ITEM 1. BUSINESS
Overview
Allegheny is an integrated energy business that owns and operates electric generation facilities and delivers electric and natural gas services to customers in Pennsylvania, West Virginia, Maryland, Virginia and Ohio. AE, Allegheny’s parent holding company, was incorporated in Maryland in 1925 and is registered as a holding company under PUHCA. Allegheny operates its business primarily through AE’s various directly and indirectly owned subsidiaries.
Allegheny has two business segments:
•
The Delivery and Services segment includes Allegheny’s electric and natural gas T&D operations.
•
The Generation and Marketing segment includes Allegheny’s power generation operations.
The Delivery and Services Segment
The principal companies and operations in AE’s Delivery and Services segment include the following:
•
The Distribution Companies include Monongahela (excluding its West Virginia generation assets), Potomac Edison and West Penn. Each of the Distribution Companies is a public utility company and does business under the trade name Allegheny Power. The Distribution Companies’ principal businesses are the operation of electric and natural gas public utility systems.
•
Monongahela was incorporated in Ohio in 1924. It conducts an electric T&D business that serves approximately 400,000 electric customers in northern West Virginia and an adjacent portion of Ohio. Monongahela also conducts a natural gas T&D business, primarily through Mountaineer. Monongahela serves approximately 226,000 residential, commercial, industrial and wholesale natural gas customers in West Virginia and owns approximately 4,878 miles of natural gas distribution pipelines. During 2004, Monongahela sold or transported 62.1 Bcf of natural gas. Monongahela’s electric and natural gas service area covers approximately 14,000 square miles with a population of approximately 1,224,000. Monongahela’s Delivery and Services segment had operating revenues of $669.0 million in 2004. In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia, including Mountaineer, subject to certain conditions. The sale is expected to be completed in mid- to late-2005. Monongahela also has generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below.
•
Potomac Edison was incorporated in Maryland in 1923 and was also incorporated in Virginia in 1974. It operates an electric T&D system in portions of West Virginia, Maryland and Virginia. Potomac Edison serves approximately 442,000 electric customers in a service area of about 7,300 square miles with a population of approximately 987,000. Potomac Edison’s 2004 total operating revenues were $924.4 million. One customer, Eastalco Aluminum Company, accounted for 12.9% and 10.5% of Potomac Edison’s 2004 and 2003 operating revenues, respectively.
•
West Penn was incorporated in Pennsylvania in 1916. It operates an electric T&D system in southwestern, north and south-central Pennsylvania. West Penn serves approximately 698,000 customers in a service area of about 9,900 square miles with a population of approximately 1,508,000. West Penn’s 2004 total operating revenues were $1,165.9 million.
The Distribution Companies assess delivery charges when other power suppliers transmit power along the Distribution Companies’ transmission grids. In April 2002, the Distribution Companies transferred operational control over their transmission systems to PJM. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.
•
Allegheny Ventures is a nonutility, unregulated subsidiary of AE that was incorporated in Delaware in 1994. Allegheny Ventures engages in telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal wholly-owned subsidiaries, ACC and AE Solutions. Both ACC and AE Solutions are Delaware corporations. ACC develops fiber-optic projects, including fiber and data services. AE Solutions manages energy-related projects.
During 2004, the Delivery and Services segment had operating revenues of $2,764.1 million and net income of $103.3 million. At December 31, 2004, the Delivery and Services segment held $4.4 billion of identifiable assets. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “Business Segments,” to the Consolidated Financial Statements.
The Generation and Marketing Segment
The principal companies and operations in AE’s Generation and Marketing segment include the following:
•
AE Supply is a Delaware limited liability company formed in 1999 and a registered holding company under PUHCA. AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities, although it no longer engages in speculative trading. As of December 31, 2004. AE Supply owned or contractually controlled 8,728 MW of generation capacity. AE Supply markets the Generation and Marketing segment’s electric generation capacity to various customers and markets. Currently, the majority of the Generation and Marketing segment’s normal operating capacity is committed to supplying the PLR and other obligations of the Distribution Companies. AE Supply’s 2004 total operating revenues were $1,270.3 million.
•
Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment. As of December 31, 2004, Monongahela owned or contractually controlled 2,123 MWs of generation capacity. Monongahela’s Generation and Marketing segment had operating revenues of $312.8 million in 2004.
•
AGC was incorporated in Virginia in 1981. AGC is owned approximately 77% by AE Supply and approximately 23% by Monongahela. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric station and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 985 MW share of generation capacity from the Bath County generation station to AE Supply and Monongahela. AGC’s 2004 total operating revenues were $69.2 million.
AE Supply is obligated under long-term contracts to provide the Distribution Companies with the power that they need to meet a majority of their PLR obligations. The Generation and Marketing segment sells power into PJM and purchases power from PJM to meet its obligations to the Distribution Companies under these contracts. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.
Although most of the Generation and Marketing segment’s generation capacity participates in the PJM system, it owns generation capacity outside of PJM, including AGC’s interest in the Bath County generation station and generation facilities in Gleason, Tennessee and Wheatland, Indiana. The Gleason and Wheatland generation facilities have been classified as held for sale, and their results have been presented as discontinued operations in the accompanying Consolidated Statements of Operations.
During 2004, the Generation and Marketing segment had operating revenues of $1,538.7 million and a net loss of $413.9 million. At December 31, 2004, the Generation and Marketing segment held $4.4 billion of identifiable assets. See “Managements Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “Business Segments,” to the Consolidated Financial Statements.
Intersegment Services
AESC was incorporated in Maryland in 1963 as a service company for AE. AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures and their respective subsidiaries have no employees. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had approximately 5,100 employees as of December 31, 2004.
The PJM Market and the Distribution Companies’ PLR Obligations
Allegheny’s business has been significantly influenced by state and federal deregulation initiatives, including the implementation of retail choice and plans to transition from cost-based to market-based rates, as well as by the development of wholesale electricity markets and RTOs, particularly PJM.
The Distribution Companies have PLR obligations to their customers in Pennsylvania, Maryland, Virginia and Ohio. AE Supply has long-term contracts with the Distribution Companies under which AE Supply provides the Distribution Companies with the majority of the power necessary to meet their PLR obligations. A majority of Allegheny’s generation assets participate in the PJM system, and most of the power that the Generation and Marketing segment generates is sold into PJM. Allegheny expects to sell power in excess of the Distribution Companies’ PLR obligations at market prices. Prevailing market prices are generally higher than the capped rates currently applicable to these PLR obligations.
For a more detailed discussion, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Overview.”
Challenges and Response
Prior to 1999, Allegheny functioned as an integrated regulated utility within its service area. In response to federal and state deregulation initiatives, however, Allegheny separated its energy generation business from its T&D business by transferring generation assets to AE Supply. Allegheny’s former senior management sought to transform AE Supply into a national power merchant in order to capitalize on these regulatory and other energy industry trends. As part of this strategy, AE Supply acquired generation assets, which collectively expanded Allegheny’s owned or controlled generation capacity by nearly one-third. AE Supply also began construction of new generation facilities. In addition, AE Supply purchased the energy trading division of Merrill Lynch in 2001. With this acquisition, the focus of AE Supply’s energy trading shifted from asset backed, short-term trading in and around its generation assets to more speculative trading activities. This expansion was financed primarily through debt.
Beginning in 2002, difficult market conditions, changes in the regulatory environment and Allegheny’s worsening credit profile placed Allegheny in a weakened financial position, which continued during 2003 and into 2004. Beginning in 2003, Allegheny’s new senior management implemented recovery plans and new long-term strategies.
Allegheny’s long-term strategy is to focus on its core generation and T&D businesses. Allegheny’s management believes that this emphasis will enable Allegheny to take advantage of its regional presence, operational expertise and knowledge of its markets. Specific goals for enhancing long-term value include:
•
Restoring Financial Strength. Beginning in 2003, Allegheny significantly improved its liquidity and overall financial strength. Allegheny’s management believes that it can continue this trend by:
•
Focusing on the Core Business. Allegheny has reoriented its business to focus on its core businesses and assets. In 2003, Allegheny exited its speculative trading activities in the Western U. S. and other energy markets. In addition, Allegheny has sold or is seeking to sell non-core assets.
•
Substantially Reducing and Proactively Managing Debt. Between December 1, 2003 and January 31, 2005, Allegheny repaid approximately $1.2 billion of debt. Allegheny’s goal is to reduce its debt by an additional $300 million by the end of 2005. Allegheny intends to continue its debt reduction efforts by applying some of its cash flow from operations and the proceeds from asset sales to the repayment of debt. The extent to which Allegheny utilizes these alternatives will depend upon the terms that are available to it and their impact on its financial condition, long-term value and overall strategy.
•
Improving Liquidity. Allegheny is improving its liquidity through prudent cash management, opportunistic sales of non-core assets, cutting costs and expenses, extending debt maturities and obtaining a revolving credit facility. For example, in December 2004, AE Supply completed the sale of its 672 MW natural gas-fired Lincoln Generating Facility, located in Manhattan, Illinois and an accompanying tolling agreement for $175.0 million in cash, subject to certain post-closing adjustments. Also in December 2004, AE sold a portion of its interest in OVEC for $102 million in cash, $96 million of which was received at the closing of the transaction and the remaining $6 million of which is expected to be paid after March 13, 2006, upon the satisfaction of certain conditions. The proceeds of these transactions were used to repay debt. AE and AE Supply also completed refinancings in 2004 that extended the maturities and lowered the interest rates of much of their debt and established a revolving credit facility for AE.
