resources Investment Banking from 2005 to 2008. Prior to that, he served as Vice President in the Investment Banking Division of Goldman, Sachs & Co.

Kirk R. Oliver has been Senior Vice President and Chief Financial Officer of AE since October 2008. Prior to joining Allegheny, Mr. Oliver was employed by Hunt Power since June 2006 and served as a senior executive from June 2007 to October 2008. Prior to that, Mr. Oliver spent eight years at TXU Corp, starting as Treasurer and then serving as Executive Vice President and Chief Financial Officer.

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

 

42


Table of Contents

ITEM 1A.    RISK FACTORS

Allegheny is subject to a variety of significant risks that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond its control. A number of these risks are identified below, in addition to the matters set forth under “Special Note Regarding Forward-Looking Statements.” Allegheny’s susceptibility to certain risks could exacerbate other risks. These risk factors should be considered carefully in evaluating Allegheny’s risk profile.

Risks Relating to the Merger with FirstEnergy

Allegheny may be unable to obtain the approvals required to complete its merger with FirstEnergy or, in order to do so, the combined company may be required to comply with material restrictions or conditions.

On February 11, 2010, Allegheny announced the execution of a merger agreement with FirstEnergy. Before the merger may be completed, both Allegheny and FirstEnergy will need to obtain shareholder approval for the proposed transaction. In addition, various filings must be made with FERC and various utility regulatory, antitrust and other authorities in the United States. These governmental authorities may impose conditions on the completion, or require changes to the terms, of the merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following completion of the merger. These conditions or changes could have the effect of delaying completion of the merger or imposing additional costs on or limiting the revenues of the combined company following the merger, which could have a material adverse effect on the financial results of the combined company and/or cause either Allegheny or FirstEnergy to abandon the merger.

If Allegheny and FirstEnergy are unable to complete the merger, we still will incur and will remain liable for significant transaction costs, including legal, accounting, financial advisory, filing, printing and other costs relating to the merger whether or not it is completed. Also, depending upon the reasons for not completing the merger, including whether Allegheny has received or entered into a competing takeover proposal, Allegheny may be required to pay FirstEnergy a termination fee of up to $150 million and reimburse FirstEnergy for its transaction expenses up to $45 million. Additionally, under specified circumstances in which the merger is not completed but the $150 million termination fee is not payable, Allegheny may nevertheless be required to reimburse FirstEnergy for its transaction expenses up to $45 million. Any such payment could have a material adverse effect on Allegheny’s business, results of operations, cash flows and financial condition. See consolidated financial statement Note 27, “Subsequent Event – Merger Agreement.”

If completed, Allegheny’s merger with FirstEnergy may not achieve its intended results.

Allegheny and FirstEnergy entered into the merger agreement with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Allegheny and FirstEnergy are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial results and prospects.

Allegheny will be subject to business uncertainties and contractual restrictions while the merger with FirstEnergy is pending that could adversely affect Allegheny’s financial results.

Uncertainty about the effect of the merger with FirstEnergy on employees, customers and suppliers may have an adverse effect on Allegheny. Although Allegheny intends to take steps designed to reduce any adverse effects, these uncertainties may impair Allegheny’s ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with Allegheny to seek to change existing business relationships.

 

43


Table of Contents

Employee retention and recruitment may be particularly challenging prior to the completion of the merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite Allegheny’s retention and recruiting efforts, key employees depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, Allegheny’s financial results could be affected.

The pursuit of the merger and the preparation for the integration of Allegheny and FirstEnergy may place a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could affect Allegheny’s business, results of operations and financial condition.

In addition, the merger agreement restricts Allegheny, without FirstEnergy’s consent, from making certain acquisitions and taking other specified actions until the merger occurs or the merger agreement terminates. These restrictions may prevent Allegheny from pursuing otherwise attractive business opportunities and making other changes to its business prior to completion of the merger or termination of the merger agreement.

Risks Relating to Regulation

Allegheny is subject to substantial governmental regulation. Compliance with current and future regulatory requirements and the need to obtain 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 and construction, sales of securities, asset sales and accounting policies and practices. Although Allegheny believes that the necessary authorizations, permits, approvals and certificates have been obtained for its existing operations and that its business is conducted in accordance with applicable laws, it cannot predict the impact of any future revisions or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to it. See “Environmental Matters” and “Regulatory Framework Affecting Allegheny.”

Changes in regulations or the imposition of additional regulations could influence Allegheny’s operating environment and may result in substantial costs to Allegheny, which could have an adverse effect on its business, results of operations, cash flows and financial condition.

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

Allegheny’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and site remediation and may, in the future, become subject to new and potentially more extensive environmental regulations, including but not limited to regulations intended to address climate change. Compliance with these laws and regulations may require Allegheny to expend significant financial resources to, among other things, meet air emission and water quality standards, conduct site remediation, perform environmental monitoring, purchase emission allowances, use alternative fuels, install and operate pollution control equipment at its generation facilities 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

 

44


Table of Contents

may be subject to civil liabilities or criminal penalties and may be required to incur significant expenditures to come into compliance. In addition, any alleged violations of environmental laws and regulations may require Allegheny to expend significant resources defending itself against such alleged violations. Either result could have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

Allegheny also may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations. For example, applicable standards under the EPA’s NSR initiatives remain in flux. Under the Clean Air Act, modification of Allegheny’s generation facilities in a manner that causes increased emissions could subject Allegheny’s existing facilities to the far more stringent NSR standards applicable to new facilities.

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

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

Shifting state and federal regulatory policies impose risks on Allegheny’s operations. Compliance with emerging regulatory initiatives could require Allegheny to incur significant costs. 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, the restructuring of transmission regulation and energy efficiency and conservation. Any new requirements arising from these actions could lead to increased operating expenses and capital expenditures, the full 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 it is possible that, in an economic downturn, price increases resulting from the transition to market rates could be smaller than previously anticipated, the heightened public and political concern over the transition to market rates could nevertheless be exacerbated by the current deteriorating national economic climate and its potential effects on consumers.

In Pennsylvania, many of the state’s electric utilities, including Allegheny, are scheduled to transition to market rates in 2010 and 2011, when applicable generation rate caps expire. Significant price increases in other states following the end of such regulatory transition periods have created a heightened political concern regarding price volatility in Pennsylvania following the expiration of its rate caps. In September 2007, a special legislative session was convened in Pennsylvania to consider various energy proposals. During the special session, several proposed bills involving the extension of rate caps were introduced. Currently, generation rate caps for Allegheny’s Pennsylvania customers expire at the end of 2010. While the Pennsylvania General

 

45


Table of Contents

Assembly adopted legislation in October 2008 that includes a number of conservation and demand-side management measures and procurement procedures, it does not address rate mitigation or the transition to market rates. However, there can be no assurance that the Pennsylvania legislature will not adopt such measures in the future. See “Regulatory Matters.”

Other proposals to re-regulate the industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which Allegheny operates. Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have an adverse effect on its business, results of operations, cash flows and financial condition. At a minimum, these types of actions raise uncertainty concerning the continued development of competitive power markets. Given Allegheny’s multi-state operations and asset base, re-regulation of restructured obligations could prove intricate, time-consuming and costly to ongoing operations.

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

Furthermore, some of the states in which Allegheny operates have enacted or are considering various energy efficiency and conservation programs, which could prove costly for Allegheny. In 2008, for example, Pennsylvania adopted Act 129, which includes a number of provisions relating to conservation, demand-side management and power procurement processes. Maryland has adopted some similar measures as part of its EmPOWER Maryland initiative. Among other things, Act 129 requires the implementation of smart meter technology, in connection with which Allegheny expects to incur substantial costs. Although Act 129 includes cost recovery provisions, any delay in or denial of cost recovery could adversely affect Allegheny. Additionally, failure to comply with Act 129 could result in significant penalties. See “Regulatory Matters.”

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. See “Regulatory Framework Affecting Allegheny.”

Allegheny could be subject to significant penalties if it violates mandatory NERC reliability standards.

The Energy Policy Act amended the FPA to, among other matters, provide for mandatory reliability standards designed to assure the reliable operation of the bulk power system. NERC established, and the FERC approved, reliability standards that impose certain operating, record-keeping and reporting requirements on the Distribution Companies, TrAIL Company, PATH, LLC, AE Supply and AGC. NERC delegated the day-to-day implementation and enforcement of these standards to eight regional oversight entities, including ReliabilityFirst, of which Allegheny is a member.

Allegheny has been, and will continue to be, subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirst is currently conducting several violation investigations that have been self-reported by Allegheny. The results of these proceedings and investigations have not had, and are not expected to have, any material impact on Allegheny’s operations or the results thereof. It is possible, however, that any violation of these mandatory standards could subject Allegheny to civil fines imposed by FERC for up to $1.0 million per day, per violation, which could have an adverse effect on Allegheny’s results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny.”

 

46


Table of Contents

The TrAIL Project and the PATH Project are subject to permitting and state regulatory approvals, and the failure to obtain any of these permits or approvals could have an adverse effect on Allegheny’s business.

The construction of both the TrAIL Project and the PATH Project are subject to the prior approval of various regulatory bodies. TrAIL Company has obtained the state siting approvals (subject to a pending appeal in Pennsylvania) necessary to construct TrAIL and is continuing to pursue necessary permits. Allegheny met with substantial political opposition, as well as opposition from environmental, community and other groups, in obtaining siting approval for TrAIL and is likely to encounter similar opposition with regard to the PATH Project. There can be no assurance that Allegheny will be able to obtain the regulatory approvals required in connection with these projects, particularly the siting approvals required to construct PATH, on a timely basis or at all. The inability to obtain any required state approval or other regulatory approval as a result of such opposition or otherwise, may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny.”

The pending sale of Potomac Edison’s Virginia distribution assets is subject to the approval of the Virginia SCC, the denial of which could have an adverse effect on Allegheny’s financial condition.

The pending sale of Potomac Edison’s distribution business in Virginia is subject to regulatory approval, which the Virginia SCC may not grant. On May 4, 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative for cash proceeds of approximately $340 million, subject to state and federal regulatory approval, certain third-party consents and applicable price adjustments. On September 15, 2009, Potomac Edison and the Cooperatives filed with the Virginia SCC a joint request for approval of the transaction. The Virginia SCC issued a procedural order scheduling an evidentiary hearing on the matter for March 2, 2010. On January 29, 2010, consultants retained by the Staff of the Virginia SCC filed testimony analyzing the transaction, asserting that current Virginia customers of Potomac Edison would pay $370 million more in rates over nine years if the Cooperatives take over service to those customers. Potomac Edison and the Cooperatives filed rebuttal testimony on February 12, 2010. Any failure to consummate the proposed sale, whether as a result of actions by the Virginia SCC or otherwise, may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition. See “Regulatory Framework Affecting Allegheny.”

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

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

Risks Relating to Allegheny’s Operations

Decreasing demand for electric power, as well as for certain commodities underlying the production of electric power and the related decline in market prices for power are adversely affecting Allegheny’s business.

During 2009, customer demand for electric power in Allegheny’s region fell significantly as a result of the ongoing economic recession and mild summer weather, among other factors. Overall demand for some of the commodities that underlie the production of electricity, and as a result the prevailing prices for those commodities, have also declined. Although power prices may be influenced by many factors, weakening demand for electricity, together with significantly lower commodity prices, have contributed to sharp declines in market prices for power over the past 12 to 15 months. Partly as a consequence of these declines, AE Supply generated significantly less power in 2009 than in 2008.

 

47


Table of Contents

Allegheny can make no assurances regarding the impact of any economic recovery on demand and market prices for power. Improvements in demand and market prices for power, if any, may lag any future improvements in overall economic conditions, and it is also possible that the current economic climate could result in long-term reduction of demand for power in our region, particularly among large industrial consumers. It is also possible that changes in customer behavior, as a result of conservation programs such as EmPOWER Maryland and Pennsylvania’s Act 129 or otherwise, could result in long-term reductions in demand for power.

Allegheny’s coal inventories have, at times, exceeded desirable levels as a result of recent decreases in our power production resulting from declines in demand and market prices for power.

AE Supply and Monongahela have various longer term coal supply contracts in place that are intended to partially mitigate our exposure to negative fluctuations in coal prices. In some cases, these contracts may require that AE Supply or Monongahela purchase a minimum volume of coal over a given time period. However, as a result of falling demand and market prices for power, Allegheny experienced declines in 2009 in the frequency with which its coal burning power plants operated. As a result, Allegheny’s coal consumption decreased significantly. Although Allegheny has been able to defer or cancel deliveries under certain contracts, it has at times been required to purchase coal in excess of immediate needs, resulting in coal inventories at some of its facilities that exceed what it considers to be optimal levels, which could have an adverse impact on its business. As coal inventories reach levels in excess of optimal levels, Allegheny may be unable to accept future deliveries at one or more of its facilities and may need to pursue alternative arrangements, including third party sales of inventory at levels below its cost, arrangements for third-party storage of a portion of its coal inventory, and modifications to its existing coal supply agreements.

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

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

Allegheny’s supercritical generation facilities were originally constructed in the late 1960s and early 1970s, and many of its other generation facilities were constructed prior to that time. Older equipment, even if maintained in accordance with good engineering practices, may require significant maintenance and capital expenditures to operate at peak efficiency or availability. If Allegheny underestimates required maintenance expenditures or is unable to make required capital expenditures due to liquidity constraints, it risks incurring more frequent unplanned outages, higher than anticipated maintenance expenditures, increased operation at higher cost of some of its less efficient generation facilities and the need to purchase power from third parties to meet its supply obligations, possibly at times when the market price for power is high, all of which may have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

Allegheny’s operating results are subject to seasonal and weather fluctuations and other factors that affect customer demand.

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 in Allegheny’s service territory peaks during the summer and winter months. 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 Regulated Operations 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.

 

48


Table of Contents

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 an adverse impact on Allegheny’s business, results of operations, cash flow and financial condition.

Allegheny’s results also may be negatively impacted as a result of other circumstances that affect customer demand for power. For example, it is possible that the current economic downturn, as well as conservation efforts such as the EmPOWER Maryland program and Pennsylvania’s Act 129, have and will continue to contribute to changes in customer behavior, which may result in a significant reduction in demand, particularly among commercial and industrial customers, which could, in turn, have an adverse impact on Allegheny’s business, results of operations, cash flow and financial condition.

Changes in weather patterns as a result of global warming could have an adverse effect on Allegheny’s business.

Allegheny also could be impacted to the extent that global warming trends affect established weather patterns or exacerbate extreme weather or weather fluctuations. Although Allegheny’s physical assets are located in a region in which they are unlikely to experience detrimental physical damage from the rising sea levels that have been modeled in various analyses that attempt to predict the effects of global warming, other weather-related effects that could be associated with global warming, such as an increase in the frequency and/or severity of storms or other significant climate changes within or outside of Allegheny’s service territory, may have an adverse impact on Allegheny’s business, results of operations, cash flow and financial condition.

Allegheny’s assets are subject to other risks beyond its control, including, but not limited to, accidents, storms, natural catastrophes and terrorism.

Much of the value of Allegheny’s business consists of its portfolio of power generation and T&D assets. Allegheny’s ability to conduct its operations depends on the integrity of these assets. The cost of repairing damage to its facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events may exceed available insurance, if any, for repairs, which may adversely impact Allegheny’s business, results of operations, cash flows and financial condition. Although Allegheny has taken, and will continue to take, reasonable precautions to safeguard these assets, Allegheny can make no assurance that its facilities will not face damage or disruptions or that it will have sufficient insurance, if any, to cover the cost of repairs. In addition, in the current geopolitical climate, enhanced concern regarding the risks of terrorism throughout the economy may impact Allegheny’s operations in unpredictable ways. Insurance coverage may not cover costs associated with any of these risks adequately or at all. While some losses may be recoverable through regulatory proceedings, the delay and uncertainty of any such recovery may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

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

Allegheny is dependent on coal for much of its electric generation capacity. Allegheny has coal supply contracts in place that partially mitigate its exposure to negative fluctuations in coal prices. However, Allegheny can provide no assurance that the counterparties to these agreements will fulfill their obligations to supply coal. The suppliers under these agreements may, as a general matter, experience financial, legal or technical problems that inhibit their ability to fulfill their obligations. Among other circumstances, the prevailing constrained credit markets and overall negative economic conditions may affect the ability of Allegheny’s suppliers to access the capital markets and maintain adequate liquidity to sustain their respective businesses. Additionally, to the extent that any of Allegheny’s coal suppliers seek bankruptcy protection, they may, in the current climate, be unable to obtain the financing necessary to continue their operations in bankruptcy and reorganize and, thus, may be forced to liquidate. Various industry and operational factors, including increased costs, transportation constraints, safety issues and operational difficulties may have negative effects on coal supplier performance. During periods of rising coal prices, the factors impacting supplier performance could have a more pronounced financial impact.

 

49


Table of Contents

Furthermore, the suppliers under these agreements may not be required to supply coal to Allegheny under certain circumstances, such as in the event of a natural disaster. If Allegheny is unable to obtain its coal requirements under these contracts, it may be required to purchase coal at higher prices. In addition, although these agreements generally contain specified prices, they also may provide for price adjustments related to changes in specified cost indices, as well as specific events, such as changes in regulations affecting the coal industry. Finally, it is possible that, in the future, market prices for coal could fall below the prices at which we have agreed to purchase coal under our long-term contracts. Changes in the supply and price of coal may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Additionally, Allegheny is subject to other fuel-related costs, which may fluctuate. For example, Allegheny has experienced, and may continue to experience, increases in its fuel handling and transportation costs and its costs to procure lime, urea and other materials necessary to the operation of its pollution controls. Significant increases in these and other fuel related costs could have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

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

Allegheny’s SO2 and NOx allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities, as well as the implementation of environmental controls. Fluctuations in the availability or cost of these emission allowances could have a material adverse effect on Allegheny’s business, financial condition, cash flows and results of operations. It is also possible that any climate change legislation will incorporate a cap and trade scheme involving CO2 emission allowances. In that case, the cost and availability of CO2 emission allowances could have an adverse effect on Allegheny’s business, financial condition, cash flows and results of operations. See “Environmental Matters.”

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

Allegheny currently is involved in a number of capital intensive projects, including the TrAIL Project, the PATH Project and the implementation of smart meter and other information technology necessary to comply with Pennsylvania’s recently-enacted Act 129. Allegheny’s ability to successfully complete these projects in a timely manner, within established budgets and without significant operational disruptions is contingent upon many variables, many of which are outside of its control. Failure to complete these projects as planned may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

Additionally, Allegheny has contracted with specialized vendors in connection with these projects, and may in the future enter into additional such contracts with respect to these and other capital projects. As such, Allegheny is exposed to the risk that these contractors may not perform as required under their contracts. Such a failure could occur for any number of reasons. Among other things, it is possible that the prevailing constrained credit markets and overall negative economic conditions may affect the ability of Allegheny’s contractors, subcontractors, suppliers and vendors to access the capital markets and maintain adequate liquidity to sustain their respective businesses. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all. Any inability to make such alternate arrangements or any substantial delays or increases in costs associated therewith may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition. For additional information regarding Act 129, see “Regulatory Matters.”

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

Because Allegheny has transferred functional control of its transmission facilities to PJM, 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

 

50


Table of Contents

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; the RPM; the locational marginal pricing mechanism; 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, changes in PJM’s credit and collateral requirements, deterioration in the credit quality of other PJM members, socialization of member defaults, the withdrawal from, or addition to, PJM of other transmission owners, may have an adverse effect on Allegheny’s results of operations, cash flow and financial condition.

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

In connection with regulations governing the transition to market competition, West Penn is 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 through the end of 2010. West Penn satisfies these obligations by purchasing power under a contract with AE Supply. At times, AE Supply may not earn as much as it otherwise could by selling power priced at its contract rates to West Penn instead of into competitive wholesale markets. In addition, AE Supply’s obligations under the agreement 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, West Penn’s capped rates may be below current wholesale market prices through the applicable transition periods. As a consequence, West Penn may at times pay more for power than it can charge retail customers and may be unable to pass the excess costs on to its retail customers. Changes in customer switching behavior could also alter both AE Supply’s and the utilities’ obligations under these agreements.

Allegheny is exposed to price volatility as a result of its participation in wholesale energy markets.

AE Supply buys and sells electricity in wholesale markets, which exposes Allegheny to the risks of rising and falling prices in those markets. Among the factors that can influence such prices are:

 

   

the balance of supply and demand for electricity, which may be influenced by any number of factors, including but not limited to prevailing weather and economic conditions;

 

   

fuel costs, the cost of emissions allowances and other production costs;

 

   

transmission constraints;

 

   

changes in PJM rules and other changes in the regulatory framework for wholesale power markets; and

 

   

market liquidity and the credit worthiness of market participants.

As a result of these and other factors, wholesale market prices for electricity may fluctuate substantially over relatively short periods of time and can be unpredictable, and may have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Allegheny’s use of derivative instruments for hedging purposes may result in financial losses.

Allegheny uses derivative instruments, such as futures, swaps, forwards and financial transmission rights, to manage its commodity and financial market risks. Allegheny could recognize losses on these contracts as a result of volatility in the market values of the underlying commodities or to the extent that a counterparty fails to perform. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these instruments involves management’s judgment or use of estimates. Furthermore, changes in the value of derivatives designated under hedge accounting to the extent not fully offset by changes in the value of the hedged transaction can result in ineffectiveness losses that may have an adverse effect on Allegheny’s results of operations.

 

51


Table of Contents

Recently, members of Congress and various federal regulatory agencies, including the SEC, the Commodity Futures Trading Commission and the U.S. Treasury Department, have put forth proposals regarding the potential for more stringent regulation of the over-the-counter (“OTC”) derivatives markets. If ultimately adopted, such regulations could include requirements for greater standardization and more centralized trading of these instruments. Some have proposed that OTC derivatives trading take place on organized exchanges. Depending upon its specific terms, it is possible that any new legislation or regulation in this regard could significantly increase Allegheny’s costs with respect to, or otherwise constrain its ability to effectively use, these instruments to manage financial risks, which could have an adverse effect on Allegheny’s business, results of operations, cash flows and financial condition.

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, at times made it difficult for Allegheny to hedge its power supply obligations and fuel requirements. Although substantial improvements have been made in Allegheny’s credit position over the past few years, significant unanticipated changes in commodity market liquidity and/or Allegheny’s access to the commodity markets, including as a result of any decline in Allegheny’s credit ratings (including ratings for AE, AE Supply or Monongahela), 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. Furthermore, if Allegheny’s credit ratings were to decline, it would likely be required to deposit additional cash or cash-equivalent collateral with its hedging counterparties, which could have a negative impact on Allegheny’s liquidity and commodity trading activities.

As widely reported, the financial markets and overall economies in the United States and abroad are currently undergoing a period of significant uncertainty and volatility. These conditions can adversely impact the liquidity of the commodity markets in which Allegheny may wish to transact and may negatively affect the ability of Allegheny’s counterparties to honor their commitments. This, in turn, could inhibit Allegheny’s ability to transact in the desired timeframe or at a satisfactory price, which could increase Allegheny’s exposure to commodity price fluctuations and may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial conditions.

Allegheny’s policies and procedures cannot eliminate all risk involved in its energy commodity activities.

Allegheny may not always hedge the entire exposure of its operations to commodity price volatility. Furthermore, Allegheny’s risk management, wholesale marketing, fuel procurements and energy trading activities, including its decisions to enter into power sales or purchase agreements, rely on models that depend on the judgments and assumptions regarding factors such as generation facility availability, future market prices, weather and the demand for electricity and other energy-related commodities. Many of these models are developed utilizing statistical relationships between numerous interrelated factors. Such relationships can change significantly in an unpredictable manner, especially during periods of significant volatility. Even when Allegheny’s policies and procedures are followed and decisions are made based on these models, Allegheny’s policies and procedures cannot eliminate all risk involved in its energy commodity activities. Allegheny’s financial position and results of operations may be adversely affected if the judgments and assumptions underlying its models prove to be inaccurate or commodity prices otherwise fluctuate in ways that Allegheny does not anticipate.

Failure to retain and attract key executive officers and other skilled professionals and technical employees could have an adverse effect on Allegheny’s operations.

Allegheny’s business is dependent on its ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high. At the same time, Allegheny has an aging workforce. The inability to

 

52


Table of Contents

attract new employees, whether to appropriately replace retiring and other departing employees or otherwise, and to retain and motivate existing employees may have an adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.

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

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

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

The Distribution Companies have been named as defendants in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at Allegheny-owned facilities where suitable alternative materials are not available. Allegheny’s management believes that any remaining asbestos at Allegheny-owned facilities is contained. The continued presence of asbestos and other regulated substances at Allegheny-owned facilities, however, could result in additional actions being brought against Allegheny. See “Legal Proceedings” and consolidated financial statement Note 19, “Asset Retirement Obligations (“ARO”).”

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. Recent results in the capital markets have increased the level of underfunding in the pension plan. Under applicable law, Allegheny is required to make cash contributions to the extent necessary to comply with minimum funding requirements imposed by regulatory requirements. The amount of and timing of such required cash contribution(s) is based on an actuarial valuation of the plan. The funded status of the plan can be affected by investment returns on plan assets, discount rates, mortality rates of plan participants, pension reform legislation and a number of other factors. There can be no assurance that the value of Allegheny’s pension plan assets will be sufficient to cover future liabilities. Although Allegheny has made significant contributions to its pension plan in recent years, it is possible that Allegheny could incur a significant pension liability adjustment, or could be required to make significant additional cash contributions to its plan, which would reduce the cash available for business and other needs.

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

The energy sector has been the subject of negative publicity, most recently in the context of the dialogue regarding climate change. Allegheny has come under some scrutiny in this regard, and also has faced public opposition in connection with its transmission expansion initiatives, as well as certain of its demand-side conservation efforts and ordinary utility rate increases. Negative publicity of this nature may make legislators, regulators and courts less likely to take a favorable view of energy companies in general and/or Allegheny, specifically, which could cause them to make decisions or take actions that are adverse to Allegheny.

 

53


Table of Contents

Risks Related to Allegheny’s Leverage and Financing Needs

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

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

 

   

a recession, including the current recession, or other 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.

As widely reported, the financial markets and overall economies in the United States and abroad are currently undergoing a period of significant uncertainty and volatility. As a result, Allegheny’s management has placed increased emphasis on monitoring the risks associated with the current environment. At this point in time, there has not been a materially negative impact on Allegheny’s liquidity. However, there can be no assurance that the cost or availability of future borrowings or other financings, if any, will not be impacted by the ongoing or future capital market disruptions.

AE’s and AE Supply’s revolving credit facilities currently are well-diversified, including more than 20 lenders at December 31, 2009. Additionally, TrAIL Company and Monongahela recently entered into separate revolving credit facilities, both of which also include a diverse group of lenders. Allegheny currently anticipates that these lenders will participate in future requests for funding. However, there can be no assurance that further deterioration in the credit markets and overall economy will not affect the ability of Allegheny’s lenders to meet their funding commitments. Additionally, Allegheny’s lenders have the ability to transfer their commitments to other institutions, and the risk that committed funds may not be available under distressed market conditions could be exacerbated to the extent that consolidation of the commitments under Allegheny’s facilities or among its lenders occurs.

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

Allegheny has substantial leverage. At December 31, 2009, Allegheny had approximately $4.56 billion of debt on a consolidated basis. Approximately $1.85 billion represented debt of AE Supply and AGC, $455 million represented debt of TrAIL Company, and the remainder constituted debt of one or more of the Distribution Companies or their subsidiaries.

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

 

   

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

 

   

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

 

54


Table of Contents
   

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

 

   

limit Allegheny’s ability to borrow additional funds; and

 

   

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

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

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

 

   

borrow funds;

 

   

incur liens and guarantee debt;

 

   

enter into a merger or other change of control transaction (other than the proposed merger with First Energy, for which Allegheny has obtained the requisite consent of the relevant lenders);

 

   

make investments;

 

   

dispose of assets; and

 

   

pay dividends and other distributions on its equity securities.

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

A downgrade or negative outlook in Allegheny’s credit ratings could increase its financing costs and the cost of maintaining certain contractual relationships.

Allegheny cannot be assured that any of its current credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in the agency’s judgment, circumstances in the future so warrant. Among other reasons, Allegheny’s credit ratings may change as a result of the differing methodologies used by various rating agencies or as a result of changes to those methodologies. Any downgrade or negative outlook in Allegheny’s credit ratings may increase its financing costs and the cost of maintaining certain contractual relationships. Among other things, if Allegheny’s credit ratings were to decline, it would likely be required to deposit additional cash or cash-equivalent collateral with its hedging counterparties, which would have a negative impact on Allegheny’s liquidity. Thus, a downgrade or negative outlook in Allegheny’s credit ratings may have an adverse effect on its business, results of operations, cash flows and financial condition.

AE has no income or cash flow apart from dividends paid or other obligations due it from its subsidiaries.

AE is a holding company and has no operations of its own. As a result, its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent upon the earnings and cash flow of its operating subsidiaries and their ability to pay dividends or make other distributions to, or repay loans from, AE. AE’s subsidiaries are distinct entities that have no obligations to make dividends or other distributions to AE, and their ability to do so is contingent upon their respective earnings and a number of other business considerations, including in some circumstances regulatory constraints.

ITEM  1B.    UNRESOLVED STAFF COMMENTS

None.

 

55


Table of Contents

ITEM 2.    PROPERTIES

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. Some of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations. Specifically, certain of the properties and other assets owned by AE Supply and Monongahela that were financed by solid waste disposal and pollution control notes are subject to liens securing the obligations under those notes.

In many cases, the properties of Monongahela, Potomac Edison, West Penn and other AE subsidiaries may be subject to certain reservations, minor encumbrances and title defects that do not materially interfere with their use. The indenture under which AGC’s unsecured debentures are issued prohibits AGC, with certain limited exceptions, from incurring or permitting liens to exist on any of its properties or assets unless the debentures are contemporaneously secured equally and ratably with all other debt secured by the lien. Most T&D lines, some substations and switching stations and some ancillary facilities at generation facilities are on lands of others, in some cases by sufferance but, in most instances, pursuant to leases, easements, rights-of-way, permits or other arrangements, many of which have not been recorded and some of which are not evidenced by formal grants. In some cases, no examination of titles has been made as to lands on which T&D lines and substations are located. Each of the Distribution Companies possesses the power of eminent domain with respect to its public utility operations. See “Business—Electric Facilities,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and consolidated financial statement Note 8, “Capitalization and Debt.”

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. Other ancillary offices exist throughout the Distribution Companies’ service territories. Additionally, Allegheny began construction in 2009 of a facility located in Fairmont, West Virginia that will serve as the center for Allegheny’s multi-state transmission functions. Construction of this facility is expected to be completed in the fall of 2010.

ITEM 3.    LEGAL PROCEEDINGS

Allegheny is involved in a number of significant legal proceedings. In certain cases, plaintiffs seek to recover large and sometimes unspecified damages, and some matters may be unresolved for several years. Allegheny cannot currently determine the outcome of the proceedings described below or the ultimate amount of potential losses. Pursuant to SFAS 5, management provides for estimated losses to the extent that information becomes available indicating that losses are probable and that the amounts are reasonably estimable. Additional losses may have an adverse effect on Allegheny’s results of operations, cash flows and financial condition.

Shareholder Actions

Purported AE shareholders have filed derivative and class action lawsuits in state courts in Pennsylvania and Maryland against AE and each of the members of AE’s Board of Directors that seek to enjoin Allegheny’s proposed merger with FirstEnergy and, in some cases, damages in the event that the merger is completed. Allegheny intends to vigorously defend against these claims but cannot predict their outcome.

Nevada Power Contracts

On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with the FERC against AE Supply seeking action by the FERC to modify prices payable to AE Supply under three trade confirmations

 

56


Table of Contents

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, the FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others. The FERC did not decide whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, the FERC issued an order, on rehearing, affirming its conclusion that the long-term contracts should not be modified. Snohomish County, NPC and other parties filed petitions for review of the FERC’s June 26, 2003 order with the United States Court of Appeals for the Ninth Circuit (the “NPC Petitions”). The NPC Petitions were consolidated in the Ninth Circuit. On December 19, 2006, the Ninth Circuit issued an opinion remanding the case to the FERC to determine, in accordance with the guidance set forth in the Ninth Circuit’s opinion, whether the FERC utilized the appropriate standard of review in deciding various claims, including NPC’s complaint. On May 3, 2007, AE Supply and others filed a petition to appeal the Ninth Circuit’s ruling to the United States Supreme Court. On June 26, 2008, the United States Supreme Court issued an opinion that rejected the Ninth Circuit’s reasoning, with instructions that the case be remanded to the FERC for amplification or clarification of its findings on two issues set forth in the opinion. The case has been remanded to the FERC, and the FERC issued an order on December 18, 2008 that provides for a paper hearing on the two issues identified by the United States Supreme Court, with initial filings due within 90 days and reply submissions within 90 days thereafter. However, the order holds those deadlines in abeyance, contingent upon settlement discussions between the parties, and a subsequent order lifting that stay has not been entered.

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

Claims 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 proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to the FERC, which arises out of claims previously filed with the FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). A judge has been assigned to the Lockyer case, and a hearing is now set for April 20, 2010, with an initial decision date of September 14, 2010. AE Supply and several other sellers have filed motions to dismiss the Lockyer case that are now pending before the assigned judge. On June 2, 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their 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

 

57


Table of Contents

been brought mostly by seasonal contractors’ employees and do not involve allegations of the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos and/or environmental insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.) 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.). Allegheny and Liberty Mutual Insurance Company resolved their dispute and, therefore, Civil Action No. 07-3168-BLS was voluntarily dismissed. The parties are seeking a declaration of coverage under the policies for asbestos-related and environmental claims.

Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. As of December 31, 2009, Allegheny’s total number of claims alleging exposure to asbestos was 861 in West Virginia and four in Pennsylvania. Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.

Environmental Matters

In addition to the matters described above, Allegheny is involved in litigation relating to compliance with certain environmental laws and regulations. See “Environmental Matters.”

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.

ITEM 4.    RESERVED.

 

58


Table of Contents

PART II

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

AE’s common stock is publicly traded. “AYE” is the trading symbol for AE’s common stock on the New York Stock Exchange. As of February 24, 2010, there were 17,130 holders of record of AE’s common stock. The table below shows the high and low sales prices of AE’s common stock in composite trading for the periods indicated:

 

     2009    2008
     High    Low    High    Low

1st Quarter

   $ 35.97    $ 20.32    $ 64.75    $ 45.46

2nd Quarter

   $ 29.85    $ 22.70    $ 55.98    $ 49.38

3rd Quarter

   $ 27.70    $ 23.42    $ 51.14    $ 33.94

4th Quarter

   $ 27.15    $ 21.84    $ 36.61    $ 23.86

In 2009, AE declared cash dividends of $0.15 per share on its common stock that were payable on March 23, June 22, September 28 and December 28, 2009, to shareholders of record on March 9, June 8, September 14 and December 14, 2009, respectively. In 2008, AE declared cash dividends of $0.15 per share on its common stock that were payable on March 24, June 23, September 29 and December 29, 2008, to shareholders of record on March 10, June 9, September 15 and December 15, 2008, respectively.

The amount and timing of dividends payable on AE’s common stock are within the sole discretion of AE’s Board of Directors. The Board of Directors reviews the dividend rate periodically in light of Allegheny’s financial position and results of operations, legislative and regulatory developments affecting Allegheny and the industry in general, overall market conditions and any other factors that the Board of Directors deems relevant. See consolidated financial statement Note 15, “Dividend Restrictions.”

 

59


Table of Contents
ITEM 6.    SELECTED FINANCIAL DATA

ALLEGHENY ENERGY, INC. AND SUBSIDIARIES

 

     2009   2008   2007   2006   2005  

(In millions, except per share amounts)

                     

Income statement data for the year ended December 31:

         

Operating revenues

  $ 3,426.8   $ 3,385.9   $ 3,307.0   $ 3,121.5   $ 3,037.9   

Operating expenses

  $ 2,507.0   $ 2,576.4   $ 2,489.7   $ 2,389.2   $ 2,501.1   

Operating income

  $ 919.8   $ 809.5   $ 817.3   $ 732.3   $ 536.8   

Income from continuing operations attributable to Allegheny Energy, Inc.

  $ 392.8   $ 395.4   $ 412.2   $ 318.7   $ 75.1   

Income (loss) from discontinued operations, net of tax

  $ —     $ —     $ —     $ 0.6   $ (6.1

Net income attributable to Allegheny Energy, Inc.

  $ 392.8   $ 395.4   $ 412.2   $ 319.3   $ 63.1   

Weighted average number of diluted shares outstanding

    170.0     170.0     169.5     168.7     158.6   

Earnings per share attributable to Allegheny Energy, Inc.:

         

Income from continuing operations attributable to Allegheny Energy, Inc.

         

—Basic

  $ 2.32   $ 2.35   $ 2.48   $ 1.94   $ 0.48   

—Diluted

  $ 2.31   $ 2.33   $ 2.43   $ 1.89   $ 0.47   

Net income attributable to Allegheny Energy, Inc.

         

—Basic

  $ 2.32   $ 2.35   $ 2.48   $ 1.94   $ 0.40   

—Diluted

  $ 2.31   $ 2.33   $ 2.43   $ 1.89   $ 0.40   

Dividends per share

  $ 0.60   $ 0.60   $ 0.15   $ —     $ —     

Balance sheet data at December 31:

         

Property, plant and equipment, net

  $ 8,957.1   $ 8,002.2   $ 7,196.6   $ 6,512.9   $ 6,277.4   

Total assets

  $ 11,589.1   $ 10,811.0   $ 9,906.6   $ 8,552.4   $ 8,558.8   

Short-term debt

  $ —     $ —     $ 10.0   $ —     $ —     

Long-term debt due within one year

  $ 140.8   $ 93.9   $ 95.4   $ 201.2   $ 477.2   

Long-term debt

  $ 4,417.0   $ 4,115.9   $ 3,943.9   $ 3,384.0   $ 3,624.5   

Total equity

  $ 3,128.1   $ 2,855.7   $ 2,548.6   $ 2,115.1   $ 1,741.3   

 

60


Table of Contents

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

The primary purpose of Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is to provide information regarding Allegheny’s past and expected future performance in implementing its strategies and managing its risks and challenges. Allegheny’s MD&A includes the following sections:

 

   

“Overview” includes a discussion of overall challenges and recent development and initiatives.

 

   

“Results of Operations” provides an overview of Allegheny’s operating results in 2009, 2008 and 2007, including a review of earnings and results by reportable segment.

 

   

“Financial Condition—Liquidity and Capital Resources” provides an analysis of Allegheny’s liquidity position and credit profile, including its sources of cash (including bank credit facilities and sources of operating cash flow) and uses of cash (including contractual obligations and capital expenditure requirements) and the key risks and uncertainties that impact Allegheny’s past and future liquidity position and financial condition. This subsection also includes a listing and discussion of Allegheny’s current credit ratings.

 

   

“Market Risk Information” provides an explanation of Allegheny’s risk management programs relating to market risk and credit risk.

 

   

“Application of Critical Accounting Policies” provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of Allegheny and that require management to make significant estimates, assumptions or other judgments.

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 primarily through AE’s various directly and indirectly owned subsidiaries.

Allegheny changed the composition of its business segments during the fourth quarter of 2009, consistent with changes made to its management structure and the internal financial reporting used by its chief operating decision maker to regularly assess the performance of the business and allocate resources.

Prior to the change in composition of segments, the Generation and Marketing segment included the regulated generation operations of Monongahela and the unregulated operations of AE Supply, and the Delivery and Services segment included the regulated operations of the Distribution Companies (excluding Monongahela’s generation operations), TrAIL Company and PATH, LLC.

The changes in Allegheny’s reportable segments during 2009 consisted primarily of the following:

 

   

Monongahela’s regulated generation operations were moved from the Generation and Marketing segment to the Delivery and Services segment.

 

   

The Generation and Marketing segment was renamed the Merchant Generation segment.

 

   

The Delivery and Services segment was renamed the Regulated Operations segment.

 

61


Table of Contents

Allegheny’s business segments are as follows:

Merchant Generation Segment

The principal companies and operations in Allegheny’s Merchant Generation segment include the following:

 

   

AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities. AE Supply markets its electric generation capacity to various customers and markets, including supplying certain obligations of West Penn and Potomac Edison.

 

   

AGC is owned approximately 59% by AE Supply and approximately 41% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and Monongahela. AGC provides its share of the power generated by the Bath County generation facility to AE Supply and Monongahela in proportion to their ownership interests. Monongahela’s ownership interest in AGC is reflected as noncontrolling interest within the Merchant Generation segment and as an equity investment within the Regulated Operations segment.

Regulated Operations Segment

The principal companies and operations in Allegheny’s Regulated Operations segment include the following:

 

   

The Distribution Companies include Monongahela, 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 operates an electric T&D business and also owns and operates electric generation facilities in northern West Virginia.

 

   

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

 

   

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

 

   

TrAIL Company was formed in 2006 to develop, construct and operate transmission expansion projects, including the TrAIL Project.

 

   

PATH, LLC was formed in 2007 by Allegheny and a subsidiary of American Electric Power Company, Inc. (“AEP”) to develop, construct and operate the PATH Project. PATH, LLC is a series limited liability company. The “West Virginia Series” is owned equally by Allegheny and a subsidiary of AEP. The “Allegheny Series” is 100% owned by Allegheny.

The Regulated Operations segment includes the operations of the Virginia distribution business, which is expected to be sold following the completion of applicable regulatory proceedings, as described in consolidated financial statement Note 3, “Assets Held for Sale.”

All of Allegheny’s generation facilities are located within the PJM market. To facilitate the economic dispatch of generation, AE Supply and Monongahela sell power into the competitive wholesale energy market operated by PJM and purchase power from the PJM market to meet their obligations to supply power. See “Business” for more information regarding Allegheny’s business and the segments and subsidiaries discussed above.

 

62


Table of Contents

Shared Services

AESC is a service company for AE that employs substantially all of the Allegheny personnel who provide services to AE and its subsidiaries, including AE Supply, AGC, the Distribution Companies, TrAIL Company, PATH, LLC and their respective subsidiaries. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had 4,383 employees as of December 31, 2009.

Business Challenges

Allegheny faces a number of risks in its generation business, including electricity and capacity price risk, fuel supply and price risk, generating plant performance and evolving environmental and other regulations and requirements.

Allegheny has executed and continues to enter into contracts for energy sales and fuel supply purchase at varying prices and duration within established policies and guidelines. Allegheny’s future profitability will be affected by prevailing market conditions and the extent and the prices at which it has entered into intermediate or long-term power sales and fuel purchase agreements.

Allegheny manages the risks described above through various means including risk management programs that are designed to monitor and measure exposure to earnings and cash flow volatility related to changes in energy and fuel prices, counterparty credit quality and the operating performance of its generating units.

A significant challenge that Allegheny faces in its regulated operations business is to maintain high quality customer service and reliability in a cost-effective manner. Allegheny’s regulated operations are rate-regulated and are subject to regulatory risk with respect to costs that may be recovered and investment returns that may be collected through customer rates in each of its operating jurisdictions. As discussed in consolidated financial statement Note 6, “Regulatory Assets and Liabilities,” there are a number of ongoing regulatory matters that may affect Allegheny’s recovery of its costs. See “Risk Factors” for additional information regarding these and other risks that Allegheny faces in its business.

The ongoing effects of the economic recession made 2009 a challenging year for Allegheny. Significantly lower market prices for electricity in 2009 reduced realized revenues from the sale of unhedged generation output and, at times, caused Allegheny’s coal-fired plants to be placed in reserve status when they were otherwise available to generate power. The reduced demand caused by economic conditions also affected Allegheny’s regulated operations, with decreases in the demand for electricity in all customer categories, especially in the industrial sector.

While the effects of the economy adversely impacted Allegheny in 2009, Allegheny:

 

   

achieved the best safety performance in recent years in its delivery business and continued to improve safety performance in its generation business;

 

   

completed its scrubber construction projects at Fort Martin and Hatfield’s Ferry on time and under budget;

 

   

succeeded in controlling operation and maintenance costs;

 

   

refinanced $843 million of indebtedness, obtained additional liquidity, extended debt maturities and securitized the remaining Fort Martin scrubber costs;

 

   

moved forward with the construction of its TrAIL transmission expansion project, which remains on schedule for a June 2011 in-service date;

 

   

settled in both West Virginia and Virginia on its requests for fuel and purchase power cost recovery and filed a base rate case in West Virginia, for which an agreed-upon procedural schedule sets evidentiary hearings in early April 2010;

 

63


Table of Contents
   

launched several energy efficiency and conservation programs in Maryland and Pennsylvania; and

 

   

held four auctions to procure power to serve Pennsylvania customers for the period after rate caps expire at the end of 2010, such that its Pennsylvania utility now has two-thirds of 2011 residential power under contract.

Allegheny plans to continue its focus on the following areas in 2010:

 

   

maintaining its investment grade credit ratings and strengthening its financial condition and liquidity position;

 

   

controlling costs and spending throughout the organization while maintaining high levels of customer satisfaction;

 

   

continuing progress on transmission expansion projects;

 

   

resolving its West Virginia base rate case successfully;

 

   

developing and implementing energy efficiency and conservation programs;

 

   

managing the transition to market-based rates in Pennsylvania;

 

   

maintaining a culture that emphasizes the importance of safety throughout its organization; and

 

   

monitoring potential environmental legislation and regulations.

In addition, Allegheny will devote significant attention to matters relating to the proposed merger with FirstEnergy, including efforts to manage certain of the risks described in “Risk Factors.”

Liquidity

Allegheny relies on access to the financial markets as a source of liquidity. Allegheny strengthened its liquidity position and significantly reduced its intermediate term refinancing risk in 2009, during which it refinanced and extended the maturities of approximately $843 million of debt that had been scheduled to mature in 2011 and 2012. In addition, AE Supply entered into a new $1 billion revolving credit facility that matures in 2012, which replaced its previous $400 million revolving credit facility that was scheduled to mature in 2011, and Monongahela entered into a new $110 million senior unsecured revolving credit facility that matures in 2012. In December 2009, MP Environmental Funding LLC and PE Environmental Funding LLC issued $64.4 million and $21.5 million of senior secured environmental control bonds, respectively. Proceeds from the bonds represent restricted funds and will be used to fund certain costs to construct and install Scrubbers at Fort Martin, as well as related financing costs. In addition, on January 25, 2010, TrAIL Company issued $450 million of senior unsecured notes due in 2015 and also entered into a new $350 million senior unsecured revolving credit facility with a three-year maturity. TrAIL Company used the net proceeds from the sale of the notes, together with funds from its new credit facility, to repay all amounts outstanding under the $550 million senior unsecured credit facility that it entered into in 2008.

 

64


Table of Contents

RESULTS OF OPERATIONS

As described in consolidated financial statement Note 12, “Segment Information,” Allegheny changed the composition of its segments during the fourth quarter of 2009, consistent with changes made to the internal reporting used by its chief operating decision maker to regularly assess the performance of the business. All disclosures relating to Allegheny’s segments for 2008 and 2007 have been reclassified to conform to the 2009 presentations. Earnings attributable to Allegheny Energy, Inc. by segment for the years ended December 31 were as follows:

 

(In millions)

   2009    2008    2007

Earnings by Segment:

        

Merchant Generation

   $ 234.0    $ 324.3    $ 294.0

Regulated Operations

     157.9      70.2      117.2

Elimination of intercompany transactions

     0.9      0.9      1.0
                    

Consolidated net income attributable to Allegheny Energy, Inc.

   $ 392.8    $ 395.4    $ 412.2
                    

Basic earnings per share

   $ 2.32    $ 2.35    $ 2.48

Diluted earnings per share

   $ 2.31    $ 2.33    $ 2.43

 

65


Table of Contents

Summary of Operating Results

Financial results for each segment were as follows:

 

(In millions)

   Merchant
Generation
    Regulated
Operations
    Eliminations     Allegheny
Consolidated
 

2009

        

Operating revenues

   $ 1,608.6      $ 3,051.2      $ (1,233.0   $ 3,426.8   
                                

Operating expenses:

        

Fuel

     675.5        211.1        —          886.6   

Purchased power and transmission

     26.4        1,702.8        (1,227.2     502.0   

Deferred energy costs, net

     —          (64.4     —          (64.4

Operations and maintenance

     247.0        445.9        (5.8     687.1   

Depreciation and amortization

     106.8        177.1        (1.8     282.1   

Taxes other than income taxes

     47.2        166.4        —          213.6   
                                

Total operating expenses

     1,102.9        2,638.9        (1,234.8     2,507.0   

Operating income

     505.7        412.3        1.8        919.8   

Other income (expense), net

     1.0        17.1        (11.1     7.0   

Interest expense

     134.9        157.4        (1.2     291.1   
                                

Income before income taxes

     371.8        272.0        (8.1     635.7   

Income tax expense

     128.8        112.8        —          241.6   
                                

Net income

     243.0        159.2        (8.1     394.1   

Net income attributable to noncontrolling interests

     (9.0     (1.3     9.0        (1.3
                                

Net income attributable to Allegheny Energy, Inc.

   $ 234.0      $ 157.9      $ 0.9      $ 392.8   
                                

2008

                        

Operating revenues

   $ 1,792.9      $ 2,855.3      $ (1,262.3   $ 3,385.9   
                                

Operating expenses:

        

Fuel

     793.4        287.5        —          1,080.9   

Purchased power and transmission

     30.3        1,622.3        (1,257.0     395.6   

Deferred energy costs, net

     —          (63.7     —          (63.7

Operations and maintenance

     222.1        458.0        (5.3     674.8   

Depreciation and amortization

     94.1        181.9        (2.1     273.9   

Taxes other than income taxes

     47.6        167.3        —          214.9   
                                

Total operating expenses

     1,187.5        2,653.3        (1,264.4     2,576.4   

Operating income

     605.4        202.0        2.1        809.5   

Other income (expense), net

     7.8        28.6        (14.1     22.3   

Interest expense

     99.7        135.6        (3.4     231.9   
                                

Income before income taxes

     513.5        95.0        (8.6     599.9   

Income tax expense

     179.7        24.4        —          204.1   
                                

Net income

     333.8        70.6        (8.6     395.8   

Net income attributable to noncontrolling interests

     (9.5     (0.4     9.5        (0.4
                                

Net income attributable to Allegheny Energy, Inc.

   $ 324.3      $ 70.2      $ 0.9      $ 395.4   
                                

 

66


Table of Contents

(In millions)

   Merchant
Generation
    Regulated
Operations
    Eliminations     Allegheny
Consolidated
 

2007

        

Operating revenues

   $ 1,625.9      $ 2,855.3      $ (1,174.2   $ 3,307.0   
                                

Operating expenses:

        

Fuel

     661.7        269.1        —          930.8   

Purchased power and transmission

     33.5        1,527.8        (1,168.1     393.2   

Deferred energy costs, net

     —          (10.1     —          (10.1

Operations and maintenance

     243.9        449.2        (6.1     687.0   

Depreciation and amortization

     89.7        189.6        (2.3     277.0   

Taxes other than income taxes

     49.8        162.0        —          211.8   
                                

Total operating expenses

     1,078.6        2,587.6        (1,176.5     2,489.7   

Operating income

     547.3        267.7        2.3        817.3   

Other income (expense), net

     24.0        31.4        (18.6     36.8   

Interest expense

     86.9        107.7        (7.3     187.3   
                                

Income before income taxes

     484.4        191.4        (9.0     666.8   

Income tax expense

     177.3        73.5        —          250.8   
                                

Net income

     307.1        117.9        (9.0     416.0   

Net income attributable to noncontrolling interests

     (13.1     (0.7     10.0        (3.8
                                

Net income attributable to Allegheny Energy, Inc.

   $ 294.0      $ 117.2      $ 1.0      $ 412.2   
                                

 

67


Table of Contents

MERCHANT GENERATION SEGMENT

The following is a summary of certain statistical information relating to the Merchant Generation segment that is regularly reviewed by its management:

 

    2009     2008     2007     2009/2008
Change
    2008/2007
Change
 

Market prices:

         

Round-the-clock energy price ($/MWh, PJM Western Hub)

  $ 38.75      $ 69.81      $ 56.92      (44.5 )%    22.6

Round-the-clock energy price ($/MWh, PJM AD Hub)

  $ 32.98      $ 53.19      $ 45.18      (38.0 )%    17.7

Natural gas price—Henry Hub NYMEX ($/MMBtu)

  $ 3.92      $ 8.84      $ 6.94      (55.7 )%    27.4

Allegheny Operating statistics:

         

Realized energy price ($/MWh) (a)

  $ 36.06      $ 55.56      $ 47.92      (35.1 )%    15.9

Supercritical Coal Units:

         

kWhs generated (in millions) (b)

    22,375        29,380        28,727      (23.8 )%    2.3

Equivalent Availability Factor (EAF) (c)

    79.9     87.6     83.1   (7.7 )%    4.5

Net Capacity Factor (NCF) (d)

    57.8     75.6     74.2   (17.8 )%    1.4

Station O&M (in millions) (e):

         

Base and operations

  $ 82.6      $ 77.5      $ 77.0      6.6   0.6

Special maintenance

    55.5        27.3        57.8      103.3   (52.8 )% 
                           

Total Station O&M

  $ 138.1      $ 104.8      $ 134.8      31.8   (22.3 )% 
                           

All Generating Units:

         

kWhs generated (in millions) (b)

    26,004        34,464        34,912      (24.5 )%    (1.3 )% 

EAF (c)

    82.3     87.9     84.0   (5.6 )%    3.9

NCF (d)

    41.3     54.9     55.5   (13.6 )%    (0.6 )% 

Station O&M (in millions):

         

Base and operations

  $ 123.5      $ 116.4      $ 114.3      6.1   1.8

Special maintenance

    62.3        40.8        66.3      52.7   (38.5 )% 
                           

Total Station O&M

  $ 185.8      $ 157.2      $ 180.6      18.2   (13.0 )% 
                           

 

(a) Represents the weighted average actual price received at the generation facility for power sold into PJM by Allegheny’s Merchant Generation plants.
(b) Excludes kWhs consumed by pumping at the Bath County, Virginia hydroelectric station.
(c) EAF represents the average available generating capacity expressed as a percentage of total generating capacity. This measure is commonly less than 100% primarily due to planned and unplanned outages and derates.
(d) NCF is a measure of actual net electricity generated compared to the amount of electricity that could have been generated at maximum operating capacity. This measure is less than 100% due to periods during which generating capacity is not available as a result of planned and unplanned outages, as well as periods during which generating capacity is available but is not dispatched because of the availability in the market of lower cost generation in amounts sufficient to meet demand.
(e) Station O&M includes base, operations and special maintenance costs. Base and operations costs consist of normal recurring expenses related to the ongoing operation of the generation facilities. Special maintenance costs include costs associated with outage-related maintenance and projects that relate to the generation facilities.

 

68


Table of Contents

Forward prices at December 31, 2009 for certain commodities in Allegheny’s region were as follows:

 

     Forward Market Prices (a)
   2010    2011    2012

Round-the-clock energy price—PJM Western Hub ($/MWh)

   $ 48.02    $ 49.55    $ 50.39

Round-the-clock energy price—PJM AD Hub ($/MWh)

   $ 39.02    $ 41.44    $ 43.62

Natural gas price—Henry Hub NYMEX ($/MMBtu)

   $ 5.79    $ 6.33    $ 6.53

 

(a) Based on average prices for the calendar year.

The performance of Allegheny’s Merchant Generation segment is significantly impacted by changes in prices for power and for commodities that underlie the generation of electric power, such as coal and natural gas. Changes in such prices result from changes in supply and demand, fuel costs, market liquidity, weather, environmental regulation and other factors. Market prices for power and related commodities are volatile and difficult to predict. Decreased demand for power and lower prices for power significantly impacted Allegheny’s Merchant Generation segment during 2009. In lower power price environments, Allegheny generates less power because of the increased amount of time during which it is not economical to run its generating units. During 2009 Allegheny utilized the flexibility afforded in certain of its coal purchase contracts to cancel or defer coal deliveries.

To manage exposure to market price changes, Allegheny sells and purchases physical energy at the wholesale level and enters into financial contracts within established risk management objectives and policies. The impacts of weak demand and low commodity prices on operating performance during 2009 were partially mitigated by power sale hedges, including Allegheny’s PLR contracts and financial hedges. The following table shows the percentages of Allegheny’s estimated future power sales and coal purchases that were hedged as of December 31, 2009:

 

     Year Ending December 31,  
   2010     2011     2012  

Percentage of expected coal-fired generation sales hedged

   82   30   4

Percentage of expected coal purchases hedged

   97   66   60

Selected financial results for the Merchant Generation segment for the years ended December 31, 2009, 2008 and 2007 were as follows:

 

Merchant Generation

(In millions)

   2009    2008    2007

Operating revenues

   $ 1,608.6    $ 1,792.9    $ 1,625.9

Operating income

   $ 505.7    $ 605.4    $ 547.3

Income before income taxes

   $ 371.8    $ 513.5    $ 484.4

 

69


Table of Contents

Operating Revenues

Merchant Generation operating revenues were as follows:

 

(In millions)

   2009     2008     2007  

PJM energy revenue (all generation)

   $ 936.5      $ 1,913.1      $ 1,669.0   
                        

PJM capacity revenue

     356.2        195.2        56.6   
                        

Power hedge revenue, net:

      

Power sale revenue—affiliated contracts

     1,198.7        1,210.6        1,123.8   

Power sale revenue—nonaffiliated contracts

     73.6        77.9        64.6   

Power purchased from PJM to serve contracts

     (1,177.6     (1,626.7     (1,334.6

Realized gains (losses) on financial hedges

     118.8        (25.6     (3.5
                        

Power hedge revenue, net

     213.5        (363.8     (149.7

Other, including unrealized gains (losses) on hedge instruments

     102.4        48.4        50.0   
                        

Total operating revenues

   $ 1,608.6      $ 1,792.9      $ 1,625.9   
                        

PJM Energy Revenue

PJM Energy Revenue represents the sale of all power produced by our Merchant Generation fleet. PJM Revenue decreased $976.6 million in 2009 compared to 2008, resulting from significantly lower demand for electricity and lower natural gas and power prices. The segment’s generation output was approximately 24.5% lower in 2009 compared to 2008 and its supercritical plant capacity factor, representing the MWhs actually generated compared to the amount of electricity that could have been generated at maximum operating capacity, dropped to 57.8% in 2009 compared to 75.6% in the prior year.

PJM Energy Revenue was higher in 2008 compared to 2007, primarily due to an increase in the market price of power, partially offset by a decrease in MWhs generated.

PJM Capacity Revenue

PJM capacity revenue increased $161.0 million and $138.6 million in 2009 and 2008, respectively, resulting from increased capacity prices under the PJM RPM auction process.

Power Sale Revenue—Affiliated Contracts

The Merchant Generation segment (AE Supply) sold West Penn the power to meet most of its customers’ needs and sold Potomac Edison the power to meet a portion of its Maryland and most of its Virginia customers’ needs under power sales contracts.

Affiliated power sale revenue decreased $11.9 million in 2009 compared to 2008 primarily due to:

 

   

a $28.8 million decrease in Maryland due to the residential customers going to market on January 1, 2009 and AE Supply winning a portion of the load contracts and a $17.1 million decrease in Virginia due primarily to lower demand,

 

   

partially offset by a $34.1 million increase in revenues in Pennsylvania due primarily to higher generation rates charged to Pennsylvania customers, which are passed on to AE Supply under the terms of the power supply contract between West Penn and AE Supply.

Affiliated power sale revenue increased $86.8 million in 2008 compared to 2007 primarily due to:

 

   

a $62.7 million increase due to new power sales agreements between AE Supply and Potomac Edison at market-based rates to serve certain of Potomac Edison’s customers in Virginia, the first of which was effective July 1, 2007 and

 

70


Table of Contents
   

a $56.4 million increase, primarily due to higher generation rates charged to Pennsylvania customers, which are passed on to AE Supply under the terms of the power supply contract between West Penn and AE Supply,

 

   

partially offset by a $32.3 million decrease related to lower sales volumes for Potomac Edison’s customers in Maryland.

Power Purchased From PJM to Serve Contracts

Power purchased from PJM to serve the Merchant Generation segment’s power sale contracts decreased $449.1 million in 2009 compared to 2008 primarily due to a decrease in market prices as well as decreased customer load, partially offset by an increase in capacity costs.

Power purchased from PJM to serve the Merchant Generation segment’s power sale contracts increased $292.1 million in 2008 compared to 2007 due to an increase in the market price of power, partially offset by decreased customer load.

Realized Gains (Losses) on Financial Hedges

Realized gains (losses) on financial hedges increased by $144.4 million in 2009 compared to 2008 due to an increase in margin on the hedges due to a decrease in market prices.

Realized gains (losses) on financial hedges decreased by $22.1 million in 2008 compared to 2007 due to a decrease in margin on the hedges due to an increase in market prices.

Other Revenues

Other revenues increased $54.0 million for 2009 compared to 2008 primarily due to unrealized gains on FTRs.

Operating Expenses

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

 

(In millions)

   2009    2008    2007

Fuel

   $ 675.5    $ 793.4    $ 661.7

Fuel expense decreased $117.9 million in 2009 compared to 2008, primarily due to a $107.7 million decrease in coal expense, resulting from a 27.1% decrease in tons of coal consumed at Allegheny’s merchant coal-fired generation facilities, partially offset by a 14.7% increase in the average cost of coal per ton.

Fuel expense increased $131.7 million in 2008 compared to 2007, primarily due to a $131.8 million increase in coal expense resulting from a 19.5% increase in the average cost of coal per ton and a 4.6% increase in tons of coal consumed at Allegheny’s merchant coal-fired generation facilities.

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

 

(In millions)

   2009    2008    2007

Purchased power and transmission

   $ 26.4    $ 30.3    $ 33.5

Purchased power and transmission expense decreased $3.9 million in 2009 compared to 2008, primarily due to a $10.6 million gain on the effective settlement of power purchase agreements in connection with the purchase of certain hydroelectric generation facilities, partially offset by costs relating to a hedge strategy associated with a transportation agreement between AE Supply and Kern River Gas Transmission Company. See consolidated financial statement Note 14, “Purchase of Hydroelectric Generation Facilities,” for additional information.

 

71


Table of Contents

Purchased power and transmission expense decreased $3.2 million in 2008 compared to 2007, primarily due to sales of excess coal and natural gas purchased for generation in 2007.

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

 

(In millions)

   2009    2008    2007

Operations and maintenance

   $ 247.0    $ 222.1    $ 243.9

Operations and maintenance expenses increased $24.9 million in 2009 compared to 2008, primarily due to an increase in costs resulting from the timing of plant maintenance, partially offset by a $6.7 million credit to operations and maintenance expense relating to the purchase of certain hydroelectric generation facilities. See consolidated financial statement Note 14, “Purchase of Hydroelectric Generation Facilities,” for additional information.

Operations and maintenance expenses decreased $21.8 million in 2008 compared to 2007, primarily due to decreased costs resulting from the timing of plant maintenance.

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

 

(In millions)

   2009    2008    2007

Depreciation and amortization

   $ 106.8    $ 94.1    $ 89.7

Depreciation and amortization expenses increased $12.7 million in 2009 compared to 2008, primarily due to Scrubber equipment at the Hatfield’s Ferry generating facility, which was placed into service during 2009.

Depreciation and amortization expenses increased $4.4 million in 2008 compared to 2007, primarily due to increased depreciation resulting from net property, plant and equipment additions.

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

 

(In millions)

   2009    2008    2007

Taxes other than income taxes

   $ 47.2    $ 47.6    $ 49.8

Taxes other than income taxes decreased $2.2 million in 2008 compared to 2007, primarily due to a tax refund.

Other Income (Expense), net

Other income (expense), net was as follows:

 

(In millions)

   2009    2008    2007

Other income (expense), net

   $ 1.0    $ 7.8    $ 24.0

Other income (expense), net decreased $6.8 million in 2009 compared to 2008, primarily due to lower interest income resulting from decreased average investments at lower rates.

Other income (expense), net decreased $16.2 million in 2008 compared to 2007, primarily due to an $8.4 million gain relating to an exchange transaction involving real estate in La Paz, Arizona that was recorded during 2007, as well as lower interest income resulting from lower average investment balances at lower interest rates.

 

72


Table of Contents

Interest Expense

Interest expense was as follows:

 

(In millions)

   2009    2008