ALLEGHENY ENERGY, INC
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:
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The Merchant Generation segment includes Allegheny’s merchant power generation operations, including the operations of AE Supply and AGC.
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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:
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Monongahela’s regulated generation operations were moved from the Generation and Marketing segment to the Delivery and Services segment.
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The Generation and Marketing segment was renamed the Merchant Generation segment.
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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.”
The Merchant Generation Segment
The principal companies and operations in AE’s Merchant Generation segment include the following:
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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.
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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:
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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.
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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.”
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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.”
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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.
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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.”
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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.”
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:
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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
“Capital Expenditures,” “Regulatory Framework Affecting Allegheny,” “Risk Factors,” and consolidated financial statement Note 5, “Transmission Expansion.”
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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.”
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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
generating units are scrubbed and a significant amount of SO2 and mercury emissions have been eliminated. See “Risk Factors,” “Capital Expenditures” and “Environmental Matters.”
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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.”
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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
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.”
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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.”
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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.
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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.”
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.
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:
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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;
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financing plans;
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market demand and prices for energy, capacity, coal and natural gas;
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the cost and availability of raw materials, including coal, and Allegheny’s ability to enter into, modify and enforce long-term fuel purchase agreements;
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PLR and power supply contracts;
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results of litigation;
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results of operations;
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internal controls and procedures;
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capital expenditures;
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status and condition of plants and equipment;
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changes in technology and their effects on the competitiveness of Allegheny’s generation facilities;
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work stoppages by Allegheny’s unionized employees;
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capacity purchase commitments; and
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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:
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the results of regulatory proceedings, including proceedings related to rates;
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plant performance and unplanned outages;
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volatility and changes in the price and demand for energy and capacity and changes in the value of FTRs;
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volatility and changes in the price of coal, natural gas and other energy-related commodities, as well as transportation costs;
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Allegheny’s ability to enter into, modify and enforce long term fuel purchase agreements;
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the effectiveness of Allegheny’s risk management policies and procedures;
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the ability and willingness of counterparties to satisfy their financial and performance obligations;
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changes in the weather and other natural phenomena;
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changes in Allegheny’s requirements for, and the availability and price of, emission allowances;
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changes in industry capacity, development and other activities by Allegheny’s competitors;
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changes in market rules, including changes to PJM’s participant rules and tariffs, and defaults by other market participants;
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the loss of any significant customers or suppliers;
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changes in both customer usage and customer switching behavior and their resulting effects on existing and future load requirements;
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the impact of government-mandated energy consumption initiatives, as well as general trends in resource conservation;
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dependence on other electric transmission and gas transportation systems and their constraints on availability;
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the reliability of Allegheny’s own system and its ongoing compliance with NERC reliability standards;
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environmental regulations;
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changes in other laws and regulations applicable to Allegheny, its markets or its activities;
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changes in the underlying inputs and assumptions, including market conditions, used to estimate the fair values of commodity contracts;
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the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;
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entry into, any failure to consummate, or any delay in the consummation of, contemplated asset sales or other strategic transactions;
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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;
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complications or other factors that make it difficult or impossible to obtain necessary lender consents or regulatory authorizations on a timely basis;
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recent and any future disruptions in the financial markets and changes in access to capital markets;
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the availability of credit;
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actions of rating agencies;
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inflationary or deflationary trends and interest rate trends;
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general economic and business conditions, including the effects of the current recession; and
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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.”
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:
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:
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.”
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.
(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.
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
(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.
(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.
(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.
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:
(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.
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.
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.
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.”
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
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
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
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:
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a 12.7% return on equity for TrAIL and the Black Oak SVC;
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an 11.7% return on equity for all other TrAIL Company transmission projects for which an incentive rate of return is not requested;
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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
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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:
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a return on equity of 14.3%;
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a return on CWIP;
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recovery of prudently incurred start-up business and administrative costs incurred prior to the time the rates go into effect; and
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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.
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).
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-
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:
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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
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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
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
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
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
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
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
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
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:
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the $73 million rate increase approved on a temporary basis on May 15, 2008 will remain in effect through June 30, 2009;
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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;
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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
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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.
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.
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.
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:
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maintaining an accurate CO2 emissions data base;
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improving the efficiency of its existing coal-burning generation facilities;
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following developing technologies for clean-coal energy and for CO2 emission controls at coal-fired power plants, including carbon sequestration;
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participating in CO2 sequestration efforts (e.g. reforestation projects) both domestically and abroad;
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analyzing options for future energy investment (e.g. renewables, clean-coal, etc.); and
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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.
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
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.
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.
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.
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.
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
Chairman, President, Chief Executive Officer and Director
Curtis H. Davis
Chief Operating Officer, Generation
Rodney L. Dickens
Vice President
Edward Dudzinski
Vice President
David M. Feinberg
Vice President, General Counsel and Secretary
Eric S. Gleason
Vice President, Corporate Development and Quality
Kirk R. Oliver
Senior Vice President and Chief Financial Officer
William F. Wahl, III
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.
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.
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
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
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.”
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.
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.
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.
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
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:
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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;
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fuel costs, the cost of emissions allowances and other production costs;
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transmission constraints;
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changes in PJM rules and other changes in the regulatory framework for wholesale power markets; and
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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.
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
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.
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:
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a recession, including the current recession, or other economic slowdown;
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the bankruptcy of one or more energy companies or highly-leveraged companies;
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significant increases in the prices for oil or other fuel;
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a terrorist attack or threatened attacks;
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a significant transmission failure; or
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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;
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limit Allegheny’s flexibility in planning for, or reacting to, changes in its business, regulatory environment and the industry in which it operates;
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place Allegheny at a competitive disadvantage compared to its competitors that have less leverage;
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limit Allegheny’s ability to borrow additional funds; and
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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:
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borrow funds;
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incur liens and guarantee debt;
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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);
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make investments;
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dispose of assets; and
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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.
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
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
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.
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:
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.”
ITEM 6. SELECTED FINANCIAL DATA
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
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.
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“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:
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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.
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:
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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.
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Monongahela operates an electric T&D business and also owns and operates electric generation facilities in northern West Virginia.
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Potomac Edison operates an electric T&D business in portions of West Virginia, Maryland and Virginia.
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West Penn operates an electric T&D business in southwestern, south-central and northern Pennsylvania.
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TrAIL Company was formed in 2006 to develop, construct and operate transmission expansion projects, including the TrAIL Project.
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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.
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:
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achieved the best safety performance in recent years in its delivery business and continued to improve safety performance in its generation business;
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completed its scrubber construction projects at Fort Martin and Hatfield’s Ferry on time and under budget;
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succeeded in controlling operation and maintenance costs;
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refinanced $843 million of indebtedness, obtained additional liquidity, extended debt maturities and securitized the remaining Fort Martin scrubber costs;
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moved forward with the construction of its TrAIL transmission expansion project, which remains on schedule for a June 2011 in-service date;
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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;
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launched several energy efficiency and conservation programs in Maryland and Pennsylvania; and
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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:
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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;
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continuing progress on transmission expansion projects;
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resolving its West Virginia base rate case successfully;
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developing and implementing energy efficiency and conservation programs;
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managing the transition to market-based rates in Pennsylvania;
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maintaining a culture that emphasizes the importance of safety throughout its organization; and
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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.
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:
Summary of Operating Results
Financial results for each segment were as follows:
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:
(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.
Forward prices at December 31, 2009 for certain commodities in Allegheny’s region were as follows:
(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:
Selected financial results for the Merchant Generation segment for the years ended December 31, 2009, 2008 and 2007 were as follows:
Operating Revenues
Merchant Generation operating revenues were as follows:
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:
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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,
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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:
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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
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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,
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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:
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:
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.
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:
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:
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:
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:
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.
Interest Expense
Interest expense was as follows:
Interest expense increased $35.2 million in 2009 compared to 2008, primarily due to costs associated with AE Supply’s September 2009 and October 2009 purchases of outstanding medium-term notes.
Interest expense increased $12.8 million in 2008 compared to 2007, primarily due to the reversal of $54.7 million of accrued interest resulting from the settlement of Allegheny’s litigation with Merrill Lynch, which was recorded during 2007, partially offset by lower average debt outstanding at lower interest rates and increased capitalized interest resulting from capital projects that were partially funded using cash from operations. See consolidated financial statement Note 24, “Acquisition of Noncontrolling Interest in AE Supply,” for additional information regarding the settlement with Merrill Lynch.
See consolidated financial statement Note 8, “Capitalization and Debt,” for additional information.
Income Tax Expense
The effective tax rate for the twelve months ended December 31, 2009 was 34.6%. Income tax expense for the twelve months ended December 31, 2009 was lower than income tax expense calculated at the federal statutory tax rate of 35%, primarily due to an adjustment to the Pennsylvania net operating loss carryforward deferred tax asset resulting from a Pennsylvania tax law change, which decreased the rate by 3.0% and the ratemaking effects of depreciation differences and investment tax credits, which reduced the rate by 0.2%. This decrease was partially offset by state taxes, which increased the rate by 2.8%.
The effective tax rate for the twelve months ended December 31, 2008 was 35.0%. Changes in tax reserves related to uncertain tax positions and audit settlements increased the effective rate by 0.9%. This increase was offset by state income taxes, permanent items, and the rate-making effects of depreciation differences and the investment tax credit, which decreased the rate by 0.9%.
The effective tax rate for the twelve months ended December 31, 2007 was 36.6%. Income tax expense for the twelve months ended December 31, 2007 was higher than income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state taxes, which increased the rate by 1.0% and increases in tax reserves related to uncertain tax positions and audit settlements, which increased the rate by 0.6%.
REGULATED OPERATIONS SEGMENT
Selected financial results for the Regulated Operations segment for the years ended December 31, 2009, 2008 and 2007 were as follows:
The performance of Allegheny’s Regulated Operations segment is significantly impacted by customer demand for electricity, regulatory ratemaking actions and the progress of transmission expansion projects. Retail electricity sales were as follows:
The decreases in retail electricity sales shown in the table above are due largely to significant decreases in industrial demand relating to the weak economic climate and, to a lesser degree, decreases in residential demand. These trends continued through December 31, 2009, and future retail electricity sales will continue to be affected by economic conditions, load fluctuations, conservation measures and weather.
In addition to retail electricity sales, management monitors the performance of the Regulated Operations segment based in part on certain statistical information including the following:
(a) This measure is calculated by dividing total revenues from retail sales of electricity by retail electricity sales.
(b) This measure is calculated by dividing total O&M, excluding O&M related to transmission expansion, which is recovered in formula rates, by retail electricity sales.
(c) Heating degree-days (“HDD”) and cooling degree-days (“CDD”). The operations of the Distribution Companies are weather sensitive. Weather conditions directly influence the volume of electricity delivered by the Distribution Companies, representing one of several factors that impact the volume of electricity delivered. Accordingly, deviations in weather from normal levels can affect Allegheny’s financial performance. Degree-day data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit, and CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65° Fahrenheit is counted as one heating degree-day. HDD and CDD are most likely to impact the usage of Allegheny’s residential and commercial customers. Industrial customers are less weather sensitive.
(d) Represents kWhs generated by Monongahela’s regulated generation facilities.
During 2008, Potomac Edison’s Virginia distribution operations reported significant losses due to increased costs of purchased power that could not be passed on to its customers. As a result of ratemaking decisions, Potomac Edison began to recover the majority of its actual purchased power costs in Virginia beginning January 1, 2009, and this resulted in increased pre-tax earnings of $98.3 million in 2009 compared to the prior year.
Capital expenditures on Allegheny’s PATH, TrAIL and other expansion transmission projects are continuing. Accumulated expenditures for these projects were $828.9 million at December 31, 2009 and $244.8 million at December 31, 2008. As discussed in consolidated financial statement Note 5, “Transmission Expansion,” increased capital spending on these projects directly impacts earnings. Income before income tax relating to transmission expansion increased $35.9 million in 2009 compared to the prior year, and net income, excluding the amount of income attributable to our joint venture partner’s noncontrolling interest in PATH, increased $20.7 million in 2009 compared to the prior year.
Operating Revenues
Regulated Operation revenues were as follows:
Total operating revenues increased $195.9 million in 2009 compared to 2008, primarily due to a $358.3 million increase in retail electric revenues, partially offset by a $171.0 million decrease in transmission services and bulk power revenues.
Retail Electric
Retail electric revenues increased $358.3 million in 2009 compared to 2008, primarily due to:
•
a $173.1 million increase in Pennsylvania operating revenues resulting from higher generation rates charged to Pennsylvania customers,
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a $149.4 million increase primarily due to an ENEC-related rate increase in West Virginia that went into effect on January 1, 2009,
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a $118.4 million increase in Maryland generation revenues primarily resulting from market-based generation pricing for residential customers effective January 1, 2009 and
•
a $98.3 million increase due to higher rates under ratemaking settlements in Virginia.
These increases were partially offset by:
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a $102.0 million decrease in retail revenue related to reduced customer demand and
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a $38.5 million decrease due to the expiration of an earnings benefit related to stranded cost recovery in Pennsylvania.
Transmission Services and Bulk Power
Transmission services and bulk power revenues decreased $171.0 million in 2009 compared to 2008, primarily due to:
•
a $164.6 million decrease in PJM revenue, net, and
•
a $33.3 million decrease in revenues from Warrior Run generation primarily resulting from the timing of maintenance outages at the facility,
•
partially offset by a $26.9 million increase in transmission and other revenues as a result of increased recoverable expenses and returns on investment that are related to transmission expansion.
Monongahela sells the power that it generates from its West Virginia jurisdictional assets into the PJM market and purchases from the PJM market the power necessary to meet its West Virginia jurisdictional customer load and its contractual obligations, which include supplying power to serve Potomac Edison’s West Virginia load. PJM revenue, net, represents the revenues from PJM sales less the costs of PJM purchases relating to West Virginia assets and load.
Revenues from generation sold into PJM were lower, primarily due to significantly lower demand and a decrease in the market price of power. Power purchased from PJM decreased due to a decrease in the market price of power and decreased customer demand.
PJM revenue, net decreased $28.8 million in 2008 compared to 2007, primarily due to an increase in power purchased from PJM at higher prices to serve Monongahela’s power supply agreements.
Revenues from Warrior Run generation increased $33.3 million in 2008 compared to 2007, primarily resulting from the timing of maintenance outages at the facility.
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:
Fuel expense decreased $76.4 million in 2009 compared to 2008, primarily due to a $65.3 million decrease in coal expense and an $8.5 million decrease in emission allowance expense. The decrease in coal expense was due to a 39.1% decrease in tons of coal consumed at Allegheny’s regulated coal-fired generation facilities, partially offset by a 22.2% increase in the average cost of coal per ton.
Fuel expense increased $18.4 million in 2008 compared to 2007, primarily due to a $22.2 million increase in coal expense, partially offset by a $6.4 million decrease in emission allowance expense. The increase in coal expense was due to an 18.6% increase in the cost of coal per ton, partially offset by a 7.6% decrease in tons of coal consumed at Allegheny’s regulated coal-fired generation facilities.
Purchased Power and Transmission: Purchased power and transmission expense represents power purchased from AE Supply and third-party suppliers, including purchases from qualifying facilities under PURPA. Purchased power and transmission expense was as follows:
Purchased power and transmission expense increased $80.5 million in 2009 compared to 2008, primarily due to:
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a $97.7 million increase, primarily due to higher rates paid under the terms of market-based power purchase contracts to supply Maryland residential customers effective January 1, 2009, partially offset a reduction in power purchased resulting from reduced customer demand and
•
an $84.1 million increase due to higher generation rates paid under the terms of a power supply agreement between West Penn and AE Supply, partially offset by a reduction in power purchased resulting from reduced customer demand.
These increases were partially offset by:
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a $50.0 million decrease related to the expiration of an intercompany market rate adjustment in Pennsylvania,
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a $15.2 million decrease in purchased power from PURPA facilities, primarily resulting from the timing of maintenance outages at the Warrior Run PURPA generation facility and
•
a $15.0 million decrease primarily due to lower rates paid under the terms of market-based power purchase contracts to supply Virginia residential customers.
Purchased power and transmission expense increased $94.5 million in 2008 compared to 2007, primarily due to:
•
a $65.8 million increase due to higher generation rates charged to Pennsylvania customers, which are contractually passed on to AE Supply under the terms of a power supply agreement between West Penn and AE Supply and
•
a $62.7 million increase due to a new power sales agreement in Virginia between AE Supply and Potomac Edison at market-based rates (see consolidated financial statement Note 4, “Rates and Regulation,” for additional information),
•
partially offset by a $21.7 million decrease due to the expiration in May 2007 of a fixed price supply agreement to serve Monongahela’s former Ohio service territory.
Deferred Energy Costs, net: Deferred energy costs, net represent an adjustment of actual costs incurred during the period for amounts that are expected to be charged or credited to customers in rates in a future period under a regulatory mechanism. The components of deferred energy costs were as follows:
AES Warrior Run PURPA Generation. To satisfy certain of its obligations under PURPA, Potomac Edison entered into a long-term contract beginning July 1, 2000 to purchase capacity and energy from the AES Warrior Run PURPA generation facility through the beginning of 2030. Potomac Edison is authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run PURPA generation facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, by means of a retail revenue surcharge. Any under-recovery or over-recovery of net costs is being deferred pending subsequent recovery from, or return to, customers through adjustments to this surcharge.
ENEC Costs. Under the annual ENEC method of recovering net power supply costs in West Virginia, including fuel costs, purchased power costs and other related expenses, net of related revenue and interest earnings on the Fort Martin Scrubber project escrow fund, Monongahela and Potomac Edison track actual costs and revenues for under and/or over recoveries, and file requests for revised ENEC rates on an annual basis. Any under and/or over recovery of costs, net of related revenues, is deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability with the corresponding impact on the Consolidated Statements of Income reflected in “Deferred energy costs, net.”
Market-based Generation and Other Costs. Potomac Edison is authorized by the Maryland PSC to recover the costs of the generation component of power sold to certain residential, commercial and industrial customers that did not choose a third-party alternative generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet for any under-recovery or over-recovery of the generation component of costs charged to these customers. In addition, under an order of the Virginia SCC, Potomac Edison was granted a rate adjustment to recover a portion of its increased purchased power costs. The order directed Potomac Edison to defer any under-or over-recovery of purchased power costs approved.
Operations and Maintenance: Operations and maintenance expenses primarily include salaries and wages, employee benefits, materials and supplies, contract work, outside services and other expenses. Operations and maintenance expenses were as follows:
Operations and maintenance expenses decreased $12.1 million in 2009 compared to 2008, primarily due to decreased costs associated with the timing of plant maintenance.
Operations and maintenance expenses increased $8.8 million in 2008 compared to 2007, primarily due to an $8.8 million increase in right-of-way vegetation expense resulting from increased maintenance activities and storm activity and a $5.1 million increase in compensation and benefits expense, partially offset by decreased costs resulting from the timing of plant maintenance.
Depreciation and Amortization: Depreciation and amortization expenses were as follows:
Depreciation and amortization expenses decreased $4.8 million in 2009 compared to 2008, primarily due to an $8.2 million decrease in amortization related to regulatory assets, partially offset by a $3.5 million increase in depreciation expense resulting from the Fort Martin Scrubbers, which were placed into service during the fourth quarter of 2009.
Depreciation and amortization expenses decreased $7.7 million in 2008 compared to 2007, primarily due to a 2007 rate order by the West Virginia PSC that extended the depreciable lives of regulated generating assets effective May 2007.
Taxes Other Than Income Taxes: Taxes other than income taxes primarily includes business and occupation taxes, payroll taxes, gross receipts taxes and property taxes. Taxes other than income taxes were as follows:
Taxes other than income taxes increased $5.3 million in 2008 compared to 2007, primarily due to an increase in gross receipts tax, resulting from an increase in Pennsylvania taxable regulated utility revenues and an increased Pennsylvania tax rate.
Other Income (Expense), net
Other income (expense), net was as follows:
Other income (expense), net decreased $11.5 million in 2009 compared to 2008, primarily due to decreased interest income on investments resulting from lower investment balances and interest rates.
Other income (expense), net decreased $2.8 million in 2008 compared to 2007, primarily due to decreased interest income on investments resulting from lower investment balances and interest rates.
Interest Expense
Interest expense was as follows:
Interest expense increased $21.8 million in 2009 compared to 2008, primarily due to Monongahela’s December 2008 issuance of $300 million of first mortgage bonds and borrowings under TrAIL Company’s credit facility. See consolidated financial statement Note 8, “Capitalization and Debt,” for additional information.
Interest expense increased $27.9 million in 2008 compared to 2007, primarily due to the December 2007 issuance of $275 million of first mortgage bonds by West Penn, the April 2007 issuance of environmental control bonds by Potomac Edison and the December 2008 issuance of $300 million of first mortgage bonds by Monongahela. See consolidated financial statement Note 8, “Capitalization and Debt,” for additional information.
Income Tax Expense
The effective tax rate for the twelve months ended December 31, 2009 was 41.5%. Income tax expense for the twelve months ended December 31, 2009 was higher than income tax expense calculated at the federal statutory tax rate of 35% primarily due to state taxes, which increased the rate by 5.0%, the segment’s share of consolidated income tax expense, which increased the rate by 2.5%, and changes in tax reserves related to uncertain tax positions and audit settlements, which increased the rate by 0.9%. These increases were partially offset by permanent differences and the ratemaking effects of investment tax credits and depreciation differences, which decreased the rate by 1.9%.
The effective tax rate for the twelve months ended December 31, 2008 was 25.7%. Income tax expense for the twelve months ended December 31, 2008 was lower than income tax expense calculated at the federal statutory tax rate of 35%, primarily due to adjustments to reserves for uncertain tax positions that decreased the rate by 9.4%, permanent differences, which decreased the rate by 7.9% and the segment’s share of consolidated tax savings, which decreased the rate by 2.0%. These deductions were partially offset by state taxes, which increased the rate by 5.8%, and the ratemaking effects of investment tax credits and depreciation differences, which increased the rate by 4.2%.
The effective tax rate for the twelve months ended December 31, 2007 was 38.5%. Income tax expense for the twelve months ended December 31, 2007 was higher than income tax expense calculated at the federal statutory tax rate of 35%, primarily due to state taxes, which increased the rate by 3.1%, the ratemaking effects of depreciation differences, which increased the rate by 2.2%, and changes in tax reserves related to uncertain tax
positions and audit settlements, which increased the rate by 1.8%. These increases were partially offset by permanent differences, which decreased the rate by 1.4%, the ratemaking effects of investment tax credits, which decreased the rate by 1.0% and the segment’s share of consolidated tax savings, which decreased the rate 1.2%.
Transmission Expansion
The Regulated Operations segment includes operations relating to transmission expansion projects, which includes TrAIL Company and PATH, LLC. The results of operations and selected balance sheet information related to transmission expansion were as follows:
TrAIL Company and PATH, LLC are subject to regulation of rates by FERC for amounts billed through PJM. FERC has approved the use of a formula rate methodology for recovery of all prudently incurred operations and maintenance expenses, a return on debt and equity on all capital expenditures in connection with TrAIL and PATH based on a hypothetical 50% debt, 50% equity capital structure, until the transmission facilities are placed into service as well as an income tax allowance. The actual capital structure will be reflected in the formula rate once the transmission facilities are placed into service. TrAIL Company and PATH, LLC recognize revenue based on allowable costs incurred and return earned. Therefore, revenues and operating income are expected to increase as the projects move forward from the planning and approval stages through development and construction. See consolidated financial statement Note 5, “Transmission Expansion” and consolidated financial statement Note 4, “Rates and Regulation” for more information regarding TrAIL and PATH.
FINANCIAL CONDITION-LIQUIDITY AND CAPITAL RESOURCES
To meet cash needs for operating expenses, the payment of interest, pension contributions, retirement of debt and construction programs, Allegheny has historically used internally generated funds (net cash provided by operations less common dividends) and external financings, including the sale of common and preferred stock, debt instruments and lease arrangements.
Allegheny manages excess cash through its internal money pool. The money pool provides funds to certain AE subsidiaries at the lower of the Federal Reserve’s previous day federal funds effective interest rate, or the Federal Reserve’s previous day seven day commercial paper rate, less four basis points. The minimum interest rate charged to approved AE subsidiaries is zero percent. AE and AE Supply can only place money into the money pool. West Penn and Potomac Edison can either place money into, or borrow money from, the money pool. AGC can only borrow money from the money pool. Since December 2009, Monongahela may only invest money into the money pool and amounts invested by Monongahela may not be borrowed by any AE subsidiary.
At December 31, 2009 and 2008, Allegheny had cash and cash equivalents of $286.6 million and $362.1 million, respectively, and current restricted funds of $25.9 million and $36.8 million, respectively. Current restricted funds at December 31, 2009 included $20.6 million of funds collected from West Virginia customers that will be used to service the ratepayer obligation bonds issued in connection with the construction of the Scrubbers at Fort Martin and $5.3 million of intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. Current restricted funds at December 31, 2008 included $21.9 million of funds collected from West Virginia customers that will be used to service the ratepayer obligation bonds issued in connection with the construction of Scrubbers at Fort Martin and $14.9 million of intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. In addition, at December 31, 2009 and 2008, Allegheny had long-term restricted funds of $60.2 million and $133.3 million, respectively. Long-term restricted funds at December 31, 2009 included $10.3 million of funds remaining from the $235 million Pennsylvania Development Financing Authority bond issued in connection with the construction and installation of Scrubbers at Hatfield’s Ferry generation facility, $49.6 million of funds relating to proceeds from the issuance of ratepayer obligation bonds in connection with the construction of the Scrubbers at Fort Martin and $0.3 of escrow funds related to the Scrubber construction projects. Long-term restricted funds at December 31, 2008 consisted of funds relating to proceeds from the issuance of ratepayer obligation bonds in connection with the construction of the Scrubbers at Fort Martin.
See consolidated financial statement Note 8, “Capitalization and Debt,” for a listing of Allegheny’s debt by maturity date. In addition, AE, AE Supply and Monongahela each have in place revolving credit facilities. AE’s credit facility matures in 2011 and AE Supply’s and Monongahela’s credit facilities mature in 2012. At December 31, 2009, borrowing capacity under these credit facilities was as follows:
In addition, at December 31, 2009, TrAIL Company had borrowings under its $550 senior unsecured credit facility in the amount of $455 million. All amounts outstanding under the senior unsecured credit facility were repaid during January 2010 with proceeds from TrAIL Company’s January 25, 2010 issuance of unsecured notes and new senior unsecured revolving credit facility. See Note 8, “Capitalization and Debt” for additional information.
Allegheny posts collateral with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. Approximately $20.8 million and $33.4 million of cash collateral deposits were included in current assets at December 31, 2009 and 2008, respectively. Approximately $3.1 million and $0.2 million of cash collateral deposits were netted against derivative liabilities on the Consolidated Balance Sheet at December 31, 2009 and 2008, respectively. If Allegheny’s credit ratings were to decline, it may be required to deposit additional cash or cash-equivalent collateral with its hedging counterparties. See consolidated financial statement Note 13, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for additional information regarding potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2009. A downgrade of AE, AE Supply and the Distribution Companies at December 31, 2009 below Standard & Poor’s BB- or Moody’s Ba3, would have required Allegheny to post an additional $80 million of collateral to counterparties, including PJM, for both derivative and non-derivative contracts.
Allegheny’s consolidated capital structure, excluding noncontrolling interest, as of December 31, 2009 and 2008, was as follows:
January 2010 Debt Activity
On January 25, 2010, TrAIL Company issued $450 million aggregate principal amount of 4.0% senior unsecured notes due in 2015 and also entered into a new $350 million senior unsecured revolving credit facility with a three-year maturity. Borrowings under the new facility will bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on TrAIL Company’s senior unsecured credit rating. 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.
During January 2010, Monongahela repaid its $110 million 7.36% medium-term notes.
2009 Debt Activity
Borrowings and principal repayments on debt during 2009 were as follows:
(a) Represents debt activity under AE Supply’s previous credit facility, which was replaced with a new credit facility during September 2009.
On July 6, 2009, the Pennsylvania Economic Development Financing Authority issued $235 million of 7.0% tax-exempt bonds that mature in 2039 and loaned the proceeds from that issuance to AE Supply to finance a portion of the cost of constructing and installing Scrubbers at its Hatfield’s Ferry generation facility. AE Supply capitalized $2.4 million in debt issuance costs associated with this transaction.
On September 4, 2009, AE Supply repurchased $97.5 million and $146.8 million, respectively, of its 7.80% notes due 2011 and its 8.25% notes due 2012 pursuant to a cash tender offer, at an aggregate premium of $18.1 million. AE Supply expensed the $18.1 million premium, $0.7 million in unamortized debt costs, and $0.6 million in fees associated with the tender offer during the three months ended September 30, 2009.
On September 24, 2009, AE Supply entered into a new $1 billion senior unsecured revolving credit facility with a three-year maturity. The new revolving credit facility replaced AE Supply’s previous $400 million revolving credit facility, which was scheduled to mature in May 2011. Loans under the new facility bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on AE Supply’s senior unsecured credit rating. AE Supply capitalized $22.3 million in debt costs related to this facility.
On October 1, 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. AE Supply used a portion of the net proceeds from the sale of these notes to repay in full its existing $447 million term loan on October 2, 2009. AE Supply capitalized $5.3 million in debt issuance costs associated with this new debt issuance and expensed $0.6 million of unamortized debt costs associated with the extinguished term loan.
On October 21, 2009, AE Supply used the remaining proceeds of its senior unsecured note offering to repurchase approximately $152 million aggregate principal amount of its 7.80% Medium Term Notes due 2011 pursuant to a cash tender offer at an aggregate premium of $12.7 million. AE Supply expensed the $12.7 million premium, $0.3 million in unamortized debt costs, and $0.4 million in fees related to this tender offer.
On December 18, 2009, Monongahela entered into a new $110 million senior unsecured revolving credit facility with a three-year maturity. Loans under the new facility generally bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on Monongahela’s senior unsecured credit rating. Monongahela capitalized approximately $1.4 million in debt costs related to this facility.
On December 23, 2009, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $64.4 million and $21.5 million, respectively, of Senior Secured Ratepayer Obligation Charge Environmental Control Bonds, Series B. These bonds securitize the right to collect an environmental control surcharge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. The bonds were issued with an interest rate of 5.1% and mature in January 2031. Net proceeds from the sale of the bonds are restricted funds and are being used to fund certain costs incurred in connection with the construction and installation of the Scrubbers at Fort Martin. Monongahela and Potomac Edison capitalized $1.9 million and $0.7 million, respectively, in debt issuance costs associated with this transaction.
Debt Activity
Issuances of indebtedness and repayments of principal on indebtedness, during 2008 were as follows:
(a) The issuance amounts represent interest that was accrued and added to the principal amount of certain bonds.
(b) Represents debt activity under AE Supply’s previous credit facility, which was replaced with a new credit facility during September 2009.
On August 15, 2008, TrAIL Company entered into a $550 million senior secured credit facility with a seven-year maturity. The facility included a $530 million construction loan and a $20 million revolving facility, both with an initial borrowing rate equal to the London Interbank Offered Rate plus 1.875 percent. Borrowings under this facility were repaid in January 2010.
On December 15, 2008, Monongahela issued $300 million aggregate principal amount of 7.95% First Mortgage Bonds that mature in 2013. Proceeds from the First Mortgage Bonds were used to repay short-term intercompany debt, to finance certain capital expenditures, including a portion of the costs to install Scrubbers at Fort Martin, and for working capital needs and other general corporate purposes.
Dividends
During 2009 and 2008 AE paid the following dividends on its common stock:
Future dividends will be declared at the discretion of the Board of Directors and will depend upon available earnings, cash flows and other relevant factors. As described in consolidated financial statement Note 15, “Dividend Restrictions”, AE’s Revolving Credit Facility places a limit on quarterly cash dividends based on net income in the four preceding quarters. Additionally, under the terms of its proposed merger with FirstEnergy, AE is prohibited from increasing its quarterly cash dividend.
Construction and Capital Requirements
Allegheny estimates that its cash-based capital expenditures will approximate $1,081 million in 2010 and $696 million in 2011, including amounts relating to transmission expansion projects. See “Business-Capital Expenditures” for additional capital expenditure detail. Additional information regarding the TrAIL and PATH transmission expansion projects follows.
TrAIL. Cost estimates for Allegheny’s portion of TrAIL are approximately $850 million, excluding expenditures for other related transmission projects. Allegheny estimates that its capital expenditures for TrAIL will be approximately $250 million and $50 million for 2010 and 2011, respectively. As discussed above in “Subsequent Event-Debt”, in January 2010, TrAIL Company issued $450 million aggregate principal amount of senior unsecured notes and also entered into a new $350 million senior unsecured revolving credit facility.
PATH. PJM is in the process of preparing its comprehensive 2010 Regional Transmission Expansion Plan, which will identify an in-service date for PATH. Allegheny’s share of total project costs for PATH is expected to be approximately $1.2 billion, and AEP’s share of total project costs for PATH is expected to be approximately $0.6 billion. Allegheny anticipates funding its capital expenditures related to PATH with future external debt financings and cash from operations.
Other Matters Concerning Liquidity and Capital Requirements
Allegheny makes cash contributions to its qualified pension plan to meet the minimum funding requirements of employee benefit and tax laws and may include additional discretionary contributions to increase the funded level of the plan. Allegheny has not yet determined the amount of future contributions, but may contribute up to $80 million to its pension plan for the year 2010. The amount of future contributions to the plan will depend on the funded status of the plan, asset performance and other factors. Allegheny currently anticipates that it will contribute $12 million to $14 million during 2010 to fund postretirement benefits other than pensions.
Allegheny has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel and transportation agreements and other contracts. The table below summarizes estimated contractual obligations by period as of December 31, 2009, excluding expected contributions for pension and postretirement benefits other than pensions, contingent liabilities and certain contractual commitments that are accounted for under fair value accounting.
(a) Does not include unamortized debt expense, discounts, premiums and payments made and debt issued subsequent to December 31, 2009.
(b) Amounts were based on interest rates as of December 31, 2009 and do not reflect any debt or interest rate changes subsequent to December 31, 2009.
(c) Amounts were calculated based on expected PURPA purchased power prices at December 31, 2009 without giving effect to possible price changes that could occur as a result of any future CO2 emissions regulation or legislation.
(d) Amounts represent Allegheny’s expected cash payments for certain information technology services under a contract that expires on December 31, 2012.
Off-Balance Sheet Arrangements
Allegheny has no off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on its financial position, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.
Cash Flows
Operating Activities
Allegheny’s cash flows from operating activities result primarily from the generation, sale and delivery of electricity. Future cash flows will be affected by the economy, weather, customer choice, future regulatory proceedings and future demand and market prices for power, as well as Allegheny’s ability to produce and supply its customers with power at competitive prices. Cash flows from operating activities were as follows:
The non-cash items included in income in 2009 primarily consisted of depreciation and amortization of $282.1 million and deferred income taxes and investment tax credit, net of $235.3 million, partially offset by deferred energy costs, net of $64.4 million.
The non-cash items included in income in 2008 primarily consisted of depreciation and amortization of $273.9 million and deferred income taxes of $156.2 million. Changes in certain assets and liabilities primarily consisted, in part, of a change in regulatory liabilities of $60.4 million, primarily relating to Allegheny receiving
payments from its customers in advance of providing service, in order to mitigate the impact of the transition to market-based generation rates, the advanced payments are being credited to the customers. Changes in certain assets and liabilities also included a change in regulatory assets of $51.3 million, primarily resulting from the recovery of previously deferred and earned revenue related to West Penn restructuring; a change in accrued taxes of $43.1 million, primarily as a result of timing differences associated with the payment of certain tax obligations; and a reduction in collateral deposits of $23.1 million, primarily due to reduced collateral requirements with various counterparties to Allegheny’s power contracts. These amounts were partially offset by $62.9 million in changes in receivables and payables resulting from normal working capital activity and an increase in materials, supplies and fuel of $62.8 million, primarily as a result of increased fuel inventory levels and higher prices.
The non-cash items included in income in 2007 primarily consisted of depreciation and amortization of $277.0 million and deferred income taxes of $260.7 million. Changes in certain assets and liabilities primarily consisted of $30.2 million in changes in receivables and payables resulting from normal working capital activity.
Investing Activities
Cash flows from investing activities were as follows:
Cash flows used in investing activities in 2009 were $1,084.8 million and primarily consisted of $1,166.2 million of capital expenditures partially offset by an $84.1 million decrease in restricted funds, primarily due to the use of restricted funds associated with the Fort Martin Scrubber project.
Cash flows used in investing activities in 2008 were $822.3 million and primarily consisted of $994.1 million of capital expenditures and $50.0 million relating to the acquisition of Merrill Lynch’s noncontrolling interest in AE Supply, partially offset by a $224.4 million decrease in restricted funds, primarily due to the use of restricted funds associated with the Fort Martin Scrubber project.
Cash flows used in investing activities in 2007 were $1,231.4 million and primarily consisted of $848.4 million of capital expenditures and a $381.5 million increase in restricted funds primarily as a result of the receipt and investment of the proceeds from environmental control bonds issued to finance the construction of Scrubbers at Fort Martin.
Financing Activities
Cash flows from financing activities were as follows:
Cash flows provided by financing activities in 2009 were $209.7 million and primarily included $1,508.3 million (net of $14.8 million related to debt issuance costs other than the costs associated with the AE Supply revolving credit facility refinancing of $22.2 million) in proceeds from the issuance of long-term debt, including borrowings of $605.0 million under AE’s and AE Supply’s revolving credit facilities and TrAIL Company’s senior secured credit facility as well as the issuance by AE subsidiaries of $920.8 million in the aggregate of medium term notes, sinking fund bonds and revenue bonds. These amounts were partially offset by $1,177.2 million in various debt repayments and $101.7 million of cash dividends paid on common stock.
Cash flows provided by financing activities in 2008 were $64.2 million and primarily included $647.6 million (net of $12.3 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, including borrowings of $360.0 million under AE Supply’s revolving credit facility and TrAIL Company’s senior secured credit facility as well as the issuance of $300.0 million of 7.95% First Mortgage Bonds, partially offset by $493.1 million in various debt repayments and $101.1 million of cash dividends paid on common stock.
Cash flows provided by financing activities in 2007 were $421.0 million and primarily included $936.9 million (net of $12.9 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt, consisting of the issuance of $459.3 million of environmental control bonds, $215.5 million of tax-exempt pollution control refunding bonds and $275.0 million of 5.95% First Mortgage Bonds. Partially offsetting these amounts were $502.2 million in various debt repayments.
AE Common Stock
AE issued 0.2 million and 2.1 million shares of common stock in 2009 and 2008, respectively, primarily in connection with stock option exercises and the settlement of stock units. There were no shares of common stock repurchased in 2009 or 2008.
Recent Accounting Pronouncements
See consolidated financial statement Note 2, “Recently Adopted and Recently Issued Accounting Standards,” for information on recent accounting pronouncements affecting Allegheny.
Credit Ratings
The following table lists Allegheny’s credit ratings, as of March 1, 2010:
(a) Issuer Default Rating
MARKET RISK INFORMATION
Allegheny is exposed to market risks associated with changes in commodity prices and interest rates as well as credit risk. The commodity price risk exposure results from market fluctuations in the price and transportation costs of electricity, coal, natural gas and other energy-related commodities. The interest rate risk exposure results from changes in interest rates related to variable-rate debt and debt that is maturing and will be refinanced. Allegheny has a program designed to systematically identify, measure, evaluate and actively manage and assess market risks.
Allegheny has a Corporate Risk Policy adopted by its Board of Directors and compliance with this policy is monitored by a Risk Management Committee, which is chaired by its Chief Executive Officer or his designee and is composed of senior management. An independent risk management group within Allegheny also measures and monitors the risk exposures to ensure compliance with the policy and to ensure that the policy is periodically reviewed.
Commodity Price Risk
Allegheny has commodity price risk to the extent that the amount of energy it generates and contracts to purchase differs from the amount of energy it has contracted to sell. Allegheny is also exposed to market risks associated with changes in commodity prices resulting from changes in supply and demand, fuel costs, market liquidity, weather, environmental regulation and other factors.
To manage its exposure to market price changes relating to its energy related assets, liabilities and other contractual arrangements, Allegheny sells and purchases physical energy at the wholesale and retail level and
enters into financial exchange-traded and over the counter derivative contracts. See consolidated financial statement Note 13, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for information regarding Allegheny’s derivative positions held at December 31, 2009.
In general, increases in forward market prices for power have a positive impact, and decreases in forward market prices have a negative impact, on Allegheny’s owned and contracted generation positions that have not been hedged. As of December 31, 2009, the percentage of expected coal-fired generation hedged was approximately 82%, 30%, 4% and 1% for 2010, 2011, 2012 and 2013, respectively. These percentages represent the estimated amount of equivalent sales divided by the amount of energy purchases contracted and estimated to be generated by our coal plants in such periods.
Allegheny measures the sensitivity of the portfolio to potential changes in market prices using high-level sensitivity analysis and Value at Risk (See Derivative Market Risk section).
Allegheny performed a high-level sensitivity analysis of the impact of changes in power and coal prices on its future pre-tax income. The estimated market price exposure for Allegheny’s coal-fired generation portfolio associated with a $10 per MWh decrease in energy prices based on December 31, 2009 market conditions and hedged position would be a decrease in pre-tax income of approximately $62 million, $243 million and $329 million for 2010, 2011 and 2012, respectively. The estimated market price exposure for Allegheny’s coal-fired generation portfolio associated with a $10 per ton increase in coal prices based on December 31, 2009 market conditions and hedged position would be a decrease in pre-tax income of approximately $5 million, $48 million and $56 million for 2010, 2011, and 2012, respectively. These power and coal price sensitivities were estimated by individually adjusting power price assumptions and coal price assumptions, respectively, while in each case holding all other variables constant. Actual results could differ based on changes in load volumes, plant performance, dispatch changes, basis changes relative to PJM Western Hub power prices, among other factors.
To the extent Allegheny does not hedge against commodity price volatility, its consolidated results of operations, cash flows and consolidated financial position may be affected either favorably or unfavorably by a shift in the forward price curves and spot commodity prices.
Allegheny enters into certain contracts for the purchase and sale of electricity. Certain of these contracts are recorded at their fair value and are an economic hedge for the generation facilities. For accounting purposes, the generation facilities are recorded at historical cost less depreciation. As a result, Allegheny’s results of operations and financial position can be favorably or unfavorably affected by a change in forward market prices.
Of its commodity-driven risks, Allegheny is primarily exposed to risks associated with the wholesale and retail electricity markets, including generation, coal and other fuel procurement, power marketing and the purchase and sale of electricity. Allegheny’s wholesale and retail activities principally consist of bilateral forward contracts for the purchase and sale of electricity. The majority of these contracts represent commitments to purchase or sell electricity at fixed prices in the future. These forward contracts can require either physical or financial settlement.
Derivative Market Risk
Derivatives that are not designated as part of a cash flow hedge relationship or as normal purchase normal sale (“NPNS”) contracts are reported in revenues on a mark-to-market basis.
Allegheny and AE Supply measure their market risk exposure to mark-to-market derivative contracts other than FTRs using value at risk model (“VaR”). VaR is a statistical model that measures the variability of value and predicts the risk of loss based on historical market price and volatility data over a given period of time. The quantification of market risk using VaR provides a consistent measure of risk across diverse energy markets and products with different risk factors to set the overall corporate risk tolerance, determine risk targets and monitor
positions. Allegheny and AE Supply calculate VaR using the Monte-Carlo technique by simulating thousands of scenarios sampling from the probability distribution of uncertain market variables. In addition to VaR, Allegheny and AE Supply routinely perform stress and scenario analyses to measure extreme losses due to exceptional events. FTRs are excluded from Allegheny’s calculation of VaR due to the absence of liquid spot and forward markets.
AE Supply calculated the VaR of a 1-day holding period at a 95% confidence level using the full term of all remaining wholesale energy market positions that are accounted for on a marked-to-market basis. These wholesale energy market positions consist of derivatives in power, emissions and natural gas excluding FTRs. The FTRs are excluded from the VaR measurement as they are generally considered as the economic hedges that serve Allegheny’s load obligation. As of December 31, 2009 and December 31, 2008, this calculation yielded a VaR of approximately $1 million and $3 million, respectively. This VaR decrease is primarily due to the positions roll-off in the existing transactions being accounted for on a mark-to-market basis as described in consolidated financial statement Note 13 “Fair Value Measurements, Derivative Instruments and Hedging Activities.”
The value of FTRs generally represents an economic hedge of future congestion charges incurred to serve Allegheny’s load obligations. The related load obligations, however, are not reflected in Allegheny’s Consolidated Balance Sheets. As a result, the timing of recognition of gains or losses on FTRs will differ from the timing of power purchases, including incurred congestion charges. The fair value of FTRs has been determined using an internal model based on data from PJM annual and monthly FTR auctions. These monthly auction results can change significantly over time and may differ from the final settlement amounts. As described in consolidated financial statement Note 13 “Fair Value Measurements, Derivative Instruments and Hedging Activities,” Allegheny recorded $33.2 million in unrealized gains attributable to FTRs during the twelve months ended December 31, 2009.
Interest Rate Risk
At December 31, 2009, AE did not have any debt subject to variable interest except for $455 million of variable rate debt relating to the TrAIL project, which is provided a return for recovery of the estimated cost of debt, compared to $537.0 million of outstanding debt subject to variable interest rates at December 31, 2008. See consolidated financial statement Note 8, “Capitalization and Debt” for additional information regarding Allegheny debt.
Credit Risk
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. Allegheny evaluates the credit standing of a prospective counterparty based on the prospective counterparty’s financial condition. Where deemed necessary, Allegheny may impose specified collateral requirements and use standardized agreements that facilitate netting of cash flows. Allegheny monitors the financial conditions of existing counterparties on an ongoing basis. Allegheny’s independent risk management group oversees credit risk.
Allegheny engages in various energy transacting activities. The counterparties to these transactions generally include electric and natural gas utilities, independent power producers, energy marketers and commercial and industrial customers. In the event the counterparties do not fulfill their obligations, Allegheny may incur a loss to close out a position.
Allegheny has a concentration of counterparties in the electric and natural gas utility industries. This concentration of counterparties may affect Allegheny’s overall exposure to credit risk, either positively or negatively, because these counterparties may be similarly affected by changes in economic or other conditions.
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. 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. 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 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. Changes in the supply and price of coal could have a material adverse effect on Allegheny’s business, results of operations, cash flow and financial condition.
As of December 31, 2009, Allegheny’s commodity hedges are comprised primarily of derivatives that will expire through May 2013.
Allegheny currently is involved in a number of capital intensive projects, including the TrAIL Project, the PATH Project and Act 129 related projects in Pennsylvania. Allegheny has contracted, or expects to contract, with specialized vendors to acquire some of the necessary materials and construction related services in order to complete these projects. As such, Allegheny is exposed to the risk that these contractors may not perform as required under their contracts. Should this occur, Allegheny may be forced to find alternate arrangements, which may cause delay and/or increased costs. Furthermore, Allegheny can provide no assurance that it would be able to make such alternate arrangements on terms acceptable to it or at all.
Allegheny also may be subject to credit risk through its participation in PJM, to the extent that PJM socializes counterparty defaults across PJM members.
Wholesale Credit Risk
Allegheny measures wholesale credit risk as the replacement cost for derivatives in power and natural gas excluding FTRs (both mark-to-market and accrual) adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where we have a legally enforceable right of setoff. Allegheny monitors and manages the credit risk of our wholesale marketing, risk management, and energy transacting operation through credit policies and procedures which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral, and the use of master netting agreements.
Retail Credit Risk
Allegheny is exposed to retail credit risk through our competitive electricity activities, which serve commercial and industrial companies. Retail credit risk results when customers default on their contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures, and the use of credit mitigation measures such as deposits in the form of letters of credit, security bonds, and cash or prepayment arrangements.
Retail credit quality is dependent on the economy and the ability of our customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, our retail credit risk may be adversely impacted.
As of December 31, 2009 and 2008, the credit portfolio of our wholesale and retail marketing, risk management, and energy transacting operation had the following public credit ratings:
(a) Includes counterparties with an investment grade rating by at least one of the major credit rating agencies. If split rating exists, the lower rating is used.
A portion of our total wholesale and retail credit risk is related to transactions that are recorded in our Consolidated Balance Sheets. These transactions primarily consist of open positions from our wholesale marketing, retail marketing, risk management, and energy transacting operations that are accounted for using derivative accounting, as well as amounts owed by wholesale counterparties for transactions that settled but have not yet been paid. The following table highlights the credit quality and exposures related to these activities, excluding FTRs, at December 31, 2009:
Due to the possibility of extreme volatility in the prices of energy commodities and derivatives, the market value of contractual positions with individual counterparties could exceed established credit limits or collateral provided by those counterparties. If such a counterparty were then to fail to perform its obligations under its contract (for example, by failing to deliver the electricity our wholesale marketing, risk management, and energy transacting operation had contracted for), we could incur a loss that could have a material impact on our financial results.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with GAAP requires management to apply accounting policies and make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. The areas described in this section require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are uncertain and that may change in subsequent periods. Further discussion of the application of these accounting policies can be found in the Notes to Consolidated Financial Statements.
Revenues and Receivables: Revenues from the sale of electricity to customers are recognized in the period that the electricity is delivered and consumed by customers, including an estimate for unbilled revenues. Energy billings to individual customers are based on meter readings, which are performed periodically on a systematic basis. At the end of each month, the amount of energy delivered to each customer is estimated based in part on the most recent reading of the customer’s meter, and the Distribution Companies recognize unbilled revenues that reflect these estimates. The unbilled revenue estimates are based on daily generation, purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses and the most recent consumer rates. A provision for uncollectible accounts is recorded as a component of operations and maintenance expense.
Derivative Contracts: Derivative contracts are recorded in Allegheny’s Consolidated Balance Sheets at fair value with changes in the fair value of the derivative contract included in revenues or expenses on the Consolidated Statements of Income unless the derivative falls within the “normal purchases and normal sales” scope exception or is designated as a cash flow hedge for accounting purposes. The normal purchases and normal sales scope exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under accrual accounting and, therefore, are not recorded on the balance sheet at fair value. For certain transactions that are designed to hedge the cash flows of a forecasted transaction, the effective portion of the hedge is recorded as a separate component of stockholders’ equity under the caption “Accumulated other comprehensive loss” and subsequently reclassified into earnings when the forecasted transaction is completed or settled. Changes in the value of any ineffective portion of the hedge are immediately recognized in earnings.
Fair values for exchange-traded instruments, principally futures, are based on actively quoted market prices. Fair values are subject to change in the near term and reflect management’s best estimate based on various factors. In establishing the fair value of commodity contracts that do not have quoted prices, such as physical contracts, FTRs and swaps, management uses available market data and pricing models to estimate fair values. Estimating the fair values of instruments that do not have quoted market prices requires management’s judgment in determining amounts that could reasonably be expected to be received from, or paid to, a third party in settlement of the instruments. These amounts could be materially different from amounts that might be realized in an actual sale transaction.
Allegheny has netting agreements with various counterparties. These agreements provide the right to set off amounts due from or to the counterparty. In cases in which these netting agreements are in place, Allegheny records the fair value of derivative assets and liabilities and of accounts receivable and accounts payable with each counterparty on a net basis. In addition, FTR assets and obligations are recorded on a net basis. Cash flows associated with derivative contracts are recorded in cash flows from operating activities. See consolidated financial statement Note 13, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for additional details regarding energy transaction activities.
Regulatory Accounting: The Distribution Companies, TrAIL Company and PATH, LLC are subject to regulations that set the rates that they are permitted to charge customers. These rates are based on costs that the applicable regulatory agencies determine that the Distribution Companies, TrAIL Company and PATH, LLC are permitted to recover. At times, regulators permit the future recovery through rates of incurred costs that would otherwise be charged to expense by an unregulated company. At times, regulators may also allow the collection of amounts in rates for costs expected to be incurred in the future or may require that amounts collected be set aside for a specific purpose or be credited or refunded to customers in the future. This ratemaking process often results in the recording of regulatory assets and liabilities based on estimated future cash inflows and outflows under regulatory guidelines and orders. Allegheny regularly reviews its regulatory assets and liabilities, including the estimates and assumptions on the basis of which they have been recorded and related regulatory interpretations.
Depreciation: Depreciation expense is determined generally on a straight-line group method over the estimated service lives of depreciable assets for unregulated operations. For regulated utility operations, depreciation expense is determined using a straight-line group method in accordance with currently enacted regulatory rates. Under the straight-line group method, plant components are categorized as “retirement units” or “minor items of property.” As retirement units are replaced, the cost of the replacement is capitalized and the original component is retired. Replacements of minor items of property are expensed as maintenance.
Long-Lived Assets: Allegheny’s Consolidated Balance Sheets include significant long-lived assets that are not subject to recovery under cost of service based ratemaking. Allegheny’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not
be recoverable through operations. If the carrying amount of the asset exceeds its fair value as determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows and market-value-to-earnings comparisons, an impairment loss is recognized, and the asset is written down to its fair value.
Excess of Cost Over Net Assets Acquired (Goodwill): Recorded goodwill is tested for impairment at least annually, and more frequently upon indication of possible impairment. The first phase of a goodwill impairment test involves comparison of reporting unit fair value to the carrying value of the reporting unit that has been assigned goodwill. All of Allegheny’s goodwill is recorded in its Merchant Generation reporting unit. This impairment testing requires the use of estimates, assumptions and other inputs to determine the fair value of the Merchant Generation reporting unit using both a discounted cash flow approach and a market-based valuation approach. These estimates, assumptions and other inputs involve the use of judgment, and changes in these inputs can significantly impact the estimated reporting unit fair value. No impairment of goodwill was recorded during any of the years presented.
Income Taxes: Allegheny is subject to income taxes in the United States and in various state jurisdictions. Significant judgment is required in evaluating tax positions and determining the provisions for income taxes. Allegheny establishes reserves for tax-related uncertainties based on estimates of whether, and the extent to which, additional taxes will be due. Allegheny adjusts these reserves in light of changing facts and circumstances, such as the outcome of tax audits.
Stock-Based Compensation: GAAP requires measurement of compensation cost for all stock-based awards at fair value on the date of grant and recognition of compensation cost over the service period for the awards expected to vest. The determination of grant date fair value requires the use of judgment based on historical information as well as future expectations. In addition, the estimates of stock-based awards that will ultimately vest requires judgment, and actual results or updated estimates may differ from current estimates. See consolidated financial statement Note 10, “Stock-Based Compensation,” for additional information.
Accounting for Pensions and Postretirement Benefits Other Than Pensions: There are a number of significant estimates and assumptions involved in determining Allegheny’s pension and other postretirement benefit (“OPEB”) obligations and costs each period, such as employee demographics, discount rates, expected rates of return on plan assets, estimated rates of future compensation increases, medical inflation and the fair value of plan assets. Changes made to provisions for pension or other postretirement benefit plans may also affect current and future pension and OPEB costs. Allegheny believes that its assumptions are supported by historical data and reasonable projections, and its projections are reviewed annually with an outside actuarial firm. See consolidated financial statement Note 11, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for additional information concerning these assumptions.
Allegheny determines its discount rate assumptions through the use of a cash flow matching process in which the timing and amount of estimated benefit cash flows for each benefit plan are matched with an interest rate curve applicable to the returns of high quality corporate bonds over the expected benefit payment period to determine an overall effective discount rate. The interest rate curve used in this process is based primarily on the Citigroup Pension Discount Curve and the Citigroup Above Median Pension Discount Curve.
Allegheny’s general approach for determining the overall expected long-term rate of return on plan assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The following table shows the effect that a one percentage point increase or decrease in the discount rate on plan assets for 2009 would have on Allegheny’s pension and OPEB obligations and costs:
Contingencies: Allegheny regularly reviews and assesses the likelihood of losses relating to environmental, legal and other contingencies and accrues a liability for matters for which it believes that a loss is probable if the probable loss can be estimated. See consolidated financial statement Note 25, “Commitments and Contingencies,” for additional information.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A relating to market risk is included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No.
Consolidated Financial Statements of Allegheny Energy, Inc. and Subsidiaries
Reports of Independent Registered Public Accounting Firms
Schedule I AE (Parent Company) Condensed Financial Statements
Schedule II Valuation and Qualifying Accounts
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued)
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME (Continued)
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY AND COMPREHENSIVE INCOME (Continued)
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note
Page
Number
Business, Basis of Presentation and Significant Accounting Policies
Recently Adopted and Recently Issued Accounting Standards
Assets Held for Sale
Rates and Regulation
Transmission Expansion
Regulatory Assets and Liabilities
Income Taxes
Capitalization and Debt
Earnings per Share
Stock-Based Compensation
Pension Benefits and Postretirement Benefits Other Than Pensions
Segment Information
Fair Value Measurements, Derivative Instruments and Hedging Activities
Purchase of Hydroelectric Generation Facilities
Dividend Restrictions
Jointly Owned Bath County Generation Facility
Financial Instruments
Goodwill and Intangible Assets
Asset Retirement Obligations (“ARO”)
Adverse Power Purchase Commitment Liability
Other Income (Expense), Net
Guarantees and Letters of Credit
Variable Interest Entities
Acquisition of Noncontrolling Interest in AE Supply
Commitments and Contingencies
Quarterly Financial Information (Unaudited)
Subsequent Event-Merger Agreement
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: BUSINESS, BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Merger Agreement
On February 10, 2010, Allegheny Energy, Inc. (“AE”), FirstEnergy Corp. (“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”). See Note 27, “Subsequent Event - Merger Agreement” for additional information.
Business Description
Allegheny Energy, Inc. (“AE” and, together with its subsidiaries, “Allegheny”) is an integrated energy business that owns and operates electric generation facilities and delivers electric services to customers in Pennsylvania, West Virginia, Maryland and Virginia. Allegheny manages its operations through two business segments: Merchant Generation and Regulated Operations. These business segments are also referred to as reportable segments.
The Merchant Generation segment includes Allegheny’s unregulated electric generation operations including Allegheny Energy Supply Company, LLC (“AE Supply”), and AE Supply’s interest in Allegheny Generating Company (“AGC”). AE Supply owns, operates and controls electric generation capacity and supplies and trades energy and energy-related commodities. AGC owns and sells generation capacity to AE Supply and Monongahela, which own approximately 59% and 41% of AGC, respectively. The Merchant Generation segment is subject to federal and state regulation but, unlike the Regulated Operations segment, is not generally subject to state regulation of rates.
The Regulated Operations segment consists of Allegheny’s regulated operations including the operations of Monongahela Power Company (“Monongahela”), The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”), Trans-Allegheny Interstate Line Company (“TrAIL Company”) and Potomac-Appalachian Transmission Highline, LLC (“PATH, LLC”). The Distribution Companies (Potomac Edison, West Penn and Monongahela) primarily operate electric transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia, Maryland and Virginia. Monongahela also owns and operates electric generation facilities in West Virginia and has an ownership interest in AGC. The Distribution Companies are subject to federal and state regulation, including regulation of rates. TrAIL Company was formed in 2006 to construct transmission expansion projects, including the Trans-Allegheny Interstate Line (“TrAIL”), a 500 kV transmission line to extend from southwestern Pennsylvania through West Virginia and into northern Virginia. PATH, LLC, which is a series limited liability company, was formed in 2007 with a subsidiary of American Electric Power Company, Inc. (“AEP”) to construct the Potomac-Appalachian Transmission Highline (“PATH”), a high-voltage transmission line that is proposed to extend across West Virginia and into Maryland. TrAIL Company and PATH, LLC are subject to the regulation of rates by the Federal Energy Regulatory Commission (the “FERC”).
Allegheny Energy Service Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of Allegheny’s personnel. As of December 31, 2009, AESC employed 4,383 employees, 1,223 of whom were subject to collective bargaining arrangements.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of AE and its subsidiaries, as well as certain variable interest entities (See Note 23, “Variable Interest Entities,” for additional information). These consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
principles, or GAAP. All significant intercompany accounts and transactions have been eliminated in consolidation. Events occurring subsequent to the date of the balance sheet have been evaluated for potential recognition or disclosure in the consolidated financial statements through the date of filing with the SEC.
Reclassifications
As described in Note 12, “Segment Information,” Allegheny changed the composition of its reportable segments during 2009. Segment disclosures for 2008 and 2007 have been reclassified to conform to the 2009 presentation. Certain additional amounts in previously issued financial statements have been reclassified to conform to the current presentation, including the retrospective application of the provisions of SFAS No.160 (ASC Topic 810) as described in Note 2, “Recently Adopted and Recently Issued Accounting Standards.”
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of derivative and energy contracts, asset retirement obligations, the effects of regulation, long-lived asset recovery, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Regulatory Assets and Liabilities
Under cost-based regulation, regulated utility enterprises generally are permitted to recover their operating expenses and earn a reasonable return on their utility investment.
Allegheny accounts for its regulated utility operations under regulated industry specific accounting provisions. The economic effects of regulation can result in a regulated company deferring costs or revenues that have been, or are expected to be, allowed in the rate-setting process in a period different from the period in which the costs, revenues or other comprehensive income would be recognized by an unregulated enterprise. Accordingly, Allegheny records assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” Allegheny periodically evaluates the applicability of regulated industry specific accounting provisions and considers factors such as regulatory changes and the impact of competition. If regulated industry specific accounting provisions would no longer apply to some portion of Allegheny’s operations, Allegheny would eliminate the related regulatory assets and liabilities and record the impact as an extraordinary item in the statement of income. See Note 6, “Regulatory Assets and Liabilities,” for additional information.
Revenues and Receivables
Revenues from the sale of generation are recorded in the period in which the electricity is delivered.
PJM Interconnection, LLC (“PJM”) is a regional transmission organization that operates a competitive wholesale energy market. To facilitate the economic dispatch of Allegheny’s generation, AE Supply and Monongahela sell most of the power that they generate into the PJM market and purchase from the PJM market most of the power needed to meet their contractual obligations to supply power. PJM power purchases and sales are reported on a net basis.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Revenues from the sale of electricity to customers of the regulated utility subsidiaries are recognized in the period that the electricity is delivered and consumed by customers, including an estimate for unbilled revenues. Energy billings to individual customers are based on meter readings, which are performed periodically on a systematic basis. At the end of each month, the amount of energy delivered to each customer is estimated based in part on the most recent reading of the customer’s meter, and the Distribution Companies recognize unbilled revenues that reflect these estimates. The unbilled revenue estimates are based on daily generation, purchases of electricity, estimated customer usage by customer type, weather effects, electric line losses and the most recent consumer rates.
A provision for uncollectible accounts is recorded as a component of operations and maintenance expense.
Fair Value Measurements, Derivative Instruments and Hedging Activities
Derivative contracts are recorded in Allegheny’s Consolidated Balance Sheets at fair value. Changes in the fair value of the derivative contract are included in revenues or expenses on the Consolidated Statements of Income unless the derivative falls within the “normal purchases and normal sales” scope exception or is designated as a cash flow hedge for accounting purposes. The normal purchases and normal sales scope exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under accrual accounting and, therefore, are not recorded on the balance sheet at fair value. For certain transactions that are designed to hedge the cash flows of a forecasted transaction and that are designated in a hedging relationship, the effective portion of the changes in fair value of the derivative contract is recorded as a separate component of equity under the caption “Accumulated other comprehensive loss” and subsequently reclassified into earnings when the forecasted transaction is settled and impacts earnings. The ineffective portion of the hedge is immediately recognized in earnings.
Fair values for exchange-traded instruments, principally futures, are based on actively quoted market prices. Fair values are subject to change in the near term and reflect management’s best estimate based on various factors. In establishing the fair value of commodity contracts that do not have quoted prices, such as physical contracts, financial transmission rights (“FTRs”) and swaps, management uses available market data and pricing models to estimate fair values. Estimating the fair values of instruments that do not have quoted market prices requires management’s judgment in determining amounts that could reasonably be expected to be received from, or paid to, a third party in settlement of the instruments. These amounts could be materially different from amounts that might be realized in an actual sale transaction.
Allegheny has netting agreements with various counterparties. These agreements provide the right to set off amounts due from or to the counterparty. In cases in which these netting agreements are in place, Allegheny records the fair value of derivative assets, liabilities and cash collateral and accounts receivable and accounts payable with each counterparty on a net basis. Cash flows associated with derivative contracts are recorded in cash flows from operating activities. See Note 13, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for additional details regarding energy transacting activities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Deferred Energy Costs
Deferred energy costs represent the deferral of certain energy costs from the period in which they were incurred to the period in which such costs are recovered in rates. Allegheny records deferred energy costs relating to the following items:
Expanded Net Energy Cost (“ENEC”)
In May 2007, the Public Service Commission of West Virginia (the “West Virginia PSC”) issued an order that re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs, including purchased power costs associated with the Grant Town PURPA generation facility and other related expenses, net of related revenue and interest earnings on the Fort Martin Scrubber project escrow fund. Under the ENEC, actual costs and revenues are tracked for under and/or over recoveries, and revised ENEC rate filings are made on an annual basis. Any under and/or over recovery of costs, net of related revenues, is deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability, with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.” See Note 4, “Rates and Regulation,” and Note 6, “Regulatory Assets and Liabilities,” for additional information.
Market-based Generation Costs
Potomac Edison is authorized by the Public Service Commission of Maryland (the “Maryland PSC”) to recover the costs of the generation component of power sold to certain residential, commercial and industrial customers who did not choose a third-party alternative generation provider. A regulatory asset or liability is recorded on Potomac Edison’s balance sheet for any under-recovery or over-recovery of the generation component of costs charged to these customers. In addition, under an order of the Virginia State Corporation Commission (the “Virginia SCC”), Potomac Edison was granted a rate adjustment to recover a portion of its increased purchased power costs. The order directed Potomac Edison to defer any under- or over-recovery of purchased power costs approved.
AES Warrior Run PURPA Generation Facility
To satisfy certain of its obligations under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), Potomac Edison entered into a long-term contract beginning July 1, 2000 to purchase capacity and energy from the AES Warrior Run PURPA generation facility through the beginning of 2030. Potomac Edison is authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run PURPA generation facility, net of any revenues received from the sale of AES Warrior Run output into the wholesale energy market, by means of a retail revenue surcharge (the “AES Warrior Run Surcharge”). Any under-recovery or over-recovery of net costs is being deferred pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge.
Grant Town PURPA Generation Facility
Monongahela acquires energy from the Grant Town PURPA generation facility in West Virginia. The West Virginia PSC approved an amendment to the Electric Energy Purchase Agreement between Monongahela and American Bituminous Power Partners, L.P., the owners of the Grant Town PURPA generation facility, in April 2006. The amendment provided for an increase in the price of energy that Monongahela is acquiring until 2017. The West Virginia PSC authorized Monongahela to institute a temporary surcharge designed to recover the increase in costs from West Virginia customers, as well as a deferred accounting mechanism by which actual aggregate amounts of the incremental cost increase were tracked and reconciled by comparison to the aggregate
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
amounts recovered from West Virginia customers through the temporary surcharge. As a result of the West Virginia Rate Order, beginning in 2007, these costs are included in the ENEC. See Note 4, “Rates and Regulation” for additional information.
Debt Issuance Costs
Costs incurred to issue debt are recorded as deferred charges on the Consolidated Balance Sheets. These costs are amortized over the term of the related debt instrument primarily using the effective interest method.
Common Services and Intercompany Transactions
Common Services. Substantially all of Allegheny’s personnel are employed by AESC, which performs services at cost for other Allegheny entities and makes payments on behalf of Allegheny entities. Each entity is responsible for its share of the cost of services provided by AESC and payments made by AESC on behalf of the entities.
Income Taxes. AE and its subsidiaries file a consolidated federal income tax return. Federal income tax expense (benefit) and tax assets and liabilities are allocated among AE and its subsidiaries generally in proportion to the taxable income of each participant, except that no subsidiary pays tax in excess of its separate return income tax liability.
Allegheny Money Pool. Allegheny manages excess cash through its internal money pool. The money pool provides funds to approved AE subsidiaries at the lower of the Federal Reserve’s previous day federal funds effective interest rate, or the Federal Reserve’s previous day seven day commercial paper rate, less four basis points. The minimum interest rate charged to approved AE subsidiaries is zero percent. AE and AE Supply can only place money into the money pool. West Penn and Potomac Edison can either place money into, or borrow money from, the money pool. AGC can only borrow money from the money pool. Beginning in December 2009, Monongahela can only invest money into the money pool, and amounts invested by Monongahela may not be borrowed by any other AE subsidiary.
Power Sales and Purchases. AE Supply provides power to Potomac Edison and West Penn to satisfy a portion of the power necessary to meet their respective retail load. AE Supply and Monongahela purchase all of AGC’s capacity in the Bath County generation facility under a “cost-of-service formula” wholesale rate schedule approved by FERC on a proportionate basis, based on their respective equity ownership of AGC.
Leases. West Penn and Monongahela own property, including buildings and software that they lease primarily to AESC for its use in providing services to AE and its affiliates.
Long-Lived Assets
Property, Plant and Equipment
Property, plant and equipment (“property”) is recorded at original cost. This cost includes direct labor, materials and indirect costs, such as operation, maintenance and depreciation of transportation and construction equipment, taxes, postretirement benefits and other benefits related to employees to the extent they are engaged in construction. In addition, property subject to rate regulation includes an allowance for funds used during construction on property for which construction work in progress is not included in rate base. Property not subject to rate regulation includes capitalized interest during the construction period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Upon retirement of property of the Distribution Companies, no gain or loss is generally recognized and the original cost of the property less salvage is charged to accumulated depreciation. The cost of removal of regulated property is charged to the related regulatory liability or regulatory asset, and the cost of removal of unregulated property, for which no asset retirement obligation (“ARO”) has been recorded, is expensed as incurred.
Allegheny capitalizes the cost of software developed for internal use. These costs are amortized on a straight-line basis over the expected useful life of the software.
Depreciation and Maintenance
Depreciation expense is determined generally on a straight-line group method over the estimated service lives of depreciable assets for unregulated operations. For regulated utility operations, depreciation expense is determined using a straight-line group method in accordance with currently enacted regulatory rates. Under the straight-line group method, plant components are categorized as “retirement units” or “minor items of property.” As retirement units are replaced, the cost of the replacement is capitalized and the original component is retired. Replacements of minor items of property are expensed as maintenance. Depreciation expense was approximately 2.3% of average depreciable property in 2009, 2008 and 2007. Estimated service lives for generation, T&D and other property at December 31, 2009 were as follows:
Years
Generation property:
Steam scrubbers and equipment
43-65
Steam generator units
45-80
Internal combustion units
40-44
Hydroelectric dams and facilities
50-152
Transmission and distribution property:
Electric equipment
10-100
Easements
70-100
Other property:
Office buildings and improvements
42-60
General office and other equipment
10-25
Vehicles and transportation
7-25
Computers, software and information systems
5-20
The cost of repairs, maintenance including planned major maintenance activities, and minor replacements of property are charged to maintenance expense as incurred.
Capitalized Interest and Allowance for Funds Used During Construction (“AFUDC”)
For non-regulated companies, Allegheny capitalizes interest costs associated with construction activities. The average interest capitalization rates in 2009, 2008, and 2007 were 6.0%, 6.6% and 7.0%, respectively. Allegheny capitalized $25.9 million, $34.6 million, and $20.0 million of interest during 2009, 2008 and 2007, respectively.
AFUDC is a component of the construction of Property, Plant and Equipment defined in the applicable regulatory uniform system of accounts as representing “the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used.” AFUDC is capitalized in those instances in which the related construction work in progress is not included in rate base in the rate setting process and is reflected in the Consolidated Statements of Income as a reduction to Interest expense and Other income (expense), net to the extent it relates to borrowed funds and other funds used in construction,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
respectively. Rates used by the regulated subsidiaries in computing AFUDC in 2009, 2008 and 2007 averaged 7.3%, 7.2% and 7.6%, respectively. Allegheny recorded AFUDC of $8.3 million in 2009 and $6.6 million in 2008 and 2007, of which $5.0 million, $3.7 million and $2.7 million was reflected in “Other income (expense), net” and $3.3 million, $2.9 million and $3.9 million was reflected as a reduction to “Interest expense” in 2009, 2008 and 2007, respectively.
Asset Impairment
Allegheny’s long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through operations. If the carrying amount of the asset exceeds the expected undiscounted future cash flows to be generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Allegheny did not record any impairment charges during 2009 and 2008.
Asset Retirement Obligations and Cost of Removal
A liability for the fair value of an asset retirement obligation (“ARO”) is recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a part of the carrying amount of the long-lived assets. The asset retirement cost is subsequently charged to expense over its useful life. Changes in the ARO resulting from the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Changes resulting from revisions to the timing or amount of the original estimate of cash flows are recognized as an increase or decrease in the asset retirement cost and ARO. When settled, actual ARO costs are charged against the recorded liability.
In addition, the Distribution Companies recover cost of removal (“COR”) for property, plant and equipment in their rates. In some jurisdictions, the recovery is provided prior to the time of asset retirement, in which case, the amounts collected are recorded as a regulatory liability. In other jurisdictions, the amounts are recovered only after being incurred, in which case, the amounts incurred are recorded as a regulatory asset until recovered. When incurred, COR costs are charged to the regulatory asset or liability.
Goodwill and Intangible Assets
Goodwill represents the acquisition cost of a business combination in excess of fair value of tangible and intangible assets acquired, less liabilities assumed. Recorded goodwill is not amortized, but is tested for impairment at least annually. Other intangible assets with finite lives are amortized over their useful lives and tested for impairment when events or circumstances warrant. See Note 18, “Goodwill and Intangible Assets” for additional information.
Investments in Unconsolidated Affiliates
Investments in unconsolidated affiliates are typically accounted for under the equity method of accounting. The income or loss on such investments is recorded in “Other income (expense), net” in the Consolidated Statements of Income. Investments in unconsolidated affiliates of $26.7 million and $28.0 million at December 31, 2009 and 2008, respectively, primarily consisted of Allegheny’s investment, through AE Supply, in Buchanan Generation LLC.
Cash Equivalents
For purposes of the Consolidated Statements of Cash Flows and Consolidated Balance Sheets, investments in money market funds and highly liquid investments purchased with original maturities of three months or less are considered to be the equivalent of cash.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Restricted Funds
At December 31, 2009 and 2008, Allegheny had current restricted funds of $25.9 million and $36.8 million, respectively. Current restricted funds at December 31, 2009 included $20.6 million of funds collected from West Virginia customers that will be used to service the environmental control bonds in connection with the construction of the Scrubbers at Fort Martin and $5.3 million of intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. Current restricted funds at December 31, 2008 included $21.9 million of funds collected from West Virginia customers that will be used to service the environmental control bonds in connection with the construction of Scrubbers at Fort Martin and $14.9 million of intangible transition charges collected from West Penn customers related to Pennsylvania transition costs. In addition, at December 31, 2009 and 2008, Allegheny had long-term restricted funds of $60.2 million and $133.3 million, respectively. Long-term restricted funds at December 31, 2009 included $10.3 million of funds remaining from the $235 million Pennsylvania Development Financing Authority bond issued in connection with the construction and installation of Scrubbers at Hatfield’s Ferry generation facility, $49.6 million of funds relating to proceeds from the issuance of ratepayer obligation bonds in connection with the construction of the Scrubbers at Fort Martin and $0.3 of escrow funds related to the Scrubber construction projects. Long-term restricted funds at December 31, 2008 consisted of funds relating to proceeds from the issuance of ratepayer obligation bonds in connection with the construction of the Scrubbers at Fort Martin.
Collateral Deposits
Allegheny posts collateral with counterparties, including PJM, for certain transactions and transmission and transportation tariffs. Approximately $20.8 million and $33.4 million of cash collateral deposits were included in current assets at December 31, 2009 and 2008, respectively. Approximately $3.1 million and $0.2 million of cash collateral deposits were netted against derivative liabilities on the Consolidated Balance Sheets at December 31, 2009 and 2008, respectively.
In addition, approximately $27.5 million of counterparty collateral deposits are netted against derivative assets on the Consolidated Balance Sheets at December 31, 2009.
Inventory
Allegheny records materials, supplies and fuel inventory, including emission allowances, using the average cost method.
Income Taxes
Allegheny computes income taxes under the liability method. Deferred income tax balances are generally determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse. Tax benefits are recognized in the financial statements when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. Such tax positions are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts.
Deferred income tax assets have also been recorded on the tax effects of net operating losses that are more likely than not to be realized through future operations and through the reversal of existing temporary differences. Allegheny has deferred investment tax credits associated with its regulated business and assets previously held by its regulated business. These investment tax credits are amortized to income on a straight-line basis over the life of the assets. See Note 7, “Income Taxes” for additional information.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Taxes Collected from Customers and Remitted to Governmental Authorities
Allegheny records taxes collected from customers, which are directly imposed on a transaction with that customer, on a net basis. That is, in instances in which Allegheny acts as a collection agent for a taxing authority by collecting taxes that are the responsibility of the customer, Allegheny records the amount collected as a liability and relieves such liability upon remittance to the taxing authority without impacting revenues or expenses.
Pension and Other Postretirement Benefits
Allegheny sponsors a noncontributory, defined benefit pension plan covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. Allegheny also maintains a Supplemental Executive Retirement Plan for executive officers and other senior executives. Allegheny also provides partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, have retiree premiums based upon an age and years-of-service vesting schedule, include other plan provisions that limit future benefits and take into account certain collective bargaining arrangements.
Pension and other postretirement benefit expense is determined by an actuarial valuation, based on assumptions that are evaluated annually.
See Note 11, “Pension Benefits and Postretirement Benefits Other Than Pensions” for additional information.
Stock-Based Compensation
Share-based payments are generally measured at fair value on the date of grant and are expensed over the requisite service period. For options, Allegheny is entitled to income tax deductions in an amount equal to the fair value of shares on the date of the option exercise less the option exercise price. To the extent that the income tax deduction exceeds the cumulative compensation expense recorded for book purposes, the tax effect of the excess (referred to as a windfall tax benefit) is recorded as a credit to stockholders’ equity when the tax benefit is realized. See Note 10, “Stock-Based Compensation” for additional information.
Accumulated Other Comprehensive Loss
The components of accumulated other comprehensive loss, included in the shareholders’ equity section of the Consolidated Balance Sheets, were as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 2: RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2009, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that replaced the previous hierarchy of GAAP and established the FASB Accounting Standards Codification (“FASB Codification”) as the single source of authoritative U.S. GAAP recognized by the FASB to be applied to the financial statements of nongovernmental entities for periods ending after September 15, 2009. Securities and Exchange Commission (“SEC”) rules and interpretive releases are also sources of authoritative GAAP for SEC registrants. This guidance modifies the GAAP hierarchy to include only two levels of GAAP: authoritative and nonauthoritative. The FASB Codification was not intended to change or alter existing GAAP, and Allegheny’s adoption of this guidance did not impact its results of operations, cash flows or financial position.
Consolidation of Variable Interest Entities
In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (“SFAS 167”). SFAS 167 amends FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities-an interpretation of ARB No. 51,” (“FIN 46(R)”), (FASB Codification Topic 805) including: a modified definition of primary beneficiary to include the power to direct the most significant activities of the variable interest entity; a requirement to perform an analysis to determine whether an enterprise’s variable interests give it a controlling financial interest in a variable interest entity; a requirement to perform ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity; and enhanced disclosures with more transparent information about an enterprise’s involvement in a variable interest entity. Although it has not yet completed its analysis, Allegheny expects to deconsolidate PATH-WV from its financial statements effective January 1, 2010. See Note 23, “Variable Interest Entities” for additional information relating to variable interest entities.
Subsequent Events
On June 16, 2009, Allegheny adopted SFAS No. 165, “Subsequent Events” (“SFAS 165”), (FASB Codification Topic 810). SFAS 165 establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued. Specifically, SFAS 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Its adoption had no effect on Allegheny’s financial statements.
Fair Value Measurements and Disclosures
On January 1, 2009, Allegheny adopted FSP FAS No. 157-2, “Effective Date of FASB Statement 157” (“FSP FAS 157-2”), (FASB Codification Topic 820), which permitted a one-year deferral of the application of SFAS 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Allegheny adopted SFAS 157, effective January 1, 2008 for financial assets and liabilities, and deferred application of SFAS 157 for non-financial assets and liabilities that are not recognized at fair value on a recurring basis until January 1, 2009. The application of SFAS 157 to non-financial assets and liabilities effective January 1, 2009 did not have a material impact on Allegheny’s results of operations or financial position.
On April 1, 2009, Allegheny adopted FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” (“FSP FAS 157-4”), (FASB Codification Topic 820). FSP FAS 157-4 provides additional
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guidance for estimating fair value in accordance with issued SFAS No. 157, “Fair Value Measurements,” when the volume and level of activity for the asset or liability have significantly decreased and includes guidance for identifying circumstances that indicate a transaction is not orderly. The adoption of FSP FAS 157-4 had no impact on Allegheny’s financial statements.
On December 31, 2009, Allegheny adopted the FASB’s ASU on “Investments in Certain Entities that Calculated Net Asset Value per Share.” The ASU provides a practical method for the fair value measurement of certain investments that do not have a readily determinable fair value. The adoption affected the fair value measurement of certain of Allegheny’s pension plan investments, but did not have material impact on Allegheny’s results of operations or financial position.
Derivative Instrument and Hedging Disclosures
On January 1, 2009, Allegheny adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS 161”), (FASB Codification Topic 815). SFAS 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of derivative contracts and the gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. SFAS 161 also requires disclosure of the location of the derivative contracts and their related gains and losses in an entity’s financial statements. Allegheny’s adoption of SFAS 161 affected Allegheny’s derivative disclosures but did not impact Allegheny’s results of operations or financial position.
Noncontrolling Interests
On January 1, 2009, Allegheny adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51” (“SFAS 160”), (FASB Codification Topic 810). SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary (formerly “minority interest”) and for the deconsolidation of a subsidiary. It also amends certain consolidation procedures for consistency with SFAS No. 141 (revised 2007), “Business Combinations.” Under SFAS 160, non-controlling interests are reported in the consolidated statement of financial position as a separate component within equity, and consolidated net income and consolidated comprehensive income are adjusted to include amounts attributable to the noncontrolling interests, for all periods presented. Allegheny’s adoption of SFAS 160 affected its financial statement presentation but did not materially affect Allegheny’s results of operations or financial position.
Postretirement Benefit Plan Asset Disclosures
In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP FAS 132(R)-1”), (FASB Codification Topic 710). This pronouncement amends SFAS No. 132 to require disclosure of the fair value of categories of plan assets based on the types of assets held in the plan, disclosures about the nature and amounts of concentrations of risk within categories of plan assets, and disclosures about the fair value measurement inputs, similar to SFAS 157. FSP FAS 132(R)-1 became effective for Allegheny beginning with disclosures as of December 31, 2009 and affected Allegheny’s financial statement disclosure but did not impact Allegheny’s results of operations or financial position.
NOTE 3: ASSETS HELD FOR SALE
On May 4, 2009, Potomac Edison signed definitive agreements to sell its electric distribution operations in Virginia (“VA Distribution Business”) to Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative (the “Cooperatives”). The agreements are subject to state regulatory approval in Virginia and West
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Virginia, as well as federal approval and certain third-party consents. Under the terms of the agreements, Potomac Edison will transfer its Virginia distribution assets and certain related liabilities to the Cooperatives in exchange for cash proceeds of approximately $340 million, subject to adjustment for changes in assets and liabilities through the closing date. As part of their agreement, Allegheny will purchase certain West Virginia distribution operations from Shenandoah Valley Electric Cooperative for approximately $15 million. The sale is subject to regulatory approval by the Virginia State Corporate Commission (the “Virginia SCC”). Evidentiary hearings regarding this matter before the Virginia SCC are scheduled to begin on 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 were to serve those customers. Potomac Edison and the Cooperatives filed rebuttal testimony on February 12, 2010. The VA Distribution Business is included in the Regulated Operations segment.
For periods after May 4, 2009, assets and liabilities relating to the VA Distribution Business are classified as “held for sale” in Allegheny’s consolidated balance sheets, and depreciation expense on those assets ceased. Assets held for sale and liabilities associated with assets held for sale at December 31, 2009 were as follows:
NOTE 4: RATES AND REGULATION
Pennsylvania
Rates. Rate caps on transmission services in Pennsylvania expired on December 31, 2005. Distribution rate caps were also scheduled to expire on December 31, 2005 and generation rate caps were scheduled to expire on December 31, 2008. By order entered May 11, 2005, the Pennsylvania Public Utility Commission (the “Pennsylvania PUC”) approved an extension of generation rate caps for West Penn customers from 2008 to 2010 and provided for increases in generation rates in 2007, 2009 and 2010, in addition to previously approved rate
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cap increases for 2006 and 2008. The order also extended distribution rate caps from 2005 to 2007, with an additional rate cap in place for 2009 at the rate in effect on January 1, 2009. The intent of this transition plan is to gradually move generation rates closer to market prices. T&D rates for all customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
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 electric distribution company (“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-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 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 previously 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, as originally proposed, would provide 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 proposes to build a new and secure telecommunications
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network. To support time of use and real time pricing as required by Act 129, West Penn proposes to 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 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 on 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 these expenditures from customers.
West Virginia
Rates. Rates in West Virginia are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
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 facility, 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. An evidentiary hearing on this matter is scheduled to begin on April 5, 2010.
Annual Adjustment of Fuel and Purchased Power Cost Rates. 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. This amount, as well as interest on the deferral, will be included in the company’s third-quarter 2010 fuel and purchased power filing for recovery in 2011. The West Virginia PSC approved the Joint Stipulation on December 29, 2009.
Maryland
Rates. In 1999, Maryland adopted electric industry restructuring legislation, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation supplier. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply but remained obligated to provide standard offer generation service, or “SOS,” at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. As discussed below, Potomac
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Edison has implemented a rate stabilization plan to transition customers from capped generation rates to rates based on market prices. T&D rates for all customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
Rate Stabilization Plan. In December 2006, Potomac Edison proposed a rate stabilization and market transition plan (the “Transition Plan”) for its Maryland residential customers, in accordance with a bill passed by the Maryland legislature in 2006. The Maryland Public Service Commission (the “Maryland PSC”) approved the Transition Plan on March 30, 2007. The Transition Plan provides for a gradual transition of Potomac Edison’s residential customers from capped generation rates to market-based generation rates, while at the same time preserving for customers the benefit of rate caps.
Under the Transition Plan, Potomac Edison’s customers who did not opt out of the Transition Plan began paying a non-bypassable surcharge (the “Rate Stabilization Surcharge”) in June 2007, which resulted in an overall rate increase of approximately 15%, after taking into account the expiration of a prior customer choice rate credit with the initiation of the new surcharge. On January 1, 2008, the surcharge increased residential rates an additional 15%.
Beginning January 1, 2009, coincident with the expiration of the residential generation rate cap and implementation of market-based generation pricing, the Rate Stabilization Surcharge converted from a charge to a credit on customers’ bills. Funds collected through the Rate Stabilization Surcharge during 2007 and 2008, plus interest, are being returned to customers as a credit on their electric bills, thereby reducing the impact of the rate cap expiration. The credit will continue, with adjustments, to maintain rate stability until approximately December 31, 2010.
The Rate Stabilization Surcharge was recorded as a regulatory liability as it was billed to customers. In addition, interest on amounts collected from customers is recognized as a component of the regulatory liability for future refund to customers. This interest is recorded as interest expense on the Consolidated Statements of Income. As amounts are returned to customers, these customer credits are being charged directly to the regulatory liability.
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 electric usage in Maryland be reduced by 15% by 2015. 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 are expected to be recovered over the next five to ten years, pending Maryland PSC approval. Meanwhile, the AUI pilot is being examined on a separate track and is currently under discussion with the Staff of the Maryland PSC.
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Virginia
Rates. 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 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
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SCC held a hearing on the settlement on November 18, 2008 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.
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.
NOTE 5: TRANSMISSION EXPANSION
Trans-Allegheny Interstate Line
In June 2006, the board of directors of PJM approved a new transmission line extending from southwestern Pennsylvania through West Virginia into northern Virginia, and designated Allegheny to build the Allegheny Power Zone (the “AP Zone”) portion of the line. PJM, which is a regional transmission operator, is responsible for the operation of, and reliability planning for, the transmission network in the PJM region and included the new line in its 2006 regional transmission expansion plan. In October 2006, Allegheny formed TrAIL Company as the entity responsible for financing, constructing, owning, operating and maintaining the new line, which is named the Trans-Allegheny Interstate Line, or “TrAIL.” TrAIL is a 500 kV high voltage line that currently is to extend from southwestern Pennsylvania through West Virginia to a point of interconnection with Virginia Electric and Power Company (“Dominion”) in northern Virginia. In addition, TrAIL Company and Dominion will jointly own an approximately 30-mile 500 kV line segment that Dominion will construct in Virginia. In addition to the TrAIL Line, other TrAIL Company projects include a new static volt-ampere reactive power compensator at the Black Oak substation, upgrades and/or replacements of transformers and/or buses at six other substations and the construction of a new transmission operations center to be located in West Virginia.
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Potomac-Appalachian Transmission Highline
In June 2007, the board of PJM directed the construction of PATH, a high-voltage transmission line project. In September 2007, Allegheny and AEP formed PATH, LLC to construct and operate PATH. PATH, LLC is a series limited liability company. The “West Virginia Series” (PATH-WV) is owned equally by Allegheny and a subsidiary of AEP. The “Allegheny Series” (PATH-Allegheny) is 100% owned by Allegheny. PATH will consist of a single 765 kV line from the AEP substation near St. Albans, West Virginia to a new substation near Kemptown, Maryland and include a new midpoint substation in West Virginia in the vicinity of eastern Grant County, northern Hardy County, or southern Hampshire County.
PJM has confirmed that the reconfigured project addresses its reliability concerns, however in December 2009 PJM suggested that the project does not need to be in service in 2014 to resolve reliability problems on the electric grid, as previously expected. This data from PJM is preliminary and not sufficient to identify a specific in-service date for the project. PJM is in the process of preparing its comprehensive 2010 Regional Transmission Expansion Plan, which will identify an in-service date for PATH.
The accounts of PATH, LLC and its operating subsidiaries are included in Allegheny’s Consolidated Financial Statements. See Note 23, “Variable Interest Entities,” for additional information.
Federal Regulation and Rate Matters
TrAIL Project. TrAIL Company earns its revenues through a FERC approved formula rate mechanism that provides for recovery of expenses and a return on investment. TrAIL Company’s formula tariff rate, which includes, among other things, an incentive return on equity for TrAIL and a static volt-ampere reactive power compensator at the Black Oak substation (the “Black Oak SVC”) is 12.7 percent and a return on equity is 11.7 percent for non-incentive projects.
PATH Project. PATH, LLC earns its revenues through a FERC approved formula rate mechanism that provides for recovery of expenses and a return on investment. PATH, LLC’s formula tariff rate includes, among other things, an incentive return on equity of 14.3 percent.
FERC set for hearing the cost of service formula rate granted in the February 29, 2008 order that are being used to calculate the annual revenue requirements for the project. 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 a return on equity remains pending before the FERC.
State Regulation Matters
Pennsylvania
By order entered on December 12, 2008, the Pennsylvania PUC authorized TrAIL Company to construct a 1.2 mile portion of the TrAIL Project in Pennsylvania from the proposed 502 Junction Substation in Greene County to the Pennsylvania-West Virginia state line. This portion of TrAIL will connect with portions of the TrAIL Project approved in West Virginia and Virginia. In the same order, the Pennsylvania PUC also approved an agreement entered into 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. In addition, West Penn agreed to release certain easements that would have been used by TrAIL Company for the Prexy Facilities, and Greene County agreed that the Pennsylvania PUC should authorize construction of the 1.2 mile portion of TrAIL from 502 Junction Substation to the Pennsylvania-West Virginia state line. An intervenor has initiated judicial review of the order by the
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Commonwealth Court of Pennsylvania. 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.
West Virginia
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. The procedural schedule established by the West Virginia PSC provides for an evidentiary hearing in this case in February 2010 and a final commission decision by June 21, 2010. 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 is 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 Regional Transmission Expansion Plan analysis.
Maryland
On May 19, 2009, Potomac Edison on behalf of PATH-Allegheny filed an application with the Maryland PSC for a certificate of public convenience and necessity to construct portions of the PATH Project in Maryland. The Maryland PSC requested briefs on certain preliminary legal issues and heard oral argument on the issues. On September 9, 2009, the Maryland PSC issued an order determining that Potomac Edison could not file an application for a certificate of public convenience and necessity on behalf of PATH-Allegheny but could file such an application on behalf of itself and directed Potomac Edison to advise the Maryland PSC of its decision to file such an application within 30 days. On October 9, 2009, Potomac Edison advised the Maryland PSC that it continued to consider its filing options, including whether to re-file an application with the Maryland PSC, and intended to inform the Maryland PSC of its decision as soon as possible. On December 21, 2009 the Potomac Edison Company, an Allegheny affiliate, submitted a new application to the Maryland Public Service Commission requesting authorization to construct the Maryland segment of the PATH Project. Potomac Edison has also agreed not to file an application with FERC pursuant to Section 216(b)(1) with the FPA prior to June 29, 2011 to construct the PATH Project in Maryland.
Virginia
On October 7, 2008, the Virginia SCC issued an order authorizing construction of the TrAIL project in Virginia, and on November 5, 2009, the Virginia Supreme Court affirmed the Virginia SCC’s order.
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
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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.
NOTE 6: REGULATORY ASSETS AND LIABILITIES
Allegheny’s regulated utility operations are subject to regulated industry specific accounting provisions. Regulatory assets represent probable future revenues associated with incurred costs that are expected to be recovered in the future from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited or refunded to customers through the rate-making process or amounts collected for costs not yet incurred. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets were as follows:
(a) Does not earn a return.
(b) Amount is being recovered over various periods associated with the remaining useful life of related regulated utility property, plant and equipment.
(c) See Note 11, “Pension Benefits and Postretirement Benefits Other Than Pensions.”
(d) Recorded amount includes an 11% return on amounts deferred that was earned through 2005. No additional return will be earned through the 2010 recovery period.
(e) Amount is being recovered over various periods through 2025, based upon the maturities of reacquired debt.
(f) Includes amounts that do not earn a return on amounts deferred with recovery periods up to two years.
(g) Includes amounts that do not earn a return on amounts deferred with various recovery periods through 2027.
(h) Net asset removal costs of $51.0 million are included in liabilities associated with assets held for sale at December 31, 2009 in the consolidated balance sheet.
(i) Amount earns interest at the approved FERC interest rate and will be recovered through 2011.
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See Note 4, “Rates and Regulation,” for additional information regarding regulatory developments impacting regulatory assets and liabilities, Note 11, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for a discussion of regulatory assets relating to pension and other postretirement benefits, and Note 13, “Fair Value Measurements, Derivative Instruments and Hedging Activities” for information relating to regulatory assets relating to unrealized gains and losses on FTRs. Other regulatory assets and liabilities reflected in the table above relate to the following:
Income Taxes, Net
In certain jurisdictions, deferred income tax expense is not permitted as a current cost in the determination of rates charged to customers. In certain of these jurisdictions a deferred income tax liability, or asset as appropriate, is recorded with an offsetting regulatory asset or liability. These deferred income taxes primarily relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. In addition, deferred income tax assets are recorded with offsetting regulatory liabilities related to deferred investment tax credits. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. The income tax regulatory liability represents amounts that will be returned to customers as the investment tax credits are amortized against taxes paid.
Pension and Other Postretirement Benefits
Allegheny recognizes the underfunded status of its defined benefit postretirement plans as a liability on its consolidated balance sheet and recognizes changes in the funded status in other comprehensive income. However, to the extent that the funded status relates to Allegheny’s rate-regulated subsidiaries and such amounts will be recovered through the rate-making process, the funded status and changes in funded status are recognized as a regulatory asset rather than as a charge to other comprehensive income.
Pennsylvania Stranded Cost Recovery and CTC Reconciliation
Pennsylvania’s Electricity Generation Customer Choice and Competition Act (the “Customer Choice Act”) gave all retail electricity customers in Pennsylvania the right to choose their electricity generation supplier beginning January 2, 2000. Under terms of a customer choice implementation agreement between the Pennsylvania PUC and West Penn, beginning in 1998 and through June 2008, West Penn was authorized to recover $670 million of Competitive Transition Charges (“CTC”) incurred as part of the transition to customer choice. West Penn’s customer bills included a CTC charge, and West Penn recognized revenue related to CTC charges through the end of the recovery period in June 2008. For 2008 and 2007, West Penn recorded pre-tax income of approximately $21 million and $52 million respectively, related to CTC.
Any difference between CTC charges recognized and the amount collected from customers was recorded as a regulatory asset for future collection. In 2005, the Pennsylvania PUC authorized West Penn to securitize and collect $115 million previously deferred as the difference between authorized and billed stranded cost recovery revenues, with an 11% return on the amounts deferred. This difference represents a separate regulatory asset (“Pennsylvania CTC Reconciliation”). Collection of these amounts from customers is occurring over an extended transition period through 2010. Recovery of the Pennsylvania CTC Reconciliation regulatory asset began after the Pennsylvania stranded cost regulatory asset was fully recovered. The amount of under-recovery of CTC during the transition period, if any, will be determined at the end of the transition period in 2010.
Expanded Net Energy Cost
In May 2007, the West Virginia PSC issued a rate order that re-established an annual ENEC method of recovering net power supply costs, including fuel costs, purchased power costs, including purchased power costs associated with the Grant Town PURPA Generation Facility and other related expenses, net of related revenue
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and interest earnings on the Fort Martin Scrubber project escrow fund. Under the ENEC, actual costs and revenues are tracked for under and/or over recoveries, and revised ENEC rate filings are made on an annual basis. Any under and/or over recovery of costs, net of related revenues, is deferred, for subsequent recovery or refund, as a regulatory asset or regulatory liability, with the corresponding impact on the Consolidated Statements of Income reflected within “Deferred energy costs, net.” See Note 4, “Rates and Regulation” for additional information.
Asset Removal Costs
In certain jurisdictions, depreciation rates include a factor representing the estimated costs associated with removing an asset from service upon retirement. The accrual accumulates during the asset’s service life and is reduced when the actual cost of removal is incurred. The accumulated balance of such removal costs represents a regulatory liability. In other jurisdictions, retirement costs are collected in rates only after they are incurred, in which case the costs are recorded as a regulatory asset. See Note 19, “Asset Retirement Obligations (“ARO”), for a description of asset retirement obligations.
Maryland Rate Stabilization and Transition Plan Surcharge
From March 2007 through December 2008, Potomac Edison collected a rate stabilization surcharge from its Maryland residential customers. The amounts collected through the surcharge and interest, which is recorded as a regulatory liability, will be returned to the Maryland residential customers in the form of a credit from January 2009 through December 2010. The credit reduces the impact of the rate cap expiration on the Maryland residential customers.
Transmission Revenue Requirement
Under a formula rate mechanism approved by FERC, TrAIL Company and PATH, LLC make annual filings in order to recover incurred costs and an allowed return. An initial rate filing is made for each calendar year using estimated costs, which is used to determine the billings to customers. All prudently incurred allowable costs and return earned during each calendar year are eventually recovered on a dollar-for-dollar basis through a true-up mechanism. As such, TrAIL Company and PATH, LLC recognize revenue as they incur recoverable costs and earn the allowed return on a monthly basis. Any differences between revenues earned based on actual costs and the amounts billed based on estimated costs are included in a regulatory asset or liability and will be recovered or refunded, respectively, in subsequent periods.
NOTE 7: INCOME TAXES
Components of federal and state income tax expense were as follows:
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On March 31, 2008, the state of West Virginia enacted a change in its income tax law that implemented combined reporting and a reduction in its income tax rate that phases in from 2009 through 2014. During 2008, Allegheny recognized a benefit of approximately $6.8 million, net of federal income tax, representing an adjustment of its deferred tax assets and liabilities to reflect the effects of this rate reduction.
The Commonwealth of Pennsylvania limited the amount of net operating loss carryforwards that may be used to reduce current year taxable income to the greater of $3 million or 12.5% of apportioned Pennsylvania taxable income per year through 2008. During 2008, an additional benefit of $3.9 million, net of applicable federal income tax, was recorded to adjust the recorded Pennsylvania net operating loss carryforward asset to reflect estimates of future Pennsylvania taxable income during the carryforward period.
On October 9, 2009, Pennsylvania enacted H.B. 1531, which modified the corporate net operating loss utilization rules and made minor modifications to apportionment provisions. Under H.B. 1531, the annual net operating loss carryforward limitation was increased to 15% of taxable income for 2010 and 20% thereafter. During 2009, an additional benefit of $11.0 million, net of applicable federal income tax, was recorded to reflect estimates of future Pennsylvania taxable income during the carryforward period and to adjust the Pennsylvania net operating loss carryforward asset to reflect estimated benefits resulting from the increased utilization caps under H.B. 1531.
The following table reconciles income tax expense calculated by applying the federal statutory income tax rate of 35% to “income before income taxes” to “income tax expense”:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
At December 31, deferred income tax assets and liabilities consisted of the following:
Allegheny has recorded as deferred income tax assets the effect of net operating losses and tax credits which will more likely than not be realized through future operations and through the reversal of existing temporary differences. The tax effected net operating loss carryforwards consisted of $150.2 million of state net operating loss carryforwards that expire from 2019 through 2029 and $72.3 million of federal net operating loss carryforwards that expire from 2023 to 2029. Federal Alternative Minimum Tax credits of $20.2 million have an indefinite carryforward period.
Allegheny’s valuation allowance on deferred tax assets was reduced in 2009 primarily because of a change in Pennsylvania tax law with respect to net operating loss carryforwards enacted in the fourth quarter of 2009. This benefit was partially offset by a reduction in the expected realization of carryforward amounts due to forecasted taxable income.
Allegheny adopted the provisions of FIN 48 (ASC Topic 740) on January 1, 2007, which prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on an income tax return. As a result of the implementation, Allegheny recognized a $17.7 million reduction to its January 1, 2007 balance of retained earnings.
Allegheny records interest and penalties associated with uncertain tax positions as a component of income tax expense. Allegheny recognized interest expense related to uncertain tax positions, net of tax, of approximately $1.0 million, $1.8 million and $0.2 million during 2009, 2008 and 2007, respectively. Accrued interest, net of tax, related to uncertain tax positions was $5.4 million and $4.5 million at December 31, 2009 and December 31, 2008, respectively. The reduction in actual interest in 2009 compared to 2008 is due primarily to resolution of federal income tax audit issues for the years 1998 to 2003.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Allegheny’s uncertain tax position reserves were $89.5 million and $79.5 million at December 31, 2009 and 2008, respectively ($59.8 million and $53.0 million, net of the federal tax benefit for state tax reserves). At December 31, 2009, approximately $85.7 million of the reserve is not expected to be resolved in the next 12 months and, therefore, has been classified as long term income taxes payable on the accompanying Consolidated Balance Sheet.
The following represents an analysis of the changes in unrecognized tax benefits during 2009, 2008 and 2007, excluding accrued interest:
If recognized, the portion of the unrecognized tax benefits that would reduce Allegheny’s effective tax rate was $54.3 million and $48.7 million at December 31, 2009 and December 31, 2008, respectively ($84.1 million and $75.2 million, respectively, before the federal income tax effects on state income tax positions).
The unrecognized tax benefit balance also included approximately $42.4 million and $37.5 million of tax positions at December 31, 2009 and December 31, 2008, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would impact the timing of cash payments to the taxing authorities.
The major jurisdictions in which Allegheny is subject to income tax are U.S. Federal, Pennsylvania, West Virginia, Maryland and Virginia. Allegheny files consolidated federal income tax returns, and those returns are currently under audit by the Internal Revenue Service (“IRS”) for the tax years 2004 through 2006. The 2007 and 2008 federal returns have been filed and are subject to review. Several of Allegheny’s subsidiaries file returns in Pennsylvania. Returns filed with the Pennsylvania Department of Revenue for the tax years 2004 through 2008 are subject to review. Allegheny also files a consolidated West Virginia return. The consolidated West Virginia return has been audited through 2004. The 2005 through 2008 returns remain subject to review. Several of Allegheny’s subsidiaries are also subject to tax in the state of Maryland. The Maryland returns for the tax years 2005 through 2008 remain subject to review. Additionally, certain Allegheny subsidiaries are subject to tax in Virginia. The Virginia returns for tax years 2005 through 2008 remain subject to review.
The IRS audits of Allegheny’s income tax returns for the tax years 1998 through 2003 have been completed. During 2008, Allegheny reached a settlement with the IRS on substantially all issues and recorded a benefit due to reduced interest charges of $6.1 million. The Joint Committee on Taxation reviewed these audits. During that review the Joint Committee made certain inquiries regarding a settlement that Allegheny had reached with the Appeals Division in 2006 relating to contributions to capital. Allegheny resolved this issue with the IRS and the Joint Committee during the fourth quarter of 2008. The net charge to earnings during the fourth quarter of 2008 was $1.4 million. Additionally, Allegheny has liabilities for uncertain positions taken on various state income tax returns that it files. The statute of limitations for some of these returns expired during 2009 and 2008 and resulted in a benefit of approximately $2.2 million and $1.3 million, respectively. During 2010, additional state statute of limitations will expire that will result in a net benefit of approximately $3.8 million.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 8: CAPITALIZATION AND DEBT
Common Stock
During 2009, 2008 and 2007, Allegheny paid the following dividends on its common stock:
AE issued 0.2 million, 2.1 million and 1.9 million shares of common stock in 2009, 2008 and 2007, respectively, primarily in connection with stock option exercises and the settlement of stock units.
Preferred Stock of Subsidiary
On September 4, 2007, Monongahela redeemed its 4.40% Cumulative Preferred Stock, $100 par value, its 4.80% Cumulative Preferred Stock, Series B, $100 par value, its 4.50% Cumulative Preferred Stock, Series C, $100 par value and its $6.28 Cumulative Preferred Stock, Series D, $100 par value with an aggregate carrying value of $24.0 million. In connection with the cash redemption, Monongahela paid accrued dividends at the redemption date plus a redemption premium of approximately $1.1 million that was charged against other paid-in capital. This premium also reduced earnings per common share as shown in Note 9, “Earnings per Share.”
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Debt
Allegheny’s long-term debt was as follows:
(a) Represents debt under AE Supply’s previous credit facility, which was replaced with a new credit facility in September 2009
(b) Variable rate debt
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Outstanding debt and scheduled debt repayments at December 31, 2009 were as follows:
(a) Amounts represent repayments based upon estimated surcharge collections from customers.
(b) Amounts represent the elimination of certain pollution control bonds, for which Monongahela and AE Supply are co-obligors.
Certain of Allegheny’s properties are subject to liens of various relative priorities securing debt.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Credit Facilities
In addition to the debt described above, AE, AE Supply and Monongahela each had a revolving credit facility. AE’s credit facility matures in 2011 and AE Supply’s and Monongahela’s credit facilities mature in 2012. At December 31, 2009, borrowing capacity under these credit facilities was as follows:
In addition, at December 31, 2009, TrAIL Company had borrowings under its $550 senior unsecured credit facility in the amount of $455 million. All amounts outstanding under the senior unsecured credit facility were repaid in January 2010, with proceeds from TrAIL Company’s January 25, 2010 issuance of unsecured notes and a new $350 million senior unsecured revolving credit facility.
Under terms of their individual credit facilities, outstanding debt of AE Supply and Monongahela may not exceed 65% of the sum of their debt and equity as of the last day of each calendar quarter. These provisions limit the net assets of AE Supply and Monongahela that may be transferred to AE.
2009 Debt Activity
Borrowings and principal repayments on debt during 2009 were as follows:
(a) Represents debt activity under AE Supply’s previous credit facility, which was replaced with a new credit facility in September 2009.
On July 6, 2009, the Pennsylvania Economic Development Financing Authority issued $235 million of 7.0% tax-exempt bonds that mature in 2039 and loaned the proceeds from that issuance to AE Supply to finance a portion of the cost of constructing and installing Scrubbers at its Hatfield’s Ferry generation facility. AE Supply capitalized $2.4 million in debt issuance costs associated with this transaction.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
On September 4, 2009, AE Supply repurchased $97.5 million and $146.8 million, respectively, of its 7.80% Notes due 2011 and its 8.25% Notes due 2012 pursuant to a cash tender offer, at an aggregate premium of $18.1 million. AE Supply expensed the $18.1 million premium, $0.7 million in unamortized debt costs, and $0.6 million in fees associated with the tender offer.
On September 24, 2009, AE Supply entered into a new $1 billion senior unsecured revolving credit facility with a three-year maturity. The new revolving credit facility replaced AE Supply’s previous $400 million revolving credit facility, which was scheduled to mature in May 2011. Loans under the new facility bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on AE Supply’s senior unsecured credit rating. AE Supply capitalized $22.3 million in debt costs related to this facility.
On October 1, 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. AE Supply used a portion of the net proceeds from the sale of these notes to repay in full its existing $447 million term loan on October 2, 2009. AE Supply capitalized $5.3 million in debt issuance costs associated with this new debt issuance and expensed $0.6 million of unamortized debt costs associated with the extinguished term loan.
On October 21, 2009, AE Supply used the remaining proceeds of its senior unsecured note offering to repurchase approximately $152 million aggregate principal amount of its 7.80% Medium Term Notes due 2011 pursuant to a cash tender offer at an aggregate premium of $12.7 million. AE Supply expensed the $12.7 million premium, $0.3 million in unamortized debt costs, and $0.4 million in fees related to this tender offer.
On December 18, 2009, Monongahela entered into a new $110 million senior unsecured revolving credit facility with a three-year maturity. Loans under the new facility generally bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on Monongahela’s senior unsecured credit rating. Monongahela capitalized approximately $1.4 million in debt costs related to this facility.
On December 23, 2009, MP Environmental Funding LLC, an indirect subsidiary of Monongahela, and PE Environmental Funding LLC, an indirect subsidiary of Potomac Edison, issued $64.4 million and $21.5 million, respectively, of Senior Secured Ratepayer Obligation Charge Environmental Control Bonds, Series B. These bonds securitize the right to collect an environmental control surcharge that Monongahela and Potomac Edison impose on their retail customers in West Virginia. The bonds were issued with an interest rate of 5.1% and mature in January 2031. Net proceeds from the sale of the bonds are restricted funds and are being used to fund certain costs incurred in connection with the construction and installation of the Scrubbers at Fort Martin. Monongahela and Potomac Edison capitalized $1.9 million and $0.7 million, respectively, in debt issuance costs associated with this transaction.
On January 15, 2010, Monongahela repaid all $110 million of its Medium-Term Notes on their due date.
On January 25, 2010, TrAIL Company issued $450 million aggregate principal amount of 4.0% senior unsecured notes due in 2015 and also entered into a new $350 million senior unsecured revolving credit facility with a three-year maturity. Borrowings under the new facility will bear interest that is calculated based on the London Interbank Offered Rate, plus a margin based on TrAIL Company’s senior unsecured credit rating. 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 had entered into in 2008.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
2008 Debt Activity
Issuances of indebtedness and repayments of principal on indebtedness, during 2008 were as follows:
(a) The issuance amounts represent interest that was accrued and added to the principal amount of certain bonds.
(b) Represents debt activity under AE Supply’s previous credit facility, which was replaced with a new credit facility during September 2009.
On August 15, 2008, TrAIL Company entered into a $550 million senior secured credit facility with a seven-year maturity. The facility included a $530 million construction loan and a $20 million revolving facility, both with an initial borrowing rate equal to the London Interbank Offered Rate plus 1.875 percent.
On December 15, 2008, Monongahela issued $300 million aggregate principal amount of 7.95% First Mortgage Bonds that mature in 2013. Proceeds from the First Mortgage Bonds were used to repay short-term intercompany debt, to finance certain capital expenditures, including a portion of the costs to install Scrubbers at Fort Martin, and for working capital needs and other general corporate purposes.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 9: EARNINGS PER SHARE
The reconciliation of the basic and diluted earnings per common share calculation was as follows:
(a) See Note 8, “Capitalization and Debt,” for information related to Monongahela’s redemption of preferred stock.
(b) The dilutive share calculations for 2009, 2008 and 2007 exclude 1,808,960 shares, 576,101 shares and 48,578 shares, respectively, under outstanding stock options because the inclusion of these stock options would have been antidilutive under the treasury stock method.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 10: STOCK-BASED COMPENSATION
On May 15, 2008, AE’s stockholders approved the Allegheny Energy, Inc. 2008 Long-Term Incentive Plan (the “2008 LTIP”). The 2008 LTIP authorized the grant of equity-based compensation to AE’s directors and to its executives and other key employees in the form of performance awards, stock options and stock appreciation rights, restricted shares, and restricted stock units.
Allegheny records compensation expense for share-based payments to employees and non-employee directors, including grants of employee stock options, performance shares, restricted shares and stock units, over the requisite service period based on their estimated fair value on the date of grant.
The following table summarizes stock-based compensation expense included in operations and maintenance expense during 2009, 2008 and 2007:
Stock-based compensation expense recognized in the Consolidated Statements of Income is based on awards ultimately expected to vest, using an estimated annual forfeiture rate of 5%. No stock-based compensation cost was capitalized in 2009, 2008 or 2007.
Stock Options
The exercise price, terms and other conditions applicable to stock option awards are generally determined by the Management Compensation and Development Committee of AE’s Board or the independent directors of the Board. The exercise price per share for each award is equal to or greater than the fair market value of a share of AE’s common stock on the grant date. Stock options vest in annual tranches on a pro-rata basis over the vesting period, which is typically two to five years, and become fully vested and exercisable upon a change in control. Stock options typically expire after 10 years. Stock option awards are expensed using the straight-line attribution method over the requisite service period of the last separately vesting tranche of the award.
Allegheny records compensation expense for employee stock options based on the estimated fair value of the options on the date of grant under the Black-Scholes option-pricing model using the following weighted-average assumptions for stock options granted in 2009, 2008 and 2007:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The annual risk-free interest rate is based on the United States Treasury yield curve at the date of the grant for a period equal to the expected term of the options granted. The expected term of the 2009, 2008 and 2007 stock option grants was calculated in accordance with Staff Accounting Bulletin 107, using the “simplified” method. AE continues to use the simplified method for its calculation of expected term due to its lack of sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term and because AE has granted stock options in prior years with varying vesting terms, which also makes it difficult to evaluate historical exercise data. The expected annual dividend yield assumption was based on AE’s current dividend rate at the time of each grant. For stock options granted in 2009, 2008 and 2007, the expected stock price volatility was based on both historical stock volatility and the volatility levels implied on the grant date by actively traded option contracts on AE’s common stock.
Stock option activity was as follows:
The grant-date fair value of stock options granted, the total pre-tax intrinsic value of stock options exercised and exercisable, and the cash received by AE from stock option exercises in 2009, 2008 and 2007 are shown in the table below:
(a) Represents the total pre-tax intrinsic value based on the difference between the market value of AE’s common stock at exercise and the exercise price of the options.
(b) Represents the total pre-tax intrinsic value based on the difference between the exercise price of stock options exercisable (with an exercise price lower than AE’s closing stock price) and AE’s closing stock price of $23.48, $33.86, and $63.61, on December 31, 2009, 2008, and 2007, respectively.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Allegheny issued new shares of its common stock to satisfy these stock option exercises. No cash tax benefit was realized from tax deductions on stock options exercised during 2009, 2008 and 2007 because of existing net operating loss carryforwards.
The following table summarizes information about stock options outstanding and stock options exercisable at December 31, 2009:
(a) Represents the total pre-tax intrinsic value based on stock options with an exercise price less than AE’s closing stock price of $23.48 as of December 31, 2009.
As of December 31, 2009, Allegheny had approximately $7.8 million of unrecognized compensation cost related to non-vested outstanding stock options, which is expected to be recognized over a weighted-average period of approximately 1.4 years.
Allegheny records excess tax benefits associated with share-based awards directly to equity only when realized. Accordingly, deferred tax assets have not been recognized for net operating loss carryforwards resulting from excess tax benefits subsequent to January 1, 2006. The unrecorded excess tax benefits from share-based awards were $66.0 million and $65.2 million at December 31, 2009 and 2008, respectively.
Performance Shares
AE has granted equity-based performance shares to key employees pursuant to which award recipients may earn shares of AE common stock based on AE’s Total Shareholder Return (“TSR”) and AE’s performance with respect to its Annual Incentive Plan (“AIP”) goals. Performance shares vest at the end of the three-year performance period and become fully vested and payable upon a change in control.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
For performance shares linked to TSR, the TSR of AE’s common stock is compared to the TSR of the companies in the Dow Jones U.S. Electric Utilities Index over a three-year performance period. Based upon AE’s percentile rank within the peer group, shares earned can range from 0% to 250% of each participant’s target award. The grant date fair value will be recognized as compensation expense over the requisite service period on a straight-line basis for awards ultimately expected to vest, using an estimated annual forfeiture rate of 5%. Activity in target performance shares linked to TSR was as follows:
The grant date fair value of performance shares linked to TSR granted during the twelve months ended December 31, 2009 was $4.6 million. The fair value was determined using a Monte Carlo simulation model, utilizing actual TSR information for the common shares of AE and its peers for the period from January 1, 2009 to the February 27, 2009 grant date and estimated future stock volatility and dividends of AE and its peers. The expected stock volatility assumptions for AE and its peer group was based on three-year historic stock volatility, and the annual dividend yield assumptions were based on current dividend yields at the grant date.
As of December 31, 2009, there was approximately $3.2 million of unrecognized compensation cost related to non-vested outstanding performance shares linked to TSR, which is expected to be recognized over a weighted average period of approximately one and a half years.
For performance shares linked to AE’s AIP goals, the number of AE common shares to be earned and distributed is based on AE’s performance compared to annual performance targets for a three-year period. The annual performance targets are established at the beginning of each individual year. Compensation expense is recognized over the remaining portion of the three-year performance period as if the awards were separate annual awards, using an estimated annual forfeiture rate of 5%. The percentage of target shares earned can range from 0% to 200%. Activity in target performance shares linked to the AIP was as follows:
As of December 31, 2009, there was approximately $1.8 million of unrecognized compensation cost related to non-vested outstanding performance shares linked to the AIP relating to performance goals, which is expected to be recognized over a weighted average period of approximately one year.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Stock Units
Allegheny’s Stock Unit Plan permitted the grant to Allegheny’s key executives, at the time of hire, of stock units representing up to 4.5 million shares of AE’s common stock. Upon vesting, an executive may convert each stock unit into one share of AE common stock. These stock units vest in annual tranches on a pro-rata basis over the vesting period, which is typically three to five years, and become fully vested upon a change in control. Stock unit awards granted prior to January 1, 2006 are expensed using the graded-vesting method. The fair value of each stock unit is equivalent to the market price of Allegheny’s stock on the date of grant. No stock units were granted since 2005.
Stock unit activity for the last three years was as follows:
(a) Represents the total pre-tax intrinsic value based on stock units outstanding multiplied by AE’s closing stock price on each respective date.
The total pre-tax intrinsic value of stock units converted to shares of AE common stock during 2009, 2008 and 2007 was $0.1 million, $23.1 million and $29.7 million, respectively. Allegheny issued new shares of its common stock in connection with the stock unit conversions. The actual number of common shares issued upon conversion of stock units was net of shares withheld to meet minimum income tax withholding requirements.
Non-Employee Director Shares
Under the Non-Employee Director Stock Plan, during 2009, 2008 and 2007 each non-employee member of AE’s Board of Directors received, on a quarterly basis, subject to his or her election to defer his or her receipt, shares of AE common stock with a value equivalent to the lesser of 1,000 shares or $30,000 of AE common stock as determined based on the closing price of AE common stock on the last business day of each calendar quarter for services performed. A maximum of 300,000 shares of AE’s common stock, subject to adjustments for stock splits, combinations, recapitalizations, stock dividends or similar changes in stock, may be issued under this plan. The 2009, 2008 and 2007 compensation of each non-employee director was 4,000 shares, 2,895 shares and 2,303 shares, respectively, of AE’s common stock. The amount of expense relating to this plan for 2009, 2008 and 2007 was $0.9 million, $1.1 million and $1.0 million, respectively, representing the closing price of AE’s common stock on the date of grant multiplied by the number of shares granted.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Non-employee director share activity in the last three years was as follows:
Restricted Shares
In the first quarter of 2009, AE granted 17,850 restricted shares with an aggregate fair value of $0.4 million and a three year vesting period.
As of December 31, 2009, Allegheny had approximately $0.3 million of unrecognized compensation cost related to non-vested restricted shares, which is expected to be recognized over a weighted average period of approximately 2 years.
Change in Control
As described above, stock options and other stock-based awards become fully vested and exercisable upon a change in control. Approval by Allegheny’s stockholders of Allegheny’s proposed merger with FirstEnergy Corp. (“FirstEnergy”) would constitute a change in control under the relevant stock-based compensation plan provisions. See also Note 27 “Subsequent Event - Merger Agreement.”
NOTE 11: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Substantially all of Allegheny’s personnel, including officers, are employed by AESC and are covered by a noncontributory, defined benefit pension plan. Allegheny also maintains a Supplemental Executive Retirement Plan (the “SERP”) for executive officers and other senior executives.
Allegheny also provides subsidies for medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the postretirement benefits other than pensions, have
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
retiree premiums based upon an age and years-of-service vesting schedule, include other plan provisions that limit future benefits and take into account certain collective bargaining arrangements. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006. The provisions of the postretirement health care plans and certain collective bargaining arrangements limit Allegheny’s costs for eligible retirees and dependents.
The components of the net periodic cost for pension benefits and for postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents by Allegheny were as follows:
For the years ended December 31, 2009, 2008 and 2007, Allegheny capitalized $17.7 million, $13.2 million and $14.1 million, respectively, of the above net periodic cost amounts to “Construction work in progress,” a component of “Property, plant and equipment, net.”
In 2008, as required by GAAP, AE changed to a December 31 measurement date for its pension plans, postretirement benefits other than pension plans and long-term disability plan. Accordingly, AE performed a measurement of plan assets and liabilities as of December 31, 2008. AE’s prior measurement date for these plans was September 30, 2007. Twelve fifteenths of net periodic cost for the fifteen month period from September 30, 2007 to December 31, 2008 was recorded as current year benefit costs and three fifteenths of the total cost was charged to retained earnings as of December 31, 2008, net of tax. The adjustment to retained earnings in the amount of $6.8 million was comprised of $6.0 million of pension benefit costs less income tax effect of $2.4 million and $5.4 million of other benefit plan costs less income tax effect of $2.2 million.
Allegheny uses the market-related value of pension assets to determine the expected return on pension plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight line basis over a five-year period. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Allegheny uses the fair value of assets to determine the expected return on postretirement benefits other than pension assets.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The amounts in accumulated other comprehensive loss, pre-tax, and regulatory assets that are expected to be recognized as components of net periodic cost during the next fiscal year are as follows:
The amounts accrued at December 31, using a measurement date of December 31, included the following components:
The SERP is a non-qualified pension plan, and Allegheny is therefore not obligated to fund the SERP obligation. The SERP obligation, which is included as a component of the pension benefit obligation shown in the table above, was $10.1 million and $8.0 million at December 31, 2009 and 2008, respectively.
Amounts recognized in the Consolidated Balance Sheets at December 31, were as follows:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Amounts recognized in “Accumulated other comprehensive loss,” pre-tax, at December 31, that have not yet been recognized as components of net periodic benefit cost, were as follows:
Allegheny has determined that a portion of the unfunded pension and postretirement benefit obligations represents an incurred cost that qualifies for regulatory asset treatment under GAAP. Because future recovery of these incurred costs are probable for certain of its state and federal jurisdictions, Allegheny has recorded regulatory assets in the amounts of $362.9 million and $332.6 million for pension benefits and $33.6 million and $57.8 million for postretirement benefits other than pensions at December 31, 2009 and 2008, respectively. The 2009 increase in regulatory assets was related to increased unfunded pension obligations.
The accumulated benefit obligation for all defined benefit pension plans was $1.12 billion and $1.04 billion at December 31, 2009 and 2008, respectively. The portion of the total accumulated benefit obligation related to the SERP was $9.0 million and $7.2 million at December 31, 2009 and 2008, respectively.
Information for pension plans with a projected benefit obligation and an accumulated benefit obligation in excess of plan assets was as follows:
The assumptions used to determine net periodic benefit costs for the years ended December 31, 2009, 2008 and 2007 are shown in the table below.
(a) Weighted-average rate for age graded scale.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The assumptions used to determine benefit obligations at December 31, 2009 and 2008 are shown in the table below:
(a) Weighted-average rate for age graded scale.
Allegheny determines its discount rate assumptions through the use of a cash flow matching process in which the timing and amount of estimated benefit cash flows for each benefit plan are matched with an interest rate curve applicable to the returns of high quality corporate bonds over the expected benefit payment period to determine an overall effective discount rate. The interest rate curve used in this process is based primarily on the Citigroup Pension Discount Curve and the Citigroup Above Median Pension Discount Curve.
Allegheny determines its expected long-term rate of return on plan assets assumption based on historical and expected future asset returns for each plan investment category as well as the current and expected future allocation of plan assets by investment category. The expected long-term rate of return on plan assets used to develop net periodic benefit costs for 2010 was 8.0%.
Assumed health care cost trend rates at December 31 were as follows:
For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 8.5% beginning in 2010 and decreasing by 0.5% each year thereafter to an ultimate rate of 5.0% in 2017, and plan provisions that limit future medical and life insurance benefits. Because of the plan provisions that limit future benefits, changes in the assumed health care cost trend rate would have a limited effect on the amounts displayed in the tables above. A one-percentage-point change in the assumed health care cost trend rate would have the following effects:
Under the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”), the federal government provides subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. The subsidy is 28% of eligible drug costs for retirees who are over age 65 and covered under Allegheny’s postretirement benefits other than pension plan.
Allegheny determined that the prescription drug benefit offered under its postretirement benefits other than pension plan is at least actuarially equivalent to Medicare Part D and is expected to continue to be actuarially equivalent through 2011. Allegheny received a total subsidy of approximately $1.5 million for 2009, $1.6 million for 2008 and $1.4 million for 2007.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Plan Assets
The long-term target asset allocation of the defined benefit pension plan is 50% equity securities and 50% fixed income securities. The long-term target for the assets associated with the postretirement benefits other than pension plans vary based on the particular structure of each plan and range from 55% to 75% equity securities and from 25% to 45% fixed income securities. Equity securities primarily include investments in large-cap and mid-cap companies primarily located in the United States (“U.S.”) and in international large-cap companies. Fixed income securities include corporate bonds of companies from diversified industries. Under the plans’ investment policies, the actual allocations may vary from the long-term objective within specified ranges. Market shifts, changes in the plan dynamics or changes in economic conditions may cause the asset mix to fall outside of the long-term policy range in a given period.
The following table disaggregates by level within the fair value hierarchy described in Note 13, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” the fair value of the pension plan’s investments by asset class as of December 31, 2009:
(a) This class seeks to generate a reasonable rate of return by investing in securities that are either issued or guaranteed by the U.S. Treasury and/or U.S. Government Agencies.
(b) This class seeks to match the returns of the S&P 500 Index and the Russell 1000 Index. Approximately 76% of these assets are invested to match the Russell 1000 index and 24% are invested to match the S&P 500 Index.
(c) This class seeks to match the return of the Russell 2000 Index.
(d) This class seeks to match the performance of the Morgan Stanley Capital International EAFE Index while providing low cost, broadly diversified, non-U.S. exposure.
(e) This class seeks to match the return of the Dow Jones U.S. Select REIT Index.
(f) This class seeks to match the return of the High Yield $200 Million Very Liquid Index, a customized Barclays Capital Index.
(g) This class seeks to match the return of the Barclays Capital U.S. Long Government/Credit Bond Index.
(h) An unallocated group annuity contract with Metropolitan Life Insurance Company. Valued at a price per unit that is based upon the underlying value of the domestic fixed income securities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The following table disaggregates by level within the fair value hierarchy the fair value of the postretirement benefits other than pensions plan’s investments by asset class as of December 31, 2009:
(a) This class seeks to generate a reasonable rate of return by investing in high grade money market instruments.
(b) This class seeks to match the return of the S&P 500 Index.
(c) The TOLI is an unallocated insurance contract that is valued based upon the underlying mutual funds and pooled investments and at the value of investments made at a London Interbank Offered Rate (LIBOR), which approximates the policy’s net cash surrender value. The underlying investments are comprised of approximately 60% equities and 40% U.S. fixed income bonds.
(d) This class seeks to match, as closely as possible, the performance of the Barclays Capital U.S. Aggregate Bond Index, by investing primarily in collateralized mortgage obligations, corporate bonds, and U.S. Treasury obligations.
At December 31, 2009 and 2008, a portion of the pension plan’s assets were invested in collective trust funds that participate in a securities lending program. These funds have modified their withdrawal procedures as a result of liquidity issues affecting the funds’ ability to liquidate their securities lending collateral investment pools. At December 31, 2009 and 2008, Allegheny’s pension plan participation in the collateral investment pool was approximately $56 million and $97 million at cost, respectively, with a market value of approximately $55 million and $91 million, respectively. Allegheny does not currently anticipate that its pension plan will experience any significant loss as a result of securities lending by funds in which it participates.
Contributions
Allegheny makes cash contributions to its qualified pension plan to meet the minimum funding requirements of employee benefit and tax laws and may include additional discretionary contributions to increase the funded level of the plan. Allegheny has not yet determined the amount of future contributions, but expects to contribute approximately $80 million to its pension plan for the year 2010. The amount of future contributions to the plan will depend on the funded status of the plan, asset performance and other factors. Allegheny currently anticipates that it will contribute $12 million to $14 million during 2010 to fund postretirement benefits other than pensions.
The Pension Protection Act of 2006 (the “Pension Protection Act”) may affect the manner in which many companies, including Allegheny, administer their pension plans. Effective January 1, 2008, the Pension Protection Act will require many companies to more fully fund their pension plans according to new funding targets, potentially resulting in greater annual contributions. Allegheny is currently assessing the impact that the Pension Protection Act will have on its pension funding in future years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Estimated Future Benefit Payments
The following table shows estimated benefit payments to be made by Allegheny, and the estimated federal subsidy payments to be received by Allegheny:
ESOSP 401(k) Savings Plan
The Allegheny Energy Employee Stock Ownership and Savings Plan (“ESOSP”) was established as a non-contributory stock ownership plan for all eligible employees, effective January 1, 1976, and was amended in 1984 to include a savings program. All of Allegheny’s employees, subject to meeting eligibility requirements, may elect to participate in the ESOSP. Under the ESOSP, each eligible employee may elect to have from 2% to 25% of his or her compensation contributed to the ESOSP on a pre-tax basis. Starting July 1, 2007, participants may elect to make all or a portion of their respective contributions to a Roth 401(k). An additional 1% to 6% of compensation may be contributed on a post-tax basis. Allegheny matches 50% of an employee’s first 6% of pre-tax salary deferrals and Roth 401(k) contributions into the ESOSP. Participants direct the investment of all contributions to specified mutual funds or AE common stock.
In 2009, 2008 and 2007, AE made ESOSP matching contributions in cash in the amount of $9.0 million, $8.6 million and $8.1 million, respectively. These contributions, less amounts capitalized in “Construction work in progress,” were expensed. The capitalized portions of these costs were $2.9 million, $2.5 million and $2.2 million in 2009, 2008 and 2007, respectively.
Disability Benefits
Allegheny provides benefits to eligible employees who are unable to perform their work duties due to an injury or illness. These benefits include income replacement under the Allegheny Energy Long-Term Disability Plan and medical and life insurance benefits under Allegheny’s medical and life insurance plans. The benefits are paid in accordance with Allegheny’s established benefit practices and policies. The liability related to these disability benefits was $8.9 million at December 31, 2009 and 2008.
NOTE 12: SEGMENT INFORMATION
Allegheny changed the composition of its reportable 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 generation operations of AE Supply; and the Delivery and Services segment included the regulated operations of Allegheny’s Distribution Companies (excluding Monongahela’s generation operations), TrAIL Company and PATH, LLC.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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.
Segment information for 2008 and 2007 has been reclassified to conform to the 2009 presentation included below:
(a) Represents elimination of transactions between reportable segments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(a) Represents elimination of transactions between reportable segments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Capital expenditures and identifiable assets by segment were as follows:
(a) Represents elimination transactions between reportable segments.
(b) Represents identifiable assets not directly attributable to segments.
NOTE 13: FAIR VALUE MEASUREMENTS, DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Allegheny determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants and based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties and the impact of credit enhancements, but also the impact of Allegheny’s own nonperformance risk on its liabilities. Allegheny uses a fair value hierarchy based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company’s own assumptions about the assumptions that market participants would use. The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below.
Level 1
-
Quoted prices for identical instruments in active markets.
Level 2
-
Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations for which all significant inputs are observable market data.
Level 3
-
Unobservable inputs significant to the fair value measurement supported by little or no market activity.
In some cases, the inputs used to measure fair value may meet the definition of more than one level of fair value hierarchy. The lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Allegheny’s assets and liabilities measured at fair value on a recurring basis at December 31, 2009 and 2008 consisted of the following:
(a) Cash equivalents represent amounts invested in money market mutual funds and are valued using Level 1 inputs.
(b) Before netting of cash collateral and FTR obligations.
See Note 11, “Pension Benefits and Postretirement Benefits Other Than Pensions,” for information related to fair value measurements of pension and other postretirement benefit plan assets.
All derivatives, except those for which an exception applies, are recorded in Allegheny’s Consolidated Balance Sheets at fair value. Derivative contracts that have been designated as normal purchases or normal sales are not subject to mark to market accounting treatment, and their effects are included in earnings at the time of contract performance.
Certain derivative contracts that hedge an exposure to variability in expected future cash flows attributable to a particular risk or transaction have been designated as cash flow hedges. Allegheny’s hedge strategies include the use of derivative contracts to manage the variable price risk related to forecasted sales and forecasted purchases of electricity. These contracts held at December 31, 2009 expire at various dates through May 2012.
For cash flow hedges, changes in the fair value of the derivative contract are reported in accumulated other comprehensive income (loss), to the extent they are effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. Changes in any ineffective portion of the hedge are immediately recognized in earnings.
For derivative contracts that have not been designated as normal purchase or normal sales or designated as part of a hedging relationship, unrealized and realized gains and losses are included in revenues or expenses on the Consolidated Statements of Income, depending on relevant facts and circumstances.
The following table disaggregates the net fair values of derivative assets and liabilities, before netting of cash collateral and FTR obligation, based on their level within the fair value hierarchy. This table excludes derivatives that have been designated as normal purchases or normal sales.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Derivative assets and liabilities included in Level 1 primarily consist of exchange-traded futures and other exchange-traded transactions that are valued using closing prices for identical instruments in active markets. Derivative assets and liabilities included in Level 2 primarily consist of commodity forward contracts and interest rate swaps. Derivatives included in Level 2 are valued using a pricing model with inputs that are observable in the market, such as quoted forward prices of commodities, or that can be derived from or corroborated by observable market data. Derivative assets included in Level 3 consist of FTRs and are valued using an internal model based on data from PJM annual and monthly FTR auctions.
The following table shows the expected settlement year for derivative assets and (liabilities) outstanding before netting of cash collateral and the FTR obligation at December 31, 2009:
The following table shows the expected settlement year for derivative assets and (liabilities) outstanding before netting of cash collateral and FTR obligation at December 31, 2008:
The following tables provide a reconciliation of the beginning and ending balance of FTR derivative assets measured at fair value (Level 3):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The following table shows the volume of derivative contracts held by Allegheny at December 31, 2009 and their respective contract expiration dates, excluding contracts designated as normal purchase or normal sale:
At December 31, 2009, Allegheny held derivative contracts for the sale or purchase of power that were entered into to hedge the variable price risk related to forecasted sales and purchases of power and were designated as cash flow hedging instruments for accounting purposes. Changes in the fair value of these hedging instruments representing the effective portion of the hedge are reported in accumulated other comprehensive income (loss) and subsequently reclassified into earnings when the forecasted transaction is settled and impacts earnings. Allegheny also held derivative contracts at December 31, 2009 that were not designated as part of a cash flow hedge relationship or as normal purchase normal sale. Changes in the fair value of these contracts are reported in revenues on a mark-to-market basis. These derivatives include contracts for the forward purchase and sale of gas that settle in 2010 and that were entered into to hedge a portion of the value of a capacity contract related to the Kern River Pipeline but that do not qualify for cash flow hedge accounting. Interest rate swaps include three interest rate swap agreements with an aggregate notional value of $343 million that were entered into during 2003 to substantially offset three existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions.
Allegheny also holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with Allegheny’s load obligations. These future obligations are not reflected on Allegheny’s Consolidated Balance Sheets, and the FTRs are not designated for cash flow hedge accounting. As a result, the timing of recognition of gains or losses on FTRs will differ from the timing of power purchases, including incurred congestion charges. Allegheny acquires its FTRs in an annual auction through a self-scheduling process involving the use of auction revenue rights (“ARRs”) allocated to members of PJM that have load serving obligations. Allegheny initially records FTRs and an FTR obligation payable to PJM at the annual FTR auction price, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by Allegheny’s unregulated subsidiaries are included in operating revenues as unrealized gains or losses. Unrealized gains or losses on FTRs held by Allegheny’s regulated subsidiaries are recorded as regulatory assets or liabilities.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The recorded fair values of derivatives at December 31, 2009 were as follows:
(a) The FTR obligation at December 31, 2009 is $127.9 million and is payable to PJM in approximately equal weekly amounts through the PJM planning year ending May 31, 2010. Of this obligation, $96.2 million has been netted against the FTR derivative asset balance and the remaining $31.7 million is included in non-derivative current liabilities on the consolidated balance sheet. Prior to June 1, 2009 FTR obligations were payable to PJM in monthly installments.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The recorded fair values of derivatives at December 31, 2008 were as follows:
(a) The FTR obligation at December 31, 2008 was $300.6 million and was payable to PJM in monthly installments through the PJM planning year ending May 31, 2009. Of this obligation, $189.8 million was netted against the FTR derivative asset balance and the remaining $110.8 million was included in non-derivative current liabilities on the consolidated balance sheet.
The following table provides details on the changes in accumulated other comprehensive income (“OCI”) relating to derivative assets and liabilities that qualified for cash flow hedge accounting.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Derivative losses included in accumulated OCI in the amount of $16.6 million, before tax, are expected to be reclassified to earnings over the next twelve months.
The following table shows the location and amounts of gains (losses) on derivatives designated as cash flow hedges:
Unrealized gains (losses) on derivative instruments not designated or qualifying as cash flow hedge instruments were as follows:
Credit Related Contingent Features
Certain of Allegheny’s derivative contracts contain collateral posting requirements tied to its credit ratings that would require posting of additional collateral in the event of a credit rating downgrade. The aggregate fair value of these derivative contracts that were in a liability position, disregarding any contractual netting arrangements, at December 31, 2009 was $21.4 million, for which Allegheny had posted collateral of $5.2 million. A one level downgrade in AE Supply’s senior unsecured credit rating at December 31, 2009 would have required the posting of $12.1 million of collateral, in addition to the $5.2 million of posted collateral, for such derivative contracts in a liability position. A downgrade in AE Supply’s senior unsecured credit rating at December 31, 2009 to below Standard & Poor’s BB- or Moody’s Ba3 would have required the posting of $15.5 million of collateral, in addition to the $5.2 million of posted collateral, for such derivative contracts in a liability position.
The aggregate fair value of these derivative contracts that were in a liability position, disregarding any contractual netting arrangements, at December 31, 2008 was $46.9 million, for which Allegheny had posted collateral of $17.2 million. A one level downgrade in AE Supply’s senior unsecured credit rating at December 31, 2008 would have required the posting of $15.6 million of collateral, in addition to the $17.2 million of posted collateral, for such derivative contracts in a liability position. A downgrade in AE Supply’s
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
senior unsecured credit rating at December 31, 2008 to below Standard & Poor’s BB- or Moody’s Ba3 would have required the posting of $21.3 million of collateral, in addition to the $17.2 million of posted collateral, for such derivative contracts in a liability position.
Credit Exposure
Allegheny and its subsidiaries have credit exposure to energy trading counterparties. The majority of these exposures are the fair value of multi-year contracts for energy sales and purchases. If these counterparties fail to perform their obligations under such contracts, Allegheny and its subsidiaries would experience lower revenues or higher costs to the extent that replacement sales or purchases could not be made at the same prices as those under the defaulted contracts.
Allegheny’s wholesale credit risk is the replacement cost for outstanding contracts and amounts owed to or due from counterparties for completed transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses in circumstances in which Allegheny has a legally enforceable right of setoff. Allegheny and its subsidiaries have credit policies to manage credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the use of master netting agreements. These agreements include credit mitigation provisions, such as margin, prepayment or other form of collateral acceptable to the counterparty. Allegheny may request additional credit assurance in the event that a counterparty’s credit ratings fall below investment grade or its exposures exceed an established credit limit.
NOTE 14: PURCHASE OF HYDROELECTRIC GENERATION FACILITIES
In December 2009, Allegheny purchased two hydroelectric generation facilities located at Allegheny Lock and Dam 5 and 6 in Freeport, PA with a nominal maximum generation capacity of 13 MW. This purchase effectively settled existing power purchase agreements under which Allegheny purchased the power generated by these facilities through 2034. Accordingly, at the transaction closing date, Allegheny recorded a credit to purchased power expense in the amount of $10.6 million, representing the fair value of the power agreements at that date. The purchase of the facilities was accounted for as a business combination for which the total consideration was $12.6 million consisting of a cash payment of approximately $2.0 million plus the fair value of the power purchase agreements. The fair value of the net assets acquired exceeded the total consideration paid by $6.7 million, representing a bargain purchase that was credited to operations and maintenance expense.
NOTE 15: DIVIDEND RESTRICTIONS
Under the terms of the AE Revolving Credit Facility, AE may pay quarterly cash dividends in an amount not to exceed 6.25% or 10% of Allegheny’s net income for the four quarters ended with the quarter immediately preceding the quarter in which the dividend is paid, depending on Allegheny’s leverage ratio on the last day of the preceding quarter. Under this restriction, AE’s dividends during the first quarter 2010 may not exceed approximately $39.0 million. Additionally, under terms of its proposed merger with FirstEnergy, AE is prohibited from increasing its quarterly cash dividend.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 16: JOINTLY OWNED BATH COUNTY GENERATION FACILITY
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 records a prorated share of all expenditures related to its interest in the Bath County generation facility. AGC is consolidated by Allegheny through its subsidiary, AE Supply. AGC’s investment and accumulated depreciation in its 40% interest in the Bath County generation facility, at December 31 were as follows:
NOTE 17: FINANCIAL INSTRUMENTS
As of December 31, 2009 and 2008, the carrying amounts of accounts receivable and accounts payable are representative of fair value because of their short-term nature. The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year, at December 31 were as follows:
The fair value of long-term debt was estimated based on actual market prices or market prices of similar debt issues.
Allegheny also has certain assets and liabilities that are recorded at fair value relating to pension plan assets and derivative instruments. See Note 11, “Pension Benefits and Postretirement Benefits Other Than Pensions” and Note 13, “Fair Value Measurements, Derivative Instruments and Hedging Activities,” for additional information.
NOTE 18: GOODWILL AND INTANGIBLE ASSETS
Allegheny’s recorded goodwill was $367.3 million at December 31, 2009 and 2008. There were no changes in recorded goodwill during 2009, 2008 or 2007. The recorded goodwill is attributable to the unregulated generation operations of AE Supply, a reporting unit that substantially comprised Allegheny’s Merchant Generation segment at December 31, 2009.
Allegheny tests goodwill for possible impairment on an annual basis as of August 31 of each year and at any other time if an event occurs or circumstances change that would indicate that the fair value of the reporting unit is likely to have decreased below its carrying amount.
The first step of the goodwill impairment test consists of comparing the reporting unit’s fair value to its carrying value, including the goodwill allocated to the reporting unit. If the estimated fair value of the reporting unit exceeds its carrying amount, the reporting unit’s goodwill is not considered to be impaired, and a second step of the impairment test is unnecessary. If required, the second step of the test compares the implied fair value of the reporting unit’s goodwill, determined in the same manner as the amount of goodwill recognized in a business combination, to the carrying amount of such goodwill.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Allegheny performed its annual goodwill impairment test as of August 31, 2009, and management concluded that the estimated fair value of the reporting unit exceeded its carrying value and, therefore, no impairment existed at that date. The fair value was estimated using both a discounted cash flow income approach and a market based approach. Both approaches involve management judgment, and estimated values are subject to change in relation to evolving market conditions and the business environment.
Intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:
Amortization expense for intangible assets was $12.6 million in 2009, $12.2 million in 2008 and $14.9 million in 2007.
Future amortization expense for intangible assets at December 31, 2009 is estimated as follows:
NOTE 19: ASSET RETIREMENT OBLIGATIONS (“ARO”)
Allegheny has AROs primarily related to ash landfills, underground and aboveground storage tanks, asbestos contained in its generation facilities, wastewater treatment lagoons and transformers containing polychlorinated biphenyls (“PCBs”).
The following table provides a reconciliation of the beginning and ending ARO liability for 2009 and 2008:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Allegheny believes it is probable that it will recover the ARO costs incurred by its regulated companies in rates. Therefore, it records costs currently incurred for AROs as a reduction to the recorded regulatory liability or it establishes a regulatory asset depending on the rate recovery mechanism of the specific jurisdiction. See Note 6, “Regulatory Assets and Liabilities” for a discussion of the regulatory assets and liabilities associated with asset retirement and removal costs.
NOTE 20: ADVERSE POWER PURCHASE COMMITMENT LIABILITY
In May 1998, the Pennsylvania PUC issued an order approving a transition plan for West Penn. This order was amended by a settlement agreement approved by the Pennsylvania PUC in November 1998. West Penn recorded an extraordinary charge in 1998 to reflect the disallowances of certain costs in the order. This charge included an estimated amount for an adverse power purchase commitment reflecting the commitment to purchase power at above-market prices. The adverse power purchase commitment liability is being amortized over the life of the commitment based on a schedule of estimated electricity purchases used to determine the amount of the charge.
As of December 31, 2009, Allegheny’s reserve for adverse power purchase commitments was $132.3 million, including a current liability of $17.9 million. Allegheny’s liability for adverse power purchase commitments decreased as follows:
These decreases in the reserve for adverse power purchase commitments are recorded as expense reductions in “Purchased power and transmission” on the Consolidated Statements of Income.
NOTE 21: OTHER INCOME (EXPENSE), NET
Other income (expense), net, consisted of the following:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 22: GUARANTEES AND LETTERS OF CREDIT
In connection with certain sales, acquisitions and financings, and in the normal course of business, AE and its subsidiaries enter into various agreements that may include guarantees or require the issuance of letters of credit. AE has a $376 million revolving credit facility, any unutilized portion of which is available to AE for the issuance of letters of credit. Additionally, subject to certain conditions, AE Supply is permitted to request letters of credit of up to $50 million in the aggregate, and AE is permitted to request, on behalf of AE Supply and its subsidiaries, letters of credit of up to $125 million in the aggregate, under AE’s revolving credit facility.
(a) Includes AE guarantees on behalf of its subsidiaries of $95.2 million and $69.7 million at December 31, 2009 and 2008, respectively.
(b) Amounts represent AE guarantees on behalf of its subsidiaries.
(c) These amounts were comprised of a letter of credit issued in connection with a contractual obligation of Allegheny Ventures that will expire in July 2010.
(d) These amounts were not issued under either AE’s credit facility or AE Supply’s credit facility.
NOTE 23: VARIABLE INTEREST ENTITIES
GAAP requires the primary beneficiary of a Variable Interest Entity (“VIE”) to consolidate the entity and also requires majority and significant variable interest investors to provide certain disclosures. A VIE is an entity in which the equity investors do not have a controlling interest or in which the equity investment at risk is insufficient to finance the entity’s activities without receiving financial support from the other parties.
Independent Power Producer (“IPP”) contracts. Potomac Edison and West Penn each have a long-term electricity purchase contract with unrelated independent power producers (“IPP”). Allegheny periodically requests from these IPPs the information necessary to determine whether they are VIEs and whether Allegheny is the primary beneficiary. Allegheny has been unable to obtain the requested information, which was determined by the IPPs to be proprietary.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Potomac Edison and West Penn purchased power from these two IPPs in the amount of $96.4 million and $42.5 million, respectively, in 2009, $113.3 million and $40.8 million, respectively, in 2008, $104.6 million and $52.5 million, respectively, in 2007. Neither Potomac Edison nor West Penn is subject to any risk of loss associated with the applicable potential VIE, because neither VIE has any obligation to the applicable IPP other than to purchase the power that the IPP produces according to the terms of the applicable electricity purchase contract.
APS Constellation, LLC (“APS Constellation”). Allegheny Ventures, Inc., a non-utility subsidiary of AE, formed a partnership in 1995 with an unregulated business of Constellation Energy in a joint venture energy services company named APS Constellation. The business purpose of APS Constellation is the marketing, development, and implementation of energy conservation projects. APS Constellation, working under an Engineer/Procure/Construct agreement as a subcontractor for Potomac Edison, completed multiple energy conservation projects for Potomac Edison’s government customers at Ft. Detrick, Maryland. The projects resulted in performance payments and other fees remitted to APS Constellation. APS Constellation securitized the future revenue streams from the projects through several financings and made a partnership distribution of the proceeds. Some of the project financings required Potomac Edison to provide ongoing guarantees.
In 2005, the joint venture operating agreement was amended to limit Allegheny’s obligations and participation in APS Constellation.
The accounts of APS Constellation are not included in Allegheny’s Consolidated Financial Statements because Allegheny does not expect to absorb a majority of the expected losses and/or residual returns based on an analysis of the services being provided under the joint venture operating agreement.
At December 31, 2009, Allegheny’s maximum exposure to loss related to APS Constellation consisted of a $0.7 million equity investment in APS Constellation, a letter of credit guarantee of $3.2 million and recourse guarantees of $6.4 million. At December 31, 2008, Allegheny’s maximum exposure to loss related to APS Constellation consisted of a $0.7 million equity investment in APS Constellation, a letter of credit guarantee of $3.3 million and recourse guarantees of $6.8 million. These guarantees are not recorded on Allegheny’s Consolidated Balance Sheet.
PATH, LLC. As discussed at Note 5, “Transmission Expansion,” in September 2007, Allegheny and AEP formed PATH, LLC to construct and operate PATH. The accounts of PATH, LLC and its operating subsidiaries, including PATH-WV (the jointly owned series of PATH, LLC) are included in Allegheny’s consolidated financial statements for the years ended 2009, 2008, and 2007.
Although Allegheny has not yet completed its analysis regarding the application of a new accounting pronouncement related to variable interest entities, Allegheny expects to deconsolidate PATH-WV from its financial statements effective January 1, 2010. At December 31, 2009 and 2008, Allegheny’s Balance Sheet primarily reflected property, plant and equipment associated with the construction of PATH-WV of approximately $35.8 million and $7.4 million, respectively, cash and cash equivalents of $3.4 million and $3.6 million, respectively, and noncontrolling interest related to AEP’s ownership of approximately $14.9 million and $4.9 million, respectively. For the years ended 2009, 2008 and 2007, PATH-WV had total revenues of $10.8 million, $6.4 million and $0, respectively, total operating income of $4.4 million, $1.6 million and $0, respectively, net income of $2.6 million, $0.9 million and $0, respectively, and net income attributable to AEP’s noncontrolling interest of $1.3 million, $0.4 million and $0, respectively. The possible deconsolidation of PATH-WV is not expected to impact net income attributable to Allegheny Energy, Inc.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Energy Insurance Services, Inc. Allegheny has entered into an insurance arrangement with Energy Insurance Services, Inc. (“EIS”) whereby EIS writes policies for Allegheny in a segregated cell, referred to as Mutual Business Program No. 2 (the “Program”). The Program is governed by a Participation Agreement that limits claims paid on policies that are not reinsured to premium payments made by Allegheny, contributions to surplus and any investment returns on those premiums less expenses. The accounts of EIS are included in Allegheny’s Consolidated Financial Statements because Allegheny is the sole beneficiary of the Program. At December 31, 2009, total assets were $18.5 million, consisting primarily of investments, and total liabilities were $13.7 million, consisting primarily of claim reserves. At December 31, 2009, Allegheny’s maximum exposure to loss related to EIS consisted of a $4.8 million equity investment in EIS recorded on its Consolidated Balance Sheet. At December 31, 2008, total assets were $15.3 million, consisting primarily of investments, and total liabilities were $12.1 million, consisting primarily of claim reserves. At December 31, 2008, Allegheny’s maximum exposure to loss related to EIS consisted of a $3.2 million equity investment in EIS recorded on its Consolidated Balance Sheet.
NOTE 24: ACQUISITION OF NONCONTROLLING INTEREST IN AE SUPPLY
On January 25, 2008, Allegheny and Merrill Lynch entered into a settlement agreement that resolved litigation between the two parties related to a dispute regarding Allegheny’s purchase of Merrill Lynch’s energy marketing and trading business in 2001. As a result of this settlement, Allegheny reversed its previously recorded accrued interest liability of $54.7 million through a credit to interest expense during the fourth quarter of 2007.
On March 31, 2008, in accordance with the settlement agreement, Allegheny made a cash payment to Merrill Lynch in the amount of $50 million, and Merrill Lynch conveyed to Allegheny its approximately 1.5% equity interest in AE Supply. Allegheny recorded the acquisition of Merrill Lynch’s noncontrolling interest in AE Supply using the purchase method of accounting. Under the purchase method of accounting, the purchase price was allocated to individual assets acquired and liabilities assumed based on the fair values of such assets and liabilities. The purchase accounting adjustments will be amortized against income over the estimated lives of the individual assets and liabilities, ranging from 3 years to 30 years. No goodwill was recorded. The effects of the purchase accounting adjustments are not expected to materially impact Allegheny’s financial results for any period. Allegheny ceased recording expense relating to the noncontrolling interest in AE Supply as of January 1, 2008.
NOTE 25: COMMITMENTS AND CONTINGENCIES
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. 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.
Environmental Matters and Litigation
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.
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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, CO 2 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 U.S. Environmental Protection Agency (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 of 1970 (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 U.S. Department of Energy 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.
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:
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maintaining an accurate CO2 emissions data base;
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improving the efficiency of its existing coal-burning generation facilities;
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following developing technologies for clean-coal energy and for CO2 emission controls at coal-fired power plants, including carbon sequestration;
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•
participating in CO2 sequestration efforts (e.g. reforestation projects) both domestically and abroad;
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analyzing options for future energy investment (e.g. renewables, clean-coal, etc.); and
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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.
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
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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 SO 2 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 generating 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 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.
On January 8, 2010, the West Virginia Department of Environmental Protection (the “WVDEP”) issued a Notice of Violation for opacity emissions at Allegheny’s Pleasants generating facility. Allegheny is evaluating certain control system operations for opacity reduction. Although a system has not yet been selected, the cost to install any such system would 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 New Source Review (“NSR”) standards of the Clean Air 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.
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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.
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.
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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.
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
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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.
Other Litigation and Contingencies
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 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
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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 4, 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 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
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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.
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 the Midwest Independent Transmission System Operator (“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.
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.
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.
Leases
Allegheny has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles, computer equipment, communication lines and buildings.
Total capital and operating lease rent payments of $18.6 million, $19.1 million and $18.5 million were recorded as rent expense in 2009, 2008 and 2007, respectively. Allegheny’s estimated future minimum lease payments for capital and operating leases, with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are:
The carrying amount of assets recorded under capitalized lease agreements included in “Property, plant and equipment, net” at December 31, consisted of the following:
PURPA
The Energy Policy Act of 2005 (the “Energy Policy Act”) amended PURPA significantly. Most notably, as of the effective date of the Energy Policy Act on August 8, 2005, electric utilities are no longer required to enter into any new contractual obligation to purchase energy from a qualifying facility if FERC finds that the facility
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has non-discriminatory access to a functioning wholesale market and open access transmission. This amendment has no impact on Allegheny’s current long-term power purchase agreements under PURPA.
Allegheny’s regulated utilities are committed to purchasing the electrical output from 466 MWs of qualifying PURPA capacity. PURPA expense pursuant to these contracts in 2009, 2008 and 2007 was $213.2 million, $222.2 million and $224.5 million, respectively. The average cost of these power purchases was approximately 6.8, 6.3 and 5.9 cents per kilowatt-hour (“kWh”) in 2009, 2008 and 2007, respectively.
The table below reflects Allegheny’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2009. The commitments were calculated based on expected PURPA purchased power prices at December 31, 2009, without giving effect to possible price changes that could occur as a result of any future CO2 emissions regulation or legislation. Actual values can vary substantially depending upon future conditions.
Fuel Purchase and Transportation Commitments
Allegheny has entered into various long-term commitments for the procurement and transportation of fuel (primarily coal) and lime to supply its generation facilities. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Allegheny’s fuel expense was $886.6 million, $1,080.9 million and $930.8 million in 2009, 2008 and 2007, respectively, of which, $823.1 million, $1,000.2 million and $831.5 million, respectively, related to coal and lime expense. In 2009, Allegheny purchased approximately 25.0% of its coal from one vendor. Total estimated long-term fuel purchase and transportation commitments at December 31, 2009 were as follows:
Other Purchase Obligations
Electronic Data Systems Corporation and EDS Information Services, LLC perform certain technology functions for Allegheny under a contract that expires on December 31, 2012. Expected cash payments under this contract are as follows:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 26: QUARTERLY FINANCIAL INFORMATION (Unaudited)
(a) Quarterly amounts may not total to full-year results due to rounding.
NOTE 27: SUBSEQUENT EVENT-MERGER AGREEMENT
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”).
Upon the terms and subject to the conditions set forth in the Merger Agreement, which has been unanimously approved by the boards of directors of AE and FirstEnergy, Merger Sub will merge with and into AE (the “Merger”), with AE continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended, and be tax-free to AE stockholders.
Pursuant to the Merger Agreement, upon the closing of the Merger, each issued and outstanding share of AE common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy (the “Exchange Ratio”).
All options to purchase shares of AE common stock under AE’s stock plans, whether vested or unvested, will automatically be converted into options to acquire a number of shares of FirstEnergy common stock as adjusted for the Exchange Ratio at an equitably adjusted option price and otherwise on the same terms and conditions. All awards of AE restricted stock that have not already vested in accordance with their terms as of immediately prior to the closing of the Merger will automatically be converted into the right to receive similarly restricted shares of FirstEnergy common stock based on the Exchange Ratio. Likewise, any performance shares and restricted stock units that have not already vested in accordance with their terms as of immediately prior to the closing of the Merger will automatically be converted into performance shares or stock units in respect of FirstEnergy common stock based on the Exchange Ratio as equitably adjusted as appropriate to reflect resulting changes in their underlying terms.
Upon the closing of the Merger, FirstEnergy’s Board of Directors will be increased from 11 to 13 members, and two of AE’s current Board members will be appointed to FirstEnergy’s Board. Paul J. Evanson, currently Chairman, President and Chief Executive Officer of AE, will become the Executive Vice Chairman of FirstEnergy, upon the closing.
Completion of the Merger is subject to various customary conditions, including, among others, (i) requisite approvals of AE and FirstEnergy stockholders, (ii) effectiveness of the registration statement for the FirstEnergy common stock to be issued in the Merger, (iii) expiration or termination of the applicable Hart-Scott-Rodino Act
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
waiting period, (iv) receipt of all required regulatory approvals from, among others, the Federal Energy Regulatory Commission and certain state public service and utility commissions, (v) the absence of any governmental action challenging or seeking to prohibit the Merger, and (vi) the absence of any material adverse effect with respect to either AE or FirstEnergy.
The Merger Agreement contains customary representations, warranties and covenants of AE and FirstEnergy, including, among others, covenants (i) to conduct their respective businesses in the ordinary course during the interim period between the execution of the Merger Agreement and completion of the Merger, (ii) not to engage in certain kinds of transactions during this interim period, (iii) to hold a stockholder meeting to put these matters before their stockholders for their consideration and (iv) to use their reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals, subject to certain limitations. Each of AE and FirstEnergy is also subject to a “no shop” restriction on its ability to solicit alternative acquisition proposals, provide information and engage in discussion with third parties, except under limited circumstances to permit AE’s or FirstEnergy’s board of directors to comply with its fiduciary duties.
The Merger Agreement contains certain termination rights for both AE and FirstEnergy and further provides that, upon termination of the Merger Agreement under specified circumstances, AE may be required to pay FirstEnergy a termination fee of $150 million and FirstEnergy may be required to pay AE a termination fee of $350 million and, in each case, reimburse the other party for up to $45 million of its reasonable out-of-pocket transaction expenses. The Merger Agreement also provides that under specified circumstances where a termination fee is not otherwise payable, AE or FirstEnergy may be required to reimburse the non-terminating party for up to $45 million of its reasonable out-of-pocket transaction expenses.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Allegheny Energy, Inc.
Greensburg, PA
We have audited the accompanying consolidated balance sheets of Allegheny Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of income, equity and comprehensive income, and cash flows for each of the two years in the period ended December 31, 2009. Our audits also included the financial statement schedules as of and for the years ended December 31, 2009 and 2008 listed in the Index at Item 8. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits. The consolidated financial statements and financial statement schedules of the Company for the year ended December 31, 2007 were audited by other auditors whose report, dated February 27, 2008 (except for the effects of changing the manner in which the Company presents noncontrolling interests as discussed in Note 2 and the change in composition of reportable segments as discussed in Note 12 to which the date is March 1, 2010), expressed an unqualified opinion and included an explanatory paragraph concerning a change in the manner in which the Company accounts for uncertain tax positions as of January 1, 2007 as discussed in Note 7.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such 2009 and 2008 consolidated financial statements present fairly, in all material respects, the financial position of Allegheny Energy, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules as of and for the years ended December 31, 2009 and 2008, when considered in relation to basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 1, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Pittsburgh, PA
March 1, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Allegheny Energy, Inc.
Greensburg, PA
We have audited the internal control over financial reporting of Allegheny Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2009 of the Company and our report dated March 1, 2010 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.
/s/ Deloitte & Touche LLP
Pittsburgh, PA
March 1, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
of Allegheny Energy, Inc.
In our opinion, the consolidated statement of income, equity and comprehensive income and cash flows for the year ended December 31, 2007 present fairly, in all material respects, the results of operations and cash flows of Allegheny Energy, Inc. and its subsidiaries for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules for the year ended December 31, 2007 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 7, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.
/s/ PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
February 27, 2008, except for the effects of changing the manner in which the Company presents
noncontrolling interests as discussed in Note 2 and the change in the composition of reportable
segments discussed in Note 12 to which the date is March 1, 2010.
S-1
SCHEDULE I
ALLEGHENY ENERGY, INC. (Parent Company)
Condensed Financial Statements
Statements of Income:
Balance Sheets:
See accompanying Note to Condensed Financial Statements.
ALLEGHENY ENERGY, INC. (Parent Company)
NOTES TO CONDENSED FINANCIAL STATEMENTS
NOTE 1: BASIS OF PRESENTATION
Pursuant to rules and regulations of the Securities and Exchange Commission (SEC), the unconsolidated condensed financial statements of Allegheny Energy, Inc. (AE) do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Form 10-K.
AE has accounted for the earnings of its subsidiaries under the equity method in these unconsolidated condensed financial statements. Stockholders’ equity reflects accumulated other comprehensive loss of $89.9 million and $43.3 million at December 31, 2009 and 2008, respectively.
S-2
SCHEDULE II
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
For Years Ended December 31, 2009, 2008 and 2007
(a) Amount charged to bad debt expense.
(b) Collection of accounts previously written off.
(c) Uncollectible accounts written off during the year.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures. AE maintains disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the chief executive officer (“CEO”) and chief financial officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosures.
As of the end of the period covered by this report, our management, with the participation of our CEO and CFO, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13(a)-15(e) and 15(d)-15(e) of the Exchange Act. This evaluation included consideration of the various processes carried out under the direction of our disclosure committee. Based on this evaluation, our CEO and CFO concluded that AE’s disclosure controls and procedures were effective, at the reasonable assurance level, to ensure that material information relating to AE is (a) accumulated and made known to its management, including our CEO and CFO, to allow timely decisions regarding required disclosure and (b) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
As an accelerated filer, AE is required to meet the requirements under Section 404 of the Sarbanes-Oxley Act of 2002. See “Management’s Report on Internal Control Over Financial Reporting,” below.
Changes in Internal Control over Financial Reporting: During the quarter ended December 31, 2009, there have been no changes in AE’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting. AE’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. AE’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. AE’s internal control over financial reporting includes those policies and procedures that:
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of AE’s assets;
(2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that AE’s receipts and expenditures are being made only in accordance with authorizations of its management and directors; and
(3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the AE’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
AE’s management assessed the effectiveness of AE’s internal control over financial reporting as of December 31, 2009. In making this assessment, AE’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control-Integrated Framework.”
Based on this assessment, management concluded that, as of December 31, 2009, AE’s internal control over financial reporting is effective based on those criteria.
The effectiveness of AE’s internal control over financial reporting as of December 31, 2009 has been audited by Deloitte & Touche, LLP, an independent registered public accounting firm, as stated in their report, which appears herein.
ITEM 9B. OTHER INFORMATION
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
The information required by this Item (other than the information set forth below) is contained in AE’s Proxy Statement for its 2010 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors,” “Executive Compensation” and “Security Ownership-Section 16(a) Beneficial Ownership Reporting Compliance,” and is incorporated herein by reference.
Executive Officers
The information required by this Item with respect to the registrant’s executive officers is contained in Item 1 of Part I of this Form 10-K under the section “Executive Officers.”
Code of Business Conduct and Ethics
Allegheny maintains a Code of Business Conduct and Ethics for its directors, officers and employees in order to promote honest and ethical conduct and compliance with the laws and regulations to which Allegheny is subject. All directors, officers and employees of Allegheny are expected to be familiar with the Code of Business Conduct and Ethics and to adhere to its principles and procedures. The Code of Business Conduct and Ethics is available free of charge on Allegheny’s website at http://www.alleghenyenergy.com. Allegheny intends to satisfy the disclosure requirements of the SEC regarding amendments to, or waivers from, the Code of Conduct and Business Ethics by posting such information on the website listed above.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is contained in AE’s Proxy Statement for the 2010 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors” and “Executive Compensation” and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item is contained in AE’s Proxy Statement for the 2010 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors” and “Executive Compensation” and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is contained in AE’s Proxy Statement for the 2010 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors” and “Executive Compensation” and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is contained in AE’s Proxy Statement for the 2010 Annual Meeting of Shareholders under the captions “Board of Directors and Election of Directors” and “Executive Compensation” and is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1)(2)
The financial statements and financial statement schedules filed as part of this Report are set forth under Item 8. Reference is made to the index on page 192.
SIGNATURES
Pursuant to the requirements of Section 13 of 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ALLEGHENY ENERGY, INC.
By:
/s/ Paul J. Evanson
(Paul J. Evanson, Chairman, President
and Chief Executive Officer)
Date: March 1, 2010
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant, in the capacities and on the date indicated.
Signature
Title
Date
(i)
Principal Executive Officer:
/s/ Paul J. Evanson
(Paul J. Evanson)
Chairman and President, Chief Executive Officer
March 1, 2010
(ii)
Principal Financial Officer:
/s/ Kirk R. Oliver
(Kirk R. Oliver)
Senior Vice President and Chief Financial Officer
March 1, 2010
(iii)
Principal Accounting Officer:
/s/ William F. Wahl, III
(William F. Wahl, III)
Vice President, Controller and Chief Accounting Officer
March 1, 2010
(iv)
Directors:
/s/ H. Furlong Baldwin
(H. Furlong Baldwin)
/s/ Ted J. Kleisner
(Ted J. Kleisner)
/s/ Eleanor Baum
(Eleanor Baum)
/s/ Christopher D. Pappas
(Christopher D. Pappas)
/s/ Paul J. Evanson
(Paul J. Evanson)
/s/ Steven H. Rice
(Steven H. Rice)
March 1, 2010
/s/ Cyrus F. Freidheim, Jr.
(Cyrus F. Freidheim, Jr.)
/s/ Gunnar E. Sarsten
(Gunnar E. Sarsten)
/s/ Julia L. Johnson
(Julia L. Johnson)
/s/ Michael H. Sutton
(Michael H. Sutton)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-160988 on Form S-3 and Registration Statement Nos. 333-65657, 333-31610, 33-40432, 333-113660, 333-117117, 333-151647, and 333-119397 on Form S-8 of our reports dated March 1, 2010, relating to the consolidated financial statements and financial statement schedules of Allegheny Energy, Inc. and subsidiaries and the effectiveness of Allegheny Energy, Inc. and subsidiaries’ internal control over financial reporting, appearing in the Annual Report on Form 10-K of Allegheny Energy, Inc. for the year ended December 31, 2009.
/s/ Deloitte & Touche LLP
Pittsburgh, Pennsylvania
March 1, 2010
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in Registration Statements on Form S-8 (Nos. 333-65657, 333-31610, 33-40432, 333-113660, 333-117117, 333-151647, and 333-119397) of Allegheny Energy, Inc. of our report dated February 27, 2008, except for the effects of changing the manner in which the Company presents noncontrolling interests as discussed in Note 2 and the change in the composition of reportable segments discussed in Note 12 to which the date is March 1, 2010, relating to the financial statements and financial statement schedules, which appear in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
March 1, 2010
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Energy, Inc., a Maryland corporation, do hereby constitute and appoint PAUL J. EVANSON and KIRK R. OLIVER , and each of them, a true and lawful attorney in his or her name, place and stead, in any and all capacities, to sign his or her name to the annual report on Form 10-K for the year ended December 31, 2009, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said company, and to cause the same to be filed with the SEC, granting unto said attorneys and each of them full power and authority to do and perform any act and thing necessary and proper to be done in the premises, as fully and to all intents and purposes as the undersigned could do if personally present, and the undersigned hereby ratifies and confirms all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.
Dated: March 1, 2010
/s/ H. Furlong Baldwin
(H. Furlong Baldwin)
/s/ Ted J. Kleisner
(Ted J. Kleisner)
/s/ Eleanor Baum
(Eleanor Baum)
/s/ Christopher D. Pappas
(Christopher D. Pappas)
/s/ Paul J. Evanson
(Paul J. Evanson)
/s/ Steven H. Rice
(Steven H. Rice)
/s/ Cyrus F. Freidheim, Jr.
(Cyrus F. Freidheim, Jr.)
/s/ Gunnar E. Sarsten
(Gunnar E. Sarsten)
/s/ Julia L. Johnson
(Julia L. Johnson)
/s/ Michael H. Sutton
(Michael H. Sutton)
EXHIBIT INDEX
(Rule 601(a))
Documents
Incorporation by Reference
2.1**
Agreement and Plan of Merger, dated as of February 10, 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny Energy, Inc.
Form 8-K filed February 11, 2010, ex. 2.1
3.1
Articles of Restatement, dated September 4, 2008
Form 10-Q filed November 6, 2008, ex. 3.1
3.2
Amended & Restated By-laws of the Company adopted December 3, 2009
Form 8-K filed December 9, 2009, ex. 3.1
10.1
Amended and Restated Revised Plan for Deferral of Compensation of Directors
Form 8-K filed October 6, 2006, ex. 99.1
10.2
Amended and Restated Revised Plan for Deferral of Compensation of Directors
Form 10-Q filed November 7, 2007, ex. 10.4
10.3
Allegheny Energy Amended and Restated Supplemental Executive Retirement Plan
Form 10-K filed December 31, 2005, ex. 10.4
10.4
Allegheny Energy Amended and Restated Supplemental Executive Retirement Plan
Form 10-Q filed November 7, 2007, ex. 10.8
10.5
Executive Life Insurance Program and Collateral Assignment Agreement
Form 10-K filed December 31, 1994, ex. 10.5
10.6
Restricted Stock Plan for Outside Directors
Form 10-K filed December 31, 1998, ex. 10.7
10.7
Amended and Restated Restricted Stock Plan for Outside Directors
Form 10-Q filed November 7, 2007, ex. 10.3
10.8
Deferred Stock Unit Plan for Outside Directors
Form 10-K filed December 31, 1997, ex. 10.8
10.9
Allegheny Energy, Inc. 2004 Non-Employee Director Stock Plan
Schedule 14A Definitive Proxy Statement filed April 4, 2004, Annex A
10.10
Allegheny Energy, Inc. Annual Incentive Plan
Schedule 14A Definitive Proxy Statement filed April 4, 2004, Annex B
10.11
Allegheny Energy, Inc. Amended and Restated Annual Incentive Plan
Form 10-Q filed November 7, 2007, ex. 10.7
10.12
Form of Stock Option Agreement
Form 10-K filed December 31, 2004 ex. 10.12
10.13
Stock Unit Plan
Form 10-K filed December 31, 2004, ex. 10.13
10.14
Amended and Restated Stock Unit Plan
Form 10-Q filed November 7, 2007, ex. 10.7
10.15
Form of Stock Unit Agreement
Form 10-K filed December 31, 2004, ex. 10.14
10.16
Allegheny Energy, Inc. 1998 Long-Term Incentive Plan
revised as of January 1, 2004
Form 10-Q filed March 31, 2004, ex. 10.1
10.17
Allegheny Energy, Inc. 1998 Long-Term Incentive Plan
amended and restated as of January 1, 2008
Form 10-Q filed November 7, 2007, ex. 10.5
10.18
Allegheny Energy, Inc. 2008 Long-Term Incentive Plan
Schedule 14A Definitive Proxy Statement filed March 20, 2008, Annex B
10.19
Executive Severance Plan
Form 8-K filed July 16, 2008, ex. 10.1
EXHIBIT INDEX
(Rule 601(a))
Documents
Incorporation by Reference
10.20
Executive Change in Control Severance Plan
Form 8-K filed July 16, 2008, ex. 10.2
10.21
Amended and Restated Employment Agreement with Chief Executive Officer
Form 8-K filed July 10, 2009, ex. 10.1
10.22
Employment Agreement of Vice President, Human Resources
Form 8-K filed January 6, 2006, ex. 10.1
10.23
Amended and Restated Non-Employee Director Stock Plan
Form 10-Q filed November 7, 2007, ex. 10.2
10.24
Amended and Restated Nonqualified Deferred Compensation Plan
Form 10-Q filed November 7, 2007, ex. 10.9
10.25
Amendment to Employment Agreement of Vice President
Form 10-Q filed November 7, 2007, ex. 10.11
10.26
Credit Agreement, dated as of September 24, 2009, among Allegheny Energy Supply Company, LLC, certain lenders party thereto and Bank of America, N.A., as Administrative Agent.
Form 10-Q filed November 9, 2009, ex. 10.4
10.27
EPC Agreement No. 1001 dated July 12, 2006, between
Allegheny Energy Supply Company, LLC and The Babcock & Wilcox Company covering Flue Gas Desulfurization Project at Hatfield’s Ferry Units 1, 2 and 3
Form 10-Q filed August 8, 2006, ex. 10.1
10.28
EPC Agreement No. 1002 dated July 13, 2006, between
Allegheny Energy Supply Company, LLC and Washington
Group International covering Balance of Plant for Flue Gas Desulfurization Project at Hatfield’s Ferry Units 1, 2 and 3
Form 10-Q filed August 8, 2006, ex. 10.2
10.29*
Alliance Agreement for Engineering, Construction and Project Management for the Trans-Allegheny Interstate Line Project, dated February 28, 2007, by and between Trans-Allegheny Interstate Line Company and Kenny Construction Company
Form 10-Q filed May 8, 2007, ex. 10.1
10.30*
Limited Liability Agreement of Potomac-Appalachian Transmission Highline, LLC, dated as of September 1, 2007
Form 10-Q filed November 7, 2007, ex. 10.1
10.31
Credit Agreement, dated as of December 18, 2009, among Monongahela Power Company, certain lenders party thereto and The Bank of Nova Scotia as Administrative Agent
Form 8-K filed December 23, 2009, ex. 10.1
10.32
Credit Agreement, dated as of January 25, 2010, among Trans-Allegheny Interstate Line Company, certain lenders party thereto and BNP Paribas, as Administrative Agent.
Form 8-K filed January 28, 2010, ex. 10.1
10.33
Amended and Restated Credit Agreement, dated as of August 15, 2008, among Trans-Allegheny Interstate Line Company, certain lenders party thereto and Citibank, N.A., as Administrative Agent
Form 10-Q filed November 6, 2008, ex. 10.1
10.34
Equity Commitment Agreement, dated as of August 15, 2008, between Allegheny Energy, Inc. and Union Bank of California, as Collateral Agent
Form 10-Q filed November 6, 2008, ex. 10.2 and Form 10-Q filed November 9, 2009, ex. 10.10
10.35
Pledge Agreement, dated as of August 15, 2008, between Allegheny Energy, Inc. and Union Bank of California, as Collateral Agent
Form 10-Q filed November 6, 2008, ex. 10.3 and Form 10-Q filed November 9, 2009, ex. 10.11
10.37
Amendment Letter, dated as of February 10, 2010, in respect of the Credit Agreement, dated as of September 24, 2009, among Allegheny Energy Supply Company, LLC, the Lenders party thereto, and Bank of America, N.A., as Administrative Agent.
Form 8-K filed February 11, 2010, ex. 10.1
EXHIBIT INDEX
(Rule 601(a))
Documents
Incorporation by Reference
10.38
Amendment Letter, dated as of February 10, 2010, in respect of the Credit Agreement, dated as of May 22, 2006, among Allegheny Energy, Inc., Allegheny Energy Supply Company, LLC, the Lenders party thereto, and Citicorp North America, Inc. as Administrative Agent.
Form 8-K filed February 11, 2010, ex. 10.2
10.39
Amendment Letter, dated as of February 10, 2010, in respect of the Credit Agreement, dated as of December 18, 2009, among Monongahela Power Company, the Lenders party thereto, and The Bank of Nova Scotia, as Administrative Agent.
Form 8-K filed February 11, 2010, ex. 10.3
10.40
Amendment Letter, dated as of February 10, 2010, in respect of the Credit Agreement, dated as of January 25, 2010, among Trans-Allegheny Interstate Line Company, the Lenders party thereto, and BNP Paribas, as Administrative Agent.
Form 8-K filed February 11, 2010, ex. 10.4
10.41
Subsidiaries’ Indentures described below
Computation of ratio of earnings to fixed charges
Filed herewith
Subsidiaries of AE:
Name of Company
State of Organization
Allegheny Energy Service Corporation-100%
Maryland
Allegheny Ventures, Inc.-100%
Delaware
Monongahela Power Company-100%
Ohio
The Potomac Edison Company-100%
Maryland and Virginia
West Penn Power Company-100%
Pennsylvania
Allegheny Energy Supply Company, LLC-100%
Delaware
Allegheny Energy Supply Hunlock Creek, LLC-100%
Delaware
Allegheny Energy Transmission, LLC-100%
Delaware
Green Valley Hydro, LLC-100%
Virginia
Ohio Valley Electric Corporation-3.50%
Ohio
23.1
Consent of Independent Registered Public Accounting Firm
See page 191 herein.
23.2
Consent of Independent Registered Public Accounting Firm
See page 192 herein.
Powers of Attorney
See page 193 herein.
31.1
Certification of Chief Executive Officer pursuant to
Rule 13a-14(a) under Securities Exchange Act of 1934
Filed herewith
31.2
Certification of Chief Financial Officer pursuant to
Rule 13a-14(a) under Securities Exchange Act of 1934
Filed herewith
32.1
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
Filed herewith
32.2
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
Filed herewith
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
* Confidential treatment has been requested from the commission for portions of this document.
** Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Allegheny will furnish the omitted schedules to the SEC upon request by the Commission.