•
Maximizing Operational Efficiency. Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation plants. In addition, Allegheny is seeking to optimize operations and maintenance costs for its generation facilities and T&D assets and related corporate functions, to reduce costs and to pursue other productivity improvements necessary to build a high-performance organization.
•
Maximizing Generation Value. Allegheny is working to maximize the value of the power that it generates by ensuring full recovery of its costs and a reasonable return through the traditional rate-making process for its regulated utilities, as well as through the transition to market-based rates for AE Supply and its subsidiaries.
•
Managing Environmental Compliance and Risks. Allegheny is working to effectively manage its environmental compliance efforts to ensure continuing compliance with applicable federal and state regulations while controlling its compliance costs, reducing emissions levels and minimizing its risk exposure.
•
Rebuilding the Management Team. Allegheny rebuilt its management team in 2003 and 2004.
Where You Can Find More Information
AE, Monongahela, Potomac Edison and AGC file or furnish Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements (for AE) and other information with or to the SEC. You may read and copy any document that the registrants file with the SEC at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. These SEC filings are also available to the public from the SEC’s website at http://www.sec.gov.
The Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements, statements of changes in beneficial ownership and other SEC filings, and any amendments to those reports, that AE, Monongahela, Potomac Edison and AGC file with or furnish to the SEC under the Exchange Act are made available free of charge on AE’s website at http://www.alleghenyenergy.com as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. Audited annual financial statements for AE Supply and West Penn, neither of which is a reporting company under the Exchange Act, also will be available on AE’s website. AE’s website and the information contained therein are not incorporated into this report.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
In addition to historical information, this report contains a number of forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Words such as anticipate, expect, project, intend, plan, believe and words and terms of similar substance used in connection with any discussion of future plans, actions or events identify forward-looking statements. These include statements with respect to:
•
regulation and the status of retail generation service supply competition in states served by the Distribution Companies;
•
financing plans;
•
demand for energy and the cost and availability of raw materials, including coal;
•
PLR and power supply contracts;
•
results of litigation;
•
results of operations;
•
internal controls and procedures;
•
capital expenditures;
•
status and condition of plants and equipment;
•
regulatory matters; and
•
accounting issues.
Forward-looking statements involve estimates, expectations and projections and, as a result, are subject to risks and uncertainties. There can be no assurance that actual results will not differ materially from expectations. Actual results have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, among others, the following:
•
changes in the price of power and fuel for electric generation;
•
general economic and business conditions;
•
changes in access to capital markets;
•
complications or other factors that make it difficult or impossible to obtain necessary lender consents or regulatory authorizations on a timely basis;
•
environmental regulations;
•
the results of regulatory proceedings, including proceedings related to rates;
•
changes in industry capacity, development and other activities by Allegheny’s competitors;
•
changes in the weather and other natural phenomena;
•
changes in the underlying inputs and assumptions, including market conditions, used to estimate the fair values of commodity contracts;
•
changes in laws and regulations applicable to Allegheny, its markets or its activities;
•
the loss of any significant customers or suppliers;
•
dependence on other electric transmission and gas transportation systems and their constraints or availability;
•
changes in PJM, including changes to participant rules and tariffs;
•
the effect of accounting guidance issued periodically by accounting standard-setting bodies; and
•
the continuing effects of global instability, terrorism and war.
RISK FACTORS
Allegheny is subject to a variety of significant risks in addition to the matters set forth under “Special Note Regarding Forward-Looking Statements” above. Allegheny’s susceptibility to certain risks could exacerbate other risks. These risk factors should be considered carefully in evaluating Allegheny’s risk profile. Risks applicable to Allegheny include:
Risks Relating to Regulation
Allegheny is subject to substantial governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits and certificates may result in substantial costs to Allegheny.
Allegheny is subject to substantial regulation from federal, state and local regulatory agencies. Allegheny is required to comply with numerous laws and regulations and to obtain numerous authorizations, permits, approvals and certificates from governmental agencies. These agencies regulate various aspects of Allegheny’s business, including customer rates, service regulations, retail service territories, generation plant operations, sales of securities, asset sales and accounting policies and practices.
Allegheny is also subject to regulation by the SEC under PUHCA, which imposes a number of restrictions on the operations of registered utility holding companies and their subsidiaries. These restrictions include a requirement that, subject to a number of exceptions, the SEC approve in advance securities issuances, financings, acquisitions and dispositions of utility assets, or of securities of utility companies, and acquisitions by utility companies of other businesses. With limited exceptions, PUHCA requires that transactions between affiliated companies in a registered holding company system be performed at cost.
Allegheny cannot predict the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to it. Changes in regulations or the imposition of additional regulations could influence Allegheny’s operating environment and may result in substantial costs to Allegheny.
Allegheny’s costs to comply with environmental laws are significant, and the cost of compliance with present and future environmental laws could adversely affect its cash flow and profitability.
Allegheny’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and site remediation. Compliance with these laws and regulations may require Allegheny to expend significant financial resources to, among other things, meet air emission standards, conduct site remediation, perform environmental monitoring, purchase emission allowances, use alternative fuels and modulate operations of its generation facilities in order to reduce emissions. If Allegheny fails to comply with applicable environmental laws and regulations, even if it is unable to do so due to factors beyond its control, it may be subject to civil liabilities or criminal penalties and may be required to incur significant expenditures to come into compliance. Alleged violations of environmental laws and regulations may require Allegheny to expend significant resources defending itself against these claims.
New environmental laws and regulations, or new interpretations of existing laws and regulations, could impose more stringent limitations on Allegheny’s generation operations or require it to incur significant additional costs.
Applicable standards under the EPA’s NSR initiatives remain in flux. Under the Clean Air Act, modification of Allegheny’s generation facilities in a manner that causes increased emissions could subject Allegheny’s
existing facilities to the far more stringent NSR standards applicable to new facilities. The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work believed by the companies to be routine maintenance.
On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue from the Attorneys General of Connecticut, New Jersey and New York and the Pennsylvania Department of Environmental Protection (“PADEP”) alleging that they made major modifications to some of their coal-fired generation facilities in West Virginia and Pennsylvania in violation of the Prevention of Significant Deterioration provisions of the Clean Air Act. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal district court in West Virginia on January 6, 2005. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired power plants in West Virginia and Pennsylvania are in compliance with the Clean Air Act. The Attorneys General have filed a motion to dismiss the declaratory judgment action. If the action is dismissed based upon their motion, the Attorneys General may file an enforcement action against Allegheny in federal court in Pennsylvania. It is also possible that the EPA and other state authorities may join in the current declaratory judgment action or, if it is dismissed, a new action filed by the Attorneys General.
In December 2004, Pennsylvania adopted Renewable Portfolio Standard legislation. The new legislation requires that, by 2020, 18% of the energy used in Pennsylvania be derived from renewable and alternative sources. The new legislation includes a five-year exemption from this requirement for companies, such as the Distribution Companies, that are operating within transition periods under the current regulations governing the transition to market competition in Pennsylvania. The full requirement will apply to those companies when the applicable transition periods end. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative energy sources are not reasonably available. Similar legislation has been adopted in Maryland. The Maryland law goes into effect on the later of the termination of the applicable transition period or July 1, 2006. See “Regulatory Framework Affecting Allegheny” below.
In addition, Allegheny incurs costs to obtain and comply with a variety of environmental permits, licenses, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if Allegheny fails to obtain, maintain or comply with any required approval, operations at affected facilities could be halted or subjected to additional costs.
For additional information regarding environmental matters, see “Environmental Matters” below.
Shifting state and federal regulatory policies impose risks on Allegheny’s operations and capital structure.
Allegheny’s operations are subject to evolving regulatory policies, including initiatives regarding deregulation of the production and sale of electricity and the restructuring of transmission regulation. State or federal regulators may also take regulatory action as a result of the power outages that affected the Northeast and Midwest United States and Canada in August 2003. Any new requirements arising from these actions could lead to increased operating expenses and capital expenditures, the amount of which cannot be predicted at this time.
The continuation of below-market retail rate caps beyond the original scheduled end of transition periods could have adverse consequences for Allegheny. In the absence of a long-term power supply contract with a power generator, the Distribution Companies must purchase their power requirements at negotiated or market prices, whether from AE Supply or an alternative supplier. If retail rates are capped below the prices at which the Distribution Companies can obtain power, the power will be sold at a loss. Legislators, regulators and consumer and other groups have sought to extend retail rate regulation in the states in which the Distribution Companies do
business through a variety of mechanisms, including through the extension of the current rate cap regimes, which are set below current market prices. Allegheny cannot predict to what extent these efforts will be successful. See “Regulatory Framework Affecting Allegheny” below.
Delays, discontinuations or reversals of electricity market restructurings in the markets in which Allegheny operates could have a material adverse effect on its results of operations and financial condition. At a minimum, these types of actions raise uncertainty concerning the continued development of competitive power markets. Given Allegheny’s multi-state operations and asset base, re-regulation of restructured obligations could prove intricate and time-consuming and could lead to complications within its capital structure.
In addition, as a result of FERC’s efforts to implement a long-term rate design for the Midwest and Mid-Atlantic regions, the Distribution Companies may not fully recover their transmission costs and may have costs shifted to them from other transmission owners. Due to capped rates and the timing of state rate cases, the Distribution Companies may not be able to pass through increased transmission costs to these retail customers for some period of time.
Risks Related to Allegheny’s Substantial Debt
Covenants contained in Allegheny’s principal financing agreements restrict its operating, financing and investing activities.
Allegheny’s principal financing agreements contain restrictive covenants that limit its ability to, among other things:
•
borrow funds;
•
incur liens and guarantee debt;
•
enter into a merger or other change of control transaction;
•
make investments;
•
prepay debt;
•
amend contracts; and
•
pay dividends and other distributions on its equity securities.
These agreements limit Allegheny’s ability to implement strategic decisions, including its ability to access capital markets or sell assets without using the proceeds to reduce debt. In addition, Allegheny is required to meet certain financial tests under some of its loan agreements, including interest coverage ratios and leverage ratios. Allegheny’s failure to comply with the covenants contained in its financing agreements could result in an event of default, which could materially and adversely affect its financial condition.
Allegheny’s substantial debt could adversely affect its ability to operate successfully and meet contractual obligations.
Allegheny is substantially leveraged. One of its principal challenges is to manage its debt while continuing the long-term process of reducing the amount of its debt. At December 31, 2004, Allegheny had $5.0 billion of debt on a consolidated basis (including discontinued operations). Approximately $700 million of that amount represented AE’s obligations, $2.8 billion represented debt of AE Supply and AGC and the remainder constituted debt of one or more of the Distribution Companies.
Allegheny’s substantial debt could have important consequences to it. For example, it could:
•
make it more difficult for Allegheny to satisfy its obligations under the agreements governing its debt;
•
require Allegheny to dedicate a substantial portion of its cash flow from operations to payments on its debt, thereby reducing the availability of its cash flow for working capital, capital expenditures and other general corporate purposes;
•
limit Allegheny’s flexibility in planning for, or reacting to, changes in its business, regulatory environment and the industry in which it operates;
•
place Allegheny at a competitive disadvantage compared to its competitors that have less debt;
•
limit Allegheny’s ability to borrow additional funds; and
•
increase Allegheny’s vulnerability to general adverse economic, regulatory and industry conditions.
Allegheny may be unable to engage in desired financing transactions.
Allegheny has substantial debt service obligations for the foreseeable future and may need to engage in refinancing and capital-raising transactions in order to pay interest and retire principal. Allegheny also may undertake other types of financing transactions in order to meet its other financial needs and increase its equity ratios. Allegheny may be unable to successfully complete financing transactions due to a number of factors, including:
•
its equity ratios, which are below the minimum levels required under its PUHCA financing authorizations;
•
its credit ratings, most of which are currently below investment grade;
•
its overall financial condition and results of its operations; and
•
volatility in the capital markets.
Allegheny currently anticipates that, in order to repay the principal of its outstanding debt, it may undertake one or more financing alternatives, such as refinancing or restructuring its debt, selling assets, reducing or delaying capital investments or raising additional capital. Allegheny can make no assurance that it can complete any of these types of financing transactions on terms satisfactory to it or at all, that any financing transaction would enable it to pay the interest or principal on its debt or meet its other financial needs or that any of these alternatives would be permitted under the terms of the agreements governing its outstanding debt.
Allegheny’s credit ratings and trading market liquidity may make it difficult for it to hedge its physical power supply commitments and resource requirements.
While Allegheny has made significant progress retiring unnecessary positions in the Western U.S. and other energy markets, its current credit ratings, together with a lack of market liquidity have made it difficult for it to retire a small number of remaining energy market positions. Market liquidity has significantly declined over the past three years. Absent a return to more liquid levels combined with an improvement in Allegheny’s credit ratings, it may not be possible for Allegheny to retire these remaining positions.
Allegheny’s credit position has also made it difficult for it to hedge its power supply obligations and fuel requirements. In the absence of effective hedges for these purposes, Allegheny must satisfy power shortfalls in the spot markets, which are volatile and can be more costly than expected.
Allegheny’s risk management, wholesale marketing, fuel procurement and energy trading activities, including its decisions to enter into power sales or purchase agreements, rely on models that depend on judgments and assumptions regarding factors such as the future market prices and demand for electricity and other energy-related commodities. Even when Allegheny’s policies and procedures are followed and decisions are made based on these models, its financial position and results of operations may be adversely affected if the judgments and assumptions underlying those models prove to be inaccurate.
Risks Relating to Allegheny’s Operations
Allegheny’s generation facilities are subject to unplanned outages and significant maintenance requirements.
The operation of power generation facilities involves many risks, including the risk of breakdown or failure of equipment, fuel interruption and performance below expected levels of output or efficiency. If Allegheny’s facilities, or the facilities of other parties upon which it depends, operate below expectations, Allegheny may lose revenues, have increased expenses or fail to receive the amount of power for which it has contracted.
Many of Allegheny’s facilities were originally constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to operate at peak efficiency or availability. If Allegheny underestimates required maintenance expenditures or is unable to make required capital expenditures due to liquidity constraints, it risks incurring more frequent unplanned outages, higher than anticipated maintenance expenditures, increased operation at higher cost of some of its less efficient generation facilities and the need to purchase power from third parties to meet its supply obligations.
Allegheny’s operating results are subject to seasonal and weather fluctuations.
Electrical power generation is generally a seasonal business, and weather patterns can have a material impact on Allegheny’s operating performance. Demand for electricity peaks during the summer and winter months, and market prices typically also peak during these times. During periods of peak demand, the capacity of Allegheny’s generation facilities may be inadequate, which could require it to purchase power at a time when the market price for power is very high. In addition, although the operational costs associated with the Delivery and Services segment are not weather-sensitive, the segment’s revenues are subject to seasonal fluctuation. Accordingly, Allegheny’s annual results and liquidity position may depend disproportionately on its performance during the winter and summer.
Allegheny’s revenues, costs and results of operations are subject to other risks beyond its control, including, but not limited to, accidents, storms, natural catastrophes and terrorism.
Much of the value of Allegheny’s business consists of its portfolio of power generation and T&D assets. Allegheny’s ability to conduct its operations depends on the integrity of these assets. The cost of repairing damage to its facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events may exceed reserves or insurance, if any, for repairs, which may adversely impact Allegheny’s results of operations and financial condition. Although Allegheny has taken, and will continue to take, reasonable precautions to safeguard these assets, Allegheny can make no assurance that its facilities will not face damage or disruptions or that it will have sufficient reserves or insurance to cover the cost of repairs. In addition, in the current geopolitical climate, enhanced concern regarding the risks of terrorism throughout the economy may impact Allegheny’s operations in unpredictable ways. Insurance coverage may not cover costs associated with any of these risks adequately or at all.
The terms of AE Supply’s power sale agreements with the Distribution Companies could require AE Supply to sell power below its costs or prevailing market prices or require the Distribution Companies to purchase power at a price above which they can sell power.
In connection with regulations governing the transition to market competition, the Distribution Companies are required to provide electricity at capped rates to retail customers who do not choose an alternate electricity generation supplier or who return to utility service from alternate suppliers. The Distribution Companies satisfy the majority of these obligations by purchasing power from AE Supply under long-term agreements. Those agreements provide for the supply of a significant portion of the Distribution Companies’ energy needs at the
mandated capped rates and for the supply of a specified remaining portion at rates based on market prices. The amount of energy priced at market rates increases over each contract term. The majority of AE Supply’s normal operating capacity is dedicated to these contracts with the Distribution Companies.
These power supply agreements present risks for both AE Supply and the Distribution Companies. At times, AE Supply may not earn as much as it otherwise could by selling power priced at capped rates to the Distribution Companies instead of into competitive wholesale markets. In addition, AE Supply’s obligations under these power supply agreements could exceed its available generation capacity, which may require AE Supply to buy power at prices that are higher than the sale prices in the power supply agreements. Changes in customer switching behavior could also alter AE Supply’s obligations under these agreements. Conversely, the Distribution Companies’ capped rates may be below current wholesale market prices through the applicable transition periods. As a consequence, the Distribution Companies may at times pay more for power than they can charge retail customers and may be unable to pass the excess costs on to their retail customers.
The supply and price of fuel and emissions credits may impact Allegheny’s financial results.
Allegheny is dependent on coal for much of its electric generation capacity. Allegheny has coal supply contracts in place that partially mitigate its exposure to negative fluctuations in coal prices. Allegheny can make no assurance, however, that the counterparties to these agreements will fulfill their obligations to supply coal. The suppliers under these agreements may experience financial or technical problems that inhibit their ability to fulfill their obligations. In addition, the suppliers under these agreements may not be required to supply coal to Allegheny under certain circumstances, such as in the event of a natural disaster. If Allegheny is unable to obtain its coal requirements under these contracts, it may be required to purchase coal at higher prices, which could have a material adverse effect on its financial condition, cash flow and results of operations.
Allegheny estimates that it may purchase sulfur dioxide (“SO2”) emission allowances for up to 50,000 tons for 2005 and an average of approximately 100,000 tons per year for 2006 through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced, and the type of fuel used, by its generation facilities. Fluctuations in the availability or cost of emission allowances could have a material adverse effect on Allegheny’s results of operations, cash flows and financial condition.
Allegheny is currently involved in significant litigation that, if not decided favorably to Allegheny, could materially adversely affect its results of operations, cash flows and financial condition.
Allegheny is currently involved in a number of lawsuits, including lawsuits relating to breach of contract and its involvement in the energy trading business. Allegheny intends to vigorously pursue these matters, but the results of these lawsuits cannot be determined. Adverse outcomes in these lawsuits could require Allegheny to make significant expenditures and could have a material adverse effect on its results of operations, cash flows and financial condition. See “Legal Proceedings.”
The Distribution Companies and other AE subsidiaries are and may become subject to legal claims arising from the presence of asbestos or other regulated substances at some of their facilities.
The Distribution Companies have been named as defendants in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at Allegheny-owned facilities where suitable alternative materials are not available. Allegheny’s management believes that any remaining asbestos at Allegheny-owned facilities is contained. The continued presence of asbestos and other regulated substances at Allegheny-owned facilities, however, could result in additional actions being brought against Allegheny. See “Legal Proceedings.”
Allegheny may be required to make significant contributions to satisfy underfunded pension liabilities.
Allegheny’s underfunded pension liabilities have increased in recent periods due to declining interest rates and financial market performance and because of the implementation of early retirement initiatives to reduce headcount. Allegheny made a total contribution to pension plans during 2004 of $27.7 million, including $0.3 million to the SERP. Minimum required funding contributions are anticipated to increase beyond 2004. However, these anticipated mandatory contributions will change in the future if Allegheny’s assumptions regarding prevailing interest rates change, if actual investments under-perform or out-perform expectations or if actuarial assumptions or asset valuation methods change.
Allegheny also contributed $28.1 million to its postretirement benefits other than pensions in 2004. These costs may increase in 2005.
Changes in PJM market policies and rules may impact Allegheny’s financial results.
Substantially all of Allegheny’s generation assets and power supply obligations are located within the PJM market. Any changes in PJM policies or market rules, including changes that are currently under consideration by FERC, could adversely affect Allegheny’s financial results.
Energy companies are subject to adverse publicity, which may make Allegheny vulnerable to negative regulatory and litigation outcomes.
The energy sector has been the subject of highly-publicized allegations of misconduct. Negative publicity of this nature may make legislatures, regulatory authorities and tribunals less likely to view energy companies favorably, which could cause them to make decisions or take actions that are adverse to Allegheny. Power outages, such as those that affected the Northeast and Midwest United States and Canada in August 2003, could exacerbate negative sentiment regarding the energy industry.
Allegheny is dependent on its ability to successfully access capital markets. An inability to access capital may adversely affect Allegheny’s business.
Allegheny relies on access to the capital markets as a source of liquidity and to satisfy any of its capital requirements that are not met by the cash flow from its operations. Capital market disruptions, or a downgrade in Allegheny’s credit ratings, could increase Allegheny’s cost of borrowing or could adversely affect its ability to access one or more financial markets. Disruptions to the capital markets could include, but are not limited to:
•
a recession or an economic slowdown;
•
the bankruptcy of one or more energy companies or highly-leveraged companies;
•
significant increases in the prices for oil or other fuel;
•
a terrorist attack or threatened attacks;
•
a significant transmission failure; or
•
changes in technology.
Risks Relating to Internal Controls and Procedures and Operational Enhancements
Allegheny’s internal controls and procedures have been substantially deficient, and it continues to expend significant resources to improve internal controls and procedures.
In August 2002, Allegheny’s independent registered public accounting firm, PricewaterhouseCoopers LLP (“PwC”), advised Allegheny that it considered AE’s and its subsidiaries’ internal controls to have material
weaknesses. The term “material weakness” refers to an organization’s internal control deficiency in which the design or operation of a component of internal control does not reduce to a relatively low level the risk that a material misstatement may be contained in the organization’s financial statements. In March 2004, PwC advised AE’s Audit Committee that although management had made significant progress in addressing the specific control weaknesses previously identified, not all of these deficiencies had been remedied and certain internal control weaknesses remained. In September 2004, PwC advised AE’s Audit Committee that certain material weaknesses remained and required remediation. As of December 31, 2004, these material weaknesses have been remediated, although some deficiencies remain. Allegheny intends to expend additional resources to further improve its internal controls.
Refocusing its business subjects Allegheny to risks and uncertainties.
Since late 2002, Allegheny has been reassessing the business environment, its position within the energy industry and its relative strengths and weaknesses. As a result of this reassessment, Allegheny has implemented significant changes to its operations as part of its overall strategy to function as an integrated utility company, to the extent practicable and permissible under relevant regulatory constraints. For example, Allegheny has reduced the size of its workforce and made substantial changes to senior management. Additional changes to Allegheny’s business will be considered as management seeks to strengthen financial and operational performance. These changes may be disruptive to Allegheny’s established organizational culture and systems. In addition, consideration and planning of strategic changes diverts management attention and other resources from day to day operations.
Allegheny may engage in sales of assets and businesses; however, market conditions and other factors may hinder this strategy.
Allegheny may continue to sell non-core assets. Sales prices for energy assets and businesses could fluctuate due to prevailing conditions. Asset sales under poor market conditions could result in substantial losses. Buyers also may find it difficult to obtain financing to purchase these assets. As part of any asset sale, Allegheny faces challenges associated with valuing the assets correctly and limiting its environmental or other retained liabilities. These transactions also may divert management attention and other resources from day to day operations.
Several factors specific to Allegheny could make asset sales particularly challenging. Allegheny and potential purchasers are subject to regulatory approvals, which can impose delays and structuring complications on asset sale transactions. Potential buyers may be reluctant to enter into agreements to purchase assets from Allegheny if they believe that required consents and approvals will result in significant delays or uncertainties in the transaction process.
Allegheny may fail to realize the benefits that it expects from its cost-savings initiatives.
Allegheny has undertaken and expects to continue to undertake cost-savings initiatives. However, Allegheny can make no assurance that it will realize on-going cost savings or any other benefits from these initiatives. Even if Allegheny realizes the benefits of its cost savings initiatives, any cash savings that it achieves may be offset by other costs, such as environmental compliance costs and higher fuel, operating and maintenance costs, or could be passed on to customers through revised rates. Staff reductions may reduce Allegheny’s workforce below the level needed to effectively manage its business and service its customers. Allegheny’s failure to realize the anticipated benefits of its cost-savings initiatives could have a material adverse effect on its business, results of operations and financial condition.
ALLEGHENY’S SALES AND REVENUES
The Generation and Marketing Segment’s Sales and Revenues
The Generation and Marketing segment had operating revenues of $1,538.7 million and $956.2 million in 2004 and 2003, respectively. For more information regarding the Generation and Marketing segment’s operating revenues, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 12, “Business Segments,” to the Consolidated Financial Statements.
The Delivery and Services Segment’s Sales and Revenues
The Delivery and Services segment had operating revenues of $2,764.1 million and $2,705.8 million in 2004 and 2003, respectively. These revenues included revenue from electric sales, regulated natural gas sales and unregulated services. The following tables describe the segment’s kWh sales and revenues from electric sales:
Intersegment Eliminations
Revenues from natural gas sales have been reclassified to discontinued operations. These revenues included:
For more information regarding the Delivery and Services segment’s revenues, see “Management’s Discussion and Analysis of Financial Condition and Operating Results” and Note 12, “Business Segments,” to the Consolidated Financial Statements.
CAPITAL EXPENDITURES
The table below shows total capital expenditures for Allegheny in 2004 and estimated capital expenditures for 2005 and 2006, as well as the environmental control expenditures that are included in these capital expenditures or estimated capital expenditures.
The Delivery and Services segment’s capital expenditures of $160.5 million for 2004 are shown net of $10.8 million in proceeds from the sale of land by WVP.
The Generation and Marketing segment’s capital expenditures include projects at generation facilities for environmental control upgrades and to remediate or prevent equipment failure. The Delivery and Services segment’s capital expenditures include projects to upgrade distribution lines and substations, as well as transmission and subtransmission systems enhancements. The amounts shown above include allowance for funds used during construction (“AFUDC”) for the Distribution Companies. AFUDC includes the non-cash cost, for the period of construction, of borrowed funds used for construction purposes and a reasonable rate on other funds used in construction.
AE Supply ceased construction of, or planning for, several generation projects in 2002 in response to market conditions, including overcapacity and lower wholesale power prices, and to conserve liquidity. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 7, “Asset Impairments,” to the Consolidated Financial Statements for information regarding charges for discontinued generation projects.
ELECTRIC FACILITIES
All of Allegheny’s owned or controlled generation capacity is part of the Generation and Marketing segment and is owned or controlled by AE, AE Supply, Monongahela or AGC. In addition, the Distribution Companies are obligated to purchase 479 MW of power through state utility commission-approved arrangements pursuant to PURPA. This PURPA capacity is part of the Delivery and Services segment. See “PURPA Capacity” below.
Allegheny’s owned and controlled capacity as of December 31, 2004 was 10,851 MW, of which 7,819 MW (72.1%) were coal-fired, 1,907 MW (17.6%) were natural gas-fired, 1,043 MW (9.6%) were pumped-storage and hydroelectric and 82 MW (0.7%) were oil-fired. These amounts include capacity to which AE Supply is entitled in conjunction with AE’s sale of a portion of its interest in OVEC.
AE holds a 3.5% equity stake in, and is a sponsoring company of, OVEC. Currently, AE Supply and Monongahela are entitled to 9% (203 MW) and 3.5% (78 MW), respectively, of OVEC capacity. OVEC supplies power to its sponsoring companies under an intercompany power agreement that expires on March 12, 2006. In December 2004, AE sold a 9% equity interest in OVEC to Buckeye Power Generating, LLC (“Buckeye”). In addition, AE Supply assigned to Buckeye all of its rights and obligations under a new OVEC intercompany power agreement effective on March 13, 2006. AE Supply retained its rights under the current agreement to 9% of the power from the OVEC electric generation facilities through March 12, 2006.
In December 2004, AE Supply sold its subsidiary, Allegheny Energy Supply Lincoln Generating Facility, LLC (“Lincoln”). Lincoln’s assets included the 672 MW natural gas-fired Lincoln Generating Facility located in Manhattan, Illinois. AE Supply is also currently seeking to sell its Gleason Generating Facility in Gleason, Tennessee and its Wheatland Generating Facility in Wheatland, Indiana.
The following table shows the nominal maximum operational generation capacity owned or controlled by Allegheny, as of December 31, 2004. This generation is included in the Generation and Marketing segment.
Nominal Maximum Operational Generation Capacity (MW)
(a)
When more than one year is listed as a commencement date for a particular station, the dates refer to the years in which operations commenced for the different units at that station.
(b)
This figure represents capacity entitlement through AE’s ownership of OVEC shares. In December 2004, AE sold a 9% equity interest in OVEC. However, AE Supply will retain its right to 9% of the power from OVEC electric generation facilities through March 12, 2006. AE holds a 3.5% equity interest in OVEC, which entitles Monongahela to 3.5% of the power from OVEC generation facilities.
(c)
This figure represents capacity entitlement of Allegheny Energy Supply Hunlock Creek, LLC (“Hunlock”) through its 50% ownership in Hunlock Creek Energy Ventures, LLC (“Hunlock Creek”). Hunlock’s entitlement to Hunlock Creek output at maximum generation capacity is indicated on the table for the steam and natural gas-fired facilities. This output is sold exclusively to AE Supply.
(d)
This figure represents capacity entitlement through ownership of AGC.
(e)
AE Supply has a license for Lake Lynn through 2024.
(f)
Green Valley Hydro’s license for hydroelectric facilities Dam No. 4 and Dam No. 5, located in West Virginia and Maryland will expire November 30, 2024. Potomac Edison has licenses through 2024 for the Shenandoah, Warren, Luray and Newport projects located in Virginia.
(g)
Buchanan Energy Company of Virginia, LLC, a subsidiary of AE Supply (“Buchanan”), is part-owner of Buchanan Generation LLC (“Buchanan Generation”). Consol Energy, Inc. and Buchanan have equal ownership interests in Buchanan Generation. AE Supply operates and dispatches 100% of Buchanan Generation’s 86 MW.
Significant 2004 Outages
On November 3, 2003, a fire occurred in Unit No. 2 at the Hatfield’s Ferry generation station located near Masontown, Pennsylvania. Hatfield’s Ferry Unit No. 2 is a 570 MW coal-fired generation unit owned by AE Supply and Monongahela. As a result of the fire, the unit’s generator, turbine and certain associated equipment sustained significant damage. On February 9, 2004, a generator failure occurred in Unit No. 1 at the Pleasants generation station located in Willow Island, West Virginia. Pleasants Unit No. 1 is a 650 MW coal-fired generation unit owned by AE Supply and Monongahela. As a result of the generator failure, the unit’s generator and associated equipment sustained damage. Both units returned to service in June 2004.
As a result of these outages, Allegheny had less power to sell into the PJM market, and its operating results were adversely affected. The estimated lost revenues (net of fuel cost savings) associated with the Hatfield’s Ferry and Pleasants outages were approximately $58 million and $35 million, respectively, for 2004. Allegheny continues to pursue additional insurance recoveries in connection with these outages.
PURPA Capacity
The following table shows additional generation capacity available to the Distribution Companies through state utility commission-approved arrangements pursuant to PURPA. PURPA requires electric utility companies, such as the Distribution Companies, to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities. The amounts shown in this table are included in the Delivery and Services segment. See “Regulatory Framework Affecting Allegheny-Federal Regulation and Rate Matters-PURPA” below.
(a)
As required under the terms of a Maryland restructuring settlement, Potomac Edison began to offer the 180 MW output of the AES Warrior Run project to the wholesale market beginning July 1, 2000 and will continue to do so for the term of the AES Warrior Run contract, which ends on February 10, 2030. Revenue received from the sale reduces the AES Warrior Run surcharge paid by Maryland customers. As of January 1, 2005, AES Warrior Run output is being sold to a non-affiliated third party.
The following table sets forth the existing miles of tower and pole T&D lines and the number of substations of the Distribution Companies and AGC as of December 31, 2004:
(a)
Total Bath County transmission lines, of which AGC owns an undivided 40% interest and Virginia Electric and Power Company owns the remainder.
The Distribution Companies’ transmission network has 12 extra-high-voltage (345 kV and above) and 31 lower-voltage interconnections with neighboring utility systems.
FUEL, POWER AND RESOURCE SUPPLY
Generation and Marketing Segment
Coal Supply
Allegheny purchased 16.9 million tons of coal in 2004 at an average price of $30.53 per ton delivered. Allegheny purchased this coal primarily from mines in Pennsylvania, West Virginia and Ohio. However, Allegheny considers sources of coal supply from other viable regions. During 2004, Allegheny conducted test burns of Powder River Basin coal from Wyoming at several generation facilities.
Historically, Allegheny has purchased coal from a limited number of suppliers. Of Allegheny’s coal purchases in 2004, 76% came from subsidiaries of two companies, the larger of which represented 58% of the total tons purchased. As of February 17, 2005, Allegheny had contracts in place for the delivery of approximately 17 million tons of coal in 2005 at an average price of $34.70 per ton delivered. This represents approximately 95% of estimated coal to be consumed in 2005. Due to various industry factors, including increased mining costs, rail transportation constraints and operational difficulties, some coal suppliers are under increased financial pressure, which has had, and may continue to have, negative effects on coal supplier performance.
As existing long-term contracts expire, Allegheny plans to enter into multi-year contracts to secure a reliable coal supply. These new arrangements are expected to be at higher prices than the expiring contracts.
Allegheny owns undeveloped coal reserves estimated to contain in excess of 120 million tons of higher sulfur coal recoverable by deep mining. Allegheny is evaluating a number of alternatives related to these undeveloped reserves.
Natural Gas Supply
AE Supply purchases natural gas services to supply its natural gas-fired facilities. In 2004, AE Supply purchased its natural gas requirements principally in the spot market. In addition, one of AE Supply’s subsidiaries has a month-to-month natural gas agreement in place with a supplier. The natural gas provided under this agreement is used at the Buchanan facility.
Natural Gas Transportation Contracts
Dominion Transmission Transportation Contract. AE Supply has a long-term agreement with Dominion Transmission, Inc. for the transportation of natural gas under a tariff approved by FERC. This agreement provides for the transportation of 95,000 decatherms of natural gas per day through May 31, 2013, from Oakford, Pennsylvania to AE Supply’s combined cycle plant in Springdale, Pennsylvania.
Equitable Gas Transportation Contract. AE Supply has a long-term agreement with Equitable Gas Company, a division of Equitable Resources, Inc., for the transportation of natural gas under a tariff approved by FERC. This agreement provides for transportation of 90,000 decatherms of natural gas per day through December 31, 2012 from Greene County, Pennsylvania to the Hatfield’s Ferry generation station in Masontown, Pennsylvania. This transportation agreement was purchased for anticipated natural gas reburn opportunities at Hatfield’s Ferry. Natural gas reburn reduces NOx emissions at a generation station by using natural gas instead of coal for a portion of the generation station’s anticipated fuel requirements. This process is used at Hatfield’s Ferry when the price of natural gas makes reburn economic relative to other NOx emission management activities.
El Paso Transportation Contract. AE Supply has a long-term agreement with El Paso Natural Gas Company for the transportation of natural gas under tariffs approved by FERC. This agreement provides for the
transportation of gas from western Texas and northern New Mexico to the southern California border and was purchased for anticipated natural gas deliveries to the La Paz combined-cycle generation facility in Arizona. This project has been cancelled. In August 2003, AE Supply obtained a permanent release of approximately 85% of its capacity obligation under this contract. In November 2004, AE Supply entered into a release for the balance of this capacity.
Kern River Transportation Contract. AE Supply has a long-term agreement with Kern River Gas Transmission Company for the transportation of natural gas under a tariff approved by FERC. This agreement provides for the transportation of 45,122 decatherms of natural gas per day through April 30, 2018 from Opal, Wyoming to Nevada and southern California. This transportation agreement was purchased for anticipated natural gas deliveries into southern California and at the Las Vegas Cogeneration II combined-cycle generation facility in Las Vegas, Nevada. In June 2004, AE Supply entered into a long-term capacity release for the full contract volume through October 2007. AE Supply recorded charges of $15.5 million related to this release in 2004.
The Delivery and Services Segment
Electric Power
Allegheny reorganized its corporate structure in response to electric utility deregulation within its service area between 1999 and 2001. The Distribution Companies, with the exception of Monongahela and its West Virginia generation assets, do not produce their own power. Monongahela transferred a portion of its generation assets relative to its Ohio and FERC generation assets, including a portion of its ownership interest in AGC, to AE Supply in 2001. Potomac Edison transferred substantially all of its generation assets to AE Supply in 2000. West Penn transferred all of its generation assets to AE Supply in 1999.
The Distribution Companies are obligated to provide electricity at capped rates to customers who do not retain an alternate electricity generation supplier during the applicable deregulation transition period. The transition periods vary across Allegheny’s service area.
•
Monongahela. In Ohio, the transition period for residential and small business customers ends on December 31, 2005. See “Regulatory Framework Affecting Allegheny-State Legislation and Regulatory Developments,” below for information regarding the termination of the transition periods for commercial and industrial customers in Ohio.
•
Potomac Edison. In Maryland, the transition period for residential customers ends on December 31, 2008. The transition period for commercial and industrial customers ended December 31, 2004. In Virginia, the transition period ends on December 31, 2010.
•
West Penn. In Pennsylvania, the transition period terminates at the end of 2008 for all customers, pending resolution of a Joint Petition for Settlement filed by West Penn and other interested parties in September 2004, which seeks to extend the transition period and increase applicable rate caps.
These transition periods could be altered by legislative, judicial or, in some cases, regulatory actions. See “Regulatory Framework Affecting Allegheny” below.
AE Supply is contractually obligated to provide power to the Distribution Companies during the relevant state deregulation transition periods under the terms of power supply agreements with the Distribution Companies. AE Supply also sells power to Potomac Edison to serve customers in Potomac Edison’s West Virginia service territory. Sales under AE Supply’s power sales agreements with West Penn, Monongahela (with respect to its Ohio customers) and Potomac Edison currently consume a majority of the normal operating capacity of AE Supply’s generation assets. These power sales agreements include both fixed price and market-based pricing components. These pricing components may not fully reflect the cost of supplying this power. As a result, AE Supply currently absorbs a portion of the risk of fuel price increases and increased costs of environmental compliance.
The Distribution Companies purchase a majority of the power required to satisfy their respective PLR obligations from AE Supply. The purchases are made under the terms of power sales agreements with AE Supply, which will terminate as set forth in the chart below. When the power sales agreements with AE Supply terminate, the Distribution Companies will be unable to rely on the previously dedicated supply of power at specified contract prices to meet their respective power supply requirements.
The arrangements to serve the PLR obligations of the Distribution Companies following the termination of these agreements have not been determined and are subject to active legislative and regulatory actions in Pennsylvania and Virginia. In Maryland, a final state commission order that prescribes a wholesale bidding process to procure market-based full requirements service for end use customers was issued on September 30, 2003. The bid solicitation process began on October 1, 2003. By January 28, 2005, the Distribution Companies had completed two full bid solicitations, securing PLR service for eligible Maryland commercial and industrial customers through May 31, 2006.
In Ohio, the market development period for medium to large commercial and industrial customers and streetlighting terminated on December 31, 2003. PUCO authorized Monongahela to issue a request for proposals for wholesale power to supply approximately 130 MW of market-based retail rate service to these customers, effective January 1, 2004. AE Supply won the competitive bid process to serve the load, subject to approval of its bid by PUCO. In October 2003, PUCO denied approval of the wholesale bid and new retail rates and continued the fixed rates for these customer classes until December 31, 2005. See “Regulatory Framework Affecting Allegheny-State Legislation, Rate Matters and Regulatory Developments,” below for a more detailed discussion of legal and regulatory actions relating to this matter.
A portion of the Distribution Companies’ PLR obligations is satisfied by PURPA contract purchases. Most of the rest of the power necessary to meet the PLR obligations of the Distribution Companies and Potomac Edison’s regulated service obligations in West Virginia is purchased from AE Supply. The table below shows the percentage of power for each jurisdictional set of customers that was purchased by the Distribution Companies from AE Supply in 2004:
(a)
The transition period for most commercial and industrial customers ended on December 31, 2003. This load is no longer served under the power sales agreement.
(b)
The transition period for commercial and industrial customers ended on December 31, 2004. This load is no longer served under the power sales agreement.
(c)
Potomac Edison’s current power sales agreement with AE Supply for West Virginia expires on December 31, 2010. However, Potomac Edison and AE Supply have agreed to a new contract that expires on December 31, 2017. The effectiveness of that contract is subject to West Virginia PSC and FERC approval.
Natural Gas Supply
In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia, including Mountaineer, for $141 million in cash and the assumption of approximately $87 million of long-term debt, subject to certain closing adjustments. The sale is subject to regulatory approval and is expected
to be completed in mid- to late-2005. These natural gas operations are shown as discontinued operations in the accompanying financial statements.
Monongahela’s regulated natural gas sales operations are carried out through Mountaineer and its Monongahela divisions. West Virginia is in the path of major natural gas supply routes from the Gulf of Mexico to the Northeast, and Monongahela has direct access to the Columbia Gas Transmission Corporation (“Columbia Gas”) and the Tennessee Gas Pipeline interstate pipeline systems. Monongahela’s principal natural gas requirements are supplied from wells located in Appalachia and the Gulf of Mexico producing basins. Monongahela’s ownership of MGS provides direct access to less than 5% of Monongahela’s total annual natural gas needs. A small part of MGS’ output is sold to third parties. Approximately 75% to 85% of Monongahela’s natural gas supply requirements are purchased on a forward basis up to 18 months in advance. The remainder, including MGS production, is purchased on a one-year or more forward basis primarily at index-based prices.
As a result of Allegheny’s past liquidity issues, coupled with natural gas price increases, Monongahela was required to prepay for some of its future natural gas purchases during 2004. Monongahela believes that it will have access to sufficient natural gas supplies to meet its anticipated requirements.
Natural Gas Transportation and Storage Capacity
Natural gas purchased from producers or suppliers in the Gulf Coast producing basin/region is transported through the interstate pipeline systems of Columbia Gas and Columbia Gulf Transmission Company (“Columbia Gulf”) to Monongahela’s local distribution facilities in West Virginia.
To ensure continuous, uninterrupted service to its customers, Mountaineer has long-term transportation and storage service agreements with Columbia Gas and Columbia Gulf. These contracts cover a wide range of transportation services and volumes. Under both Mountaineer’s and WVP’s Purchased Gas Adjustment clauses, purchased gas costs including transportation and storage services, if prudently incurred, are recovered from the respective companies’ customers.
Typically, large commercial and industrial end-users of natural gas use natural gas sales and/or transportation contracts for load management purposes. Under these contracts, users purchase and/or transport natural gas with the understanding that they may be forced to shut down their use of natural gas or switch to alternate sources of energy during periods of high demand for natural gas. In addition, during times of extraordinary supply problems, curtailments of deliveries to some classes of customers (typically large industrial customers) with interstate transportation contracts may be necessary, but only in accordance with guidelines established by appropriate federal and state regulatory agencies.
REGULATORY FRAMEWORK AFFECTING ALLEGHENY
The interstate transmission services and wholesale power sales of the Distribution Companies and AE Supply are regulated by FERC under the Federal Power Act (the “FPA”). The Distribution Companies’ local distribution service and sales at the retail level are subject to state regulation. The statutory and regulatory framework affecting these companies has evolved significantly over the past decade, and these changes have exposed the companies to significant new risks and opportunities.
AE and all of its subsidiaries are also subject to the broad jurisdiction of the SEC under PUHCA. In addition, Allegheny’s communications subsidiary, ACC, is subject, to a limited extent, to the jurisdiction of the Federal Communications Commission and state communications regulatory commissions. Allegheny is subject to numerous other local, state and federal laws, regulations and rules.
Federal Regulation and Rate Matters
FERC, Competition and RTOs
FERC is an independent agency within the U.S. Department of Energy that regulates the transmission and wholesale of electricity under the authority of the FPA. Under the FPA, FERC regulates the rates, terms and conditions of wholesale power sales and transmission services offered by public utilities.
The FPA gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity. Entities such as the Distribution Companies and AE Supply that sell electricity at wholesale or own transmission facilities are considered “public utilities” subject to FERC jurisdiction. Public utilities must obtain FERC approval of their wholesale rate schedules. Rates for transmission service are determined on a cost of service basis, or, if the utility has demonstrated that it does not have market power, FERC may grant market-based rate authority, which allows transactions to be priced based on prevailing market conditions.
Over the past decade, FERC has taken a number of steps to foster increased competition within the electric industry. Among other things, FERC requires public utilities to offer non-discriminatory, open-access transmission services. In addition, FERC imposed standards of conduct governing communications between employees conducting transmission functions and employees engaged in wholesale power sale activities. These standards of conduct are intended to prevent utilities from giving their power marketing businesses preferential access to transmission system information. FERC also has taken steps to encourage utilities to participate in RTOs, such as PJM, by transferring control over their transmission assets to RTOs.
Following FERC’s initiative to promote competition, a number of states, including Pennsylvania, Maryland, Virginia and Ohio, adopted retail access legislation, which permitted utilities to transfer their generation assets to affiliated companies or third parties. Similar to many other utilities, the Distribution Companies restructured their businesses in Pennsylvania, Maryland, Virginia and Ohio between 1996 and 2001 to comply with retail restructuring requirements in those states by, among other things, transferring generation assets serving customers in those states to AE Supply.
However, this trend toward restructuring and increased competition for retail markets has slowed in response to events over the past several years. Among other things, significant price volatility (particularly in the California wholesale market), allegations of improper trading activities and overall declines in electricity demand and in the economy, generally, have contributed to this slowdown. Market-based competition within the wholesale markets is now continuing with greater FERC oversight, and some states have moved away from electricity choice at the retail level by delaying the implementation of retail competition (as in Virginia) or rejecting it outright (as in West Virginia). Delays, discontinuations or reversals of electricity marketing restructurings in states in which Allegheny operates could have a material adverse effect on its results of operation and financial condition. See “State Legislation, Rate Matters and Regulatory Developments” below.
In April 2002, the Distribution Companies transferred functional control of their transmission assets to PJM. As part of its approval of the transfer of control, FERC permitted a transmission rate surcharge designed to allow the Distribution Companies to recover $85 million in revenues that would otherwise not be collectible once they joined PJM. In 2004, 2003 and 2002, the Distribution Companies recovered approximately $35 million, $27 million and $23 million of these surcharges, respectively. FERC also allowed the Distribution Companies to collect a surcharge to recover the costs associated with Allegheny’s integration into PJM, which expired at the end of 2004. Accordingly, the Distribution Companies have fully recovered all of these surcharges as of December 31, 2004.
The Distribution Companies also may be impacted by recent FERC actions with respect to the transmission rate design within PJM. Beginning in November 2003, FERC issued a series of orders related to transmission rate design for the PJM and Midwest Independent Transmission System Operator regions. Specifically, FERC ordered the elimination of multiple and additive (i.e., “pancaked”) rates and called for the implementation of a long-term rate design for the region. In November 2004, FERC rejected long-term regional rate proposals from the Distribution Companies and others and ordered the continuation of the existing rate design and the implementation of a transition charge for this region through March 31, 2006. FERC also authorized three transmission owners to submit filings that would enable them to assess additional transition charges against the Distribution Companies and other utilities in PJM. Allegheny estimates that these additional charges, if accepted by FERC, will result in net transmission charges to the Distribution Companies of approximately $0.5 million for the four-month period ended March 31, 2005 and approximately $8.9 million for the twelve-month period ended March 31, 2006. In February 2005, FERC accepted these transition charges, effective December 1, 2004, subject to an evidentiary hearing regarding the data and methodology used to determine the charges and proposed adjustments. The order expected to be issued by FERC may require the Distribution Companies to refund some portion of the amounts received from these transition charges or entitle the Distribution Companies to receive additional revenue from these charges. In addition, the Distribution Companies may be required to pay additional amounts as a result of surcharges imposed on the transition charges previously billed to the Distribution Companies.
Substantially all of Allegheny’s generation assets and power supply obligations are located within the PJM market. Any changes in PJM policies and/or market rules, including changes that are currently under consideration by FERC, could adversely affect Allegheny’s financial results. These matters include proposed revisions to PJM’s tariff concerning the auction of financial transmission rights and the allocation mechanism for the auction revenues; changes in transmission congestion patterns due to the proposed implementation of PJM’s regional transmission expansion planning protocol or other required transmission system upgrades; the effects throughout the system of new members joining PJM and new generation retirement rules and reliability pricing issues.
By September 30, 2005, AE Supply, the Distribution Companies and other Allegheny entities that had market-based rate authority granted by FERC are required to file a triennial analysis of market power with FERC. This filing is required as a condition to continuing to sell electric energy at wholesale and market rates.
PUHCA
Any entity that owns, controls or has the power to vote 10% or more of the outstanding voting securities of an “electric utility company,” or a holding company for an electric utility company, is subject to SEC regulation under PUHCA.
PUHCA imposes financial and operational conditions and restrictions on many aspects of a registered holding company system’s business. PUHCA restricts a registered holding company system from expanding into other businesses by prohibiting it from engaging in activities that are not functionally related to its core business. PUHCA also requires registered holding company systems to confine themselves to a single integrated public utility system. Most important in light of Allegheny’s past liquidity issues, PUHCA requires pre-approval from
the SEC for, among other things, the issuance of debt or equity securities and for the sale or acquisition of utility assets. The SEC, in certain matters, also requires state approvals as a condition to authorizations, even though such approvals might not be required under applicable state laws. Thus, the PUHCA approval process introduces significant lead times into routine transactions under normal circumstances.
Additionally, under PUHCA, the SEC has imposed a common equity to total capitalization ratio on the utilities that it regulates, thus imposing additional operating constraints not imposed on other utilities. Allegheny’s current common equity ratio is below the level required under its current financing authorizations, which has required it to obtain additional authorizations.
Many of Allegheny’s competitors are not regulated under PUHCA and, therefore, do not face these constraints.
PURPA
PURPA requires electric utility companies such as the Distribution Companies to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying small power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. State public service commissions or legislatures establish the rates paid for electric energy purchased from these qualifying facilities.
The Distribution Companies have committed to purchase 479 MW of qualifying PURPA capacity. In 2004, payments for PURPA capacity and energy pursuant to these contracts totaled approximately $197.8 million. The average cost to the Distribution Companies of these power purchases was 5.2 cents/kWh. The Distribution Companies are currently authorized to recover substantially all of these costs in their retail rates. The Distribution Companies’ obligations to purchase power from qualified PURPA projects in the future may exceed amounts they are authorized to recover from their customers, which could result in losses related to the PURPA contracts.
State Legislation, Rate Matters and Regulatory Developments
Pennsylvania
The Electricity Generation Customer Choice and Competition Act (the “Customer Choice Act”) gave all retail electricity customers in Pennsylvania the right to choose their electricity generation supplier as of January 2, 2000. Under the Customer Choice Act and a subsequent restructuring settlement approved by the Pennsylvania PUC, West Penn transferred its generation assets to AE Supply. West Penn retained its T&D assets. West Penn’s T&D assets are subject to traditional regulated utility ratemaking (i.e., cost-based rates). As part of West Penn’s restructuring settlement, West Penn is subject to rate caps on its T&D rates through December 31, 2005 and on its generation rates through December 31, 2008. West Penn is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver.
West Penn has long-term power sales agreements with AE Supply to provide West Penn with the amount of electricity necessary to meet the majority of its PLR retail obligations (and certain wholesale contracts) during the Pennsylvania transition period. As directed by the Customer Choice Act, the Pennsylvania PUC has issued draft PLR service rules addressing the utilities’ obligation to serve customers at the end of their respective transition periods.
In November 2003, West Penn requested approval to issue additional transition bonds up to amounts originally authorized to securitize the portion of West Penn’s stranded costs that are not recoverable on a timely basis due to operation of the generation rate cap. In September 2004, West Penn, the Pennsylvania Office of Consumer Advocate, the Office of Small Business Advocate and The West Penn Power Industrial Intervenors
filed a Joint Petition for Settlement and for Modification of the 1998 Restructuring Settlement (the “Joint Petition”). In March 2005, the parties filed an amendment to the Joint Petition, adding additional parties. If the joint petition is approved, West Penn will be allowed to securitize up to $115 million of additional transition costs (including the deferred portion of the competitive transition charge (“CTC”) from 1999 through 2004) through the issuance of transition bonds. Under the proposed settlement, distribution rate caps will be extended from 2005 to 2007, and generation rate caps will be extended from 2008 to 2010, with additional generation rate increases occurring in 2007, 2009 and 2010. These increases will gradually move generation rates closer to market-based rates.
In August 2004, West Penn filed its annual CTC reconciliation for the twelve months ended July 31, 2004. The reconciliation showed a twelve-month underrecovery of $13.2 million, for a cumulative underrecovery of approximately $78.3 million. In October 2004, West Penn filed a Petition for Continued Deferral of CTC Underrecovery as Regulatory Asset. The Pennsylvania PUC approved the reconciliation and granted authorization to record the 2004 cumulative underrecovery as a regulatory asset, for full and complete recovery, with an annual interest rate of 11%.
Recently enacted legislation requires the implementation of an alternative energy portfolio standard in Pennsylvania which will require electric distribution companies and retail electric suppliers in Pennsylvania to obtain certain percentages of their energy supplies from alternative sources. The new legislation includes a five-year exemption from this requirement for companies, such as West Penn, that are operating within a transition period under the current regulations governing the transition to market competition in Pennsylvania. The full requirement will apply to those companies when the transition period ends. The legislation also includes a provision that will allow the Pennsylvania PUC to modify or eliminate these obligations if alternative sources are not reasonably available. The law directs that all costs related to the purchase of electricity from alternative energy sources and payments for alternative energy credits will be fully recovered pursuant to an automatic energy adjustment clause. The Pennsylvania PUC initiated a proceeding in January 2005 to investigate implementation and enforcement of the legislation.
West Virginia
In 1998, the West Virginia legislature passed legislation directing the West Virginia PSC to determine whether retail electric competition was in the best interests of West Virginia and its citizens. In response, the West Virginia PSC submitted a plan to introduce full retail competition on January 1, 2001. The West Virginia legislature approved, but never implemented, this plan. In March 2003, the West Virginia legislature passed a bill that clarified the jurisdiction of the West Virginia PSC over electric generation facilities. Based on these actions, Allegheny has concluded that retail competition and the deregulation of generation is no longer likely in West Virginia. In 2000, Potomac Edison received approval to transfer its West Virginia generation assets to AE Supply. The West Virginia PSC never acted on a similar petition by Monongahela, and Monongahela agreed to withdraw its petition.
In July 2003, Potomac Edison, Monongahela and certain other interested parties filed a stipulation with the West Virginia PSC on issues related to their generation asset transfers, including the amount transferred to AE Supply representing Ohio’s allocated share of Monongahela’s generation. The West Virginia PSC has not yet approved the stipulation and the parties to the agreement have initiated discussions to consider modifications to the agreement.
On September 27, 2004, Monongahela, Mountaineer and Mountaineer Gas Holding Limited Partnership (“Mountaineer Holdings”) filed a joint petition with the West Virginia PSC for approval to transfer the stock of Mountaineer and certain other natural gas distribution assets owned by Monongahela to Mountaineer Holdings, the prospective buyer of Monongahela’s West Virginia natural gas business. In a separate petition also filed on September 27, 2004, Mountaineer filed to increase its distribution rates by approximately $23 million, or 9.6%, annually. Mountaineer Holdings’ obligation to complete this transaction is conditioned on approval of a rate increase that is not materially different from the increase requested. The West Virginia PSC issued an order suspending the rates until September 8, 2005 and directing the administrative law judge to render a decision in this matter no later than July 11, 2005.
Monongahela’s natural gas distribution business is divided into two components for purposes of its Purchased Gas Adjustments (“PGA”): West Virginia Power Gas Services (“WVPGS”) and Mountaineer. WVPGS and Mountaineer file with the West Virginia PSC to adjust their PGA every year. The PGA mechanism compares the revenue received for recovery of projected gas expenses to the actual gas expenses incurred by WVPGS or Mountaineer and defers any difference as a regulatory asset or liability to be collected or returned, respectively, to customers in the next proceeding. The PGA generally has no effect on earnings. An annual PGA period normally begins with service provided on and after November 1 and concludes on October 31 of the following year.
On October 7, 2004, an administrative law judge for the West Virginia PSC approved an interim PGA increase, effective on November 1, 2004, of $4.1 million, or 12.5%, for WVPGS and $26.4 million, or 9.7%, for Mountaineer. In January 2005, the West Virginia PSC issued a second interim decision, which became final in February 2005, approving final PGA rates that were higher than the prior year’s rates, but lower than the first approved interim rates, effective February 1, 2005. These rates resulted in an increase over the prior year of $3.9 million, or 11.8%, for WVPGS and $25.0 million, or 9.2%, for Mountaineer. The estimated annual total revenue increases reflect the companies’ agreement to defer half of the under-recovered balances as of June 30, 2004. Approximately $1 million for WVPGS and $7 million for Mountaineer will be deferred until the next PGA proceeding. Carrying charges will accumulate on these deferred amounts at Allegheny’s cost of debt calculated for a one-year period, which will also be recovered in the next PGA proceeding.
Maryland
Maryland adopted electric industry restructuring legislation in 1999, which gave Potomac Edison’s Maryland retail electric customers the right to choose their electricity generation suppliers. In 2000, Potomac Edison transferred its Maryland generation assets to AE Supply. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates for all customers were capped through 2004 and are otherwise subject to traditional regulated utility ratemaking (i.e., cost-based rates). Potomac Edison is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver.
The Maryland transition period lasted through December 31, 2004 for commercial and industrial customers and extends through December 31, 2008 for residential customers. Potomac Edison has long-term power sales agreements with AE Supply to provide the amount of electricity necessary to meet the majority of Potomac Edison’s PLR retail obligations (and certain wholesale contracts) during the Maryland transition period. Potomac Edison will procure the wholesale electric supply services necessary to serve its PLR obligations after the expiration of the transition period and before the expiration of its PLR obligations through a competitive bid process. Potomac Edison will be allowed to recover its costs for providing these services, including a return for its shareholder, through an administrative charge.
In January 2005, a previously approved increase in Potomac Edison’s distribution rates went into effect.
In 2000, the Maryland PSC issued an order imposing standards of conduct between Maryland utilities and their affiliates. In 2005, the Maryland PSC is expected to issue final regulations to provide standards governing a utility’s conduct with its affiliates in Maryland.
Recently enacted legislation requires the implementation of a renewable energy portfolio standard in Maryland. Beginning upon the later of the expiration of the transition period for any particular customer class served by a supplier or January 1, 2006, retail electricity suppliers in Maryland will have to obtain certain percentages of their energy supplies from renewable energy resources. The law provides that if renewable resources are too expensive, or are unavailable in quantities sufficient to meet the standard in any given year, suppliers can opt instead to pay a “compliance fee.” The law directs the Maryland PSC to allow electric suppliers to recover their costs from customers, including any compliance fees that they incur.
Virginia
Under the Virginia Electric Utility Restructuring Act of 1999 (as amended, the “Restructuring Act”), Potomac Edison’s retail electric customers in Virginia have the right to choose their electricity generation supplier. Potomac Edison transferred all of its Virginia generation assets to AE Supply in 2000, except certain small hydro facilities, which were transferred to Green Valley Hydro. Potomac Edison retained its T&D assets. Potomac Edison’s T&D rates are capped through 2010, subject to certain exceptions. Potomac Edison has two opportunities to petition the Virginia SCC for changes to its T&D rates, between January 1, 2004 and June 30, 2007 and once again after July 1, 2007. The Restructuring Act requires the Virginia SCC to adjust Potomac Edison’s capped rates not more than once annually for the timely recovery of costs prudently incurred after July 1, 2004 for transmission or distribution system reliability or to comply with state or federal environmental laws or regulations. In addition, after July 1, 2007, Potomac Edison will have the right to recover annually certain purchased power expenses as an exception to capped rates. Potomac Edison is the PLR for those customers who do not choose an alternate supplier or whose alternate supplier does not deliver.
Potomac Edison has long-term power sales agreements with AE Supply to provide Potomac Edison with the amount of electricity necessary to meet the majority of its PLR retail obligations (and a wholesale contract) through June 30, 2007. After that, Potomac Edison will purchase its PLR requirements from the wholesale market and recover certain costs from customers through a purchased power adjustment clause.
On October 8, 2004, the Virginia SCC approved Potomac Edison’s application to transfer control of its transmission facilities to PJM subject to the requirement that both Potomac Edison and PJM submit annual reports to the Virginia SCC beginning October 1, 2005.
Ohio
The Ohio General Assembly adopted legislation in 1999 to restructure its electric utility industry, provide retail electric customers the right to choose their electricity generation supplier and begin a transition to market rates. The 1999 legislation granted Ohio’s residential customers a 5% reduction in the generation portion of their rates until December 31, 2005, which is when the transition period ends. Pursuant to a settlement, Monongahela’s transition period for large industrial, commercial and street lighting customers was scheduled to end on December 31, 2003, but, as discussed below, has been extended by PUCO until December 31, 2005. Under the regulatory transition plan, Monongahela transferred its Ohio generation assets to AE Supply in June 2001. Monongahela retained its T&D assets. Monongahela’s T&D rates are capped through the end of the transition period for all customers and, thereafter, are subject to traditional regulated utility ratemaking (i.e., cost-based rates). Monongahela is the PLR for customers who do not choose an alternate supplier or whose alternate supplier does not deliver.
In July 2003, PUCO authorized Monongahela to issue a request for proposals for wholesale power to supply approximately 130 MW of new standard market-based retail rate service to its large industrial and commercial customers and to its street lighting customers. In October 2003, PUCO denied approval of the wholesale bid and new retail rates and froze the current fixed rates for these customer classes until December 31, 2005. In February 2004, Monongahela appealed PUCO’s decision to the Ohio Supreme Court. On December 30, 2004, the Ohio Supreme Court affirmed PUCO’s October 2003 order extending Monongahela’s rate freeze for large commercial and industrial customers past the end of 2003.
In February 2004, Monongahela filed for an injunction in federal court seeking to recover, in retail rates, its costs of purchasing power in the wholesale market. In May 2004, the court partially granted Monongahela’s request, ruling that the Ohio legislation adopted in 1999 to restructure the electric utility industry was unconstitutional to the extent it did not permit Monongahela to make a claim with PUCO that its rates are confiscatory. Monongahela requested reconsideration of the court’s order, which the court partially granted by retaining jurisdiction over this matter. PUCO initiated a proceeding in compliance with the federal court’s directive. In June 2004, Monongahela filed its application for rate relief, which PUCO denied in December 2004
with respect to certain large industrial and commercial customers and street lighting customers. Monongahela requested rehearing of PUCO’s ruling on January 7, 2005, which was denied. Monongahela appealed this ruling on February 25, 2005. On January 12, 2005, Monongahela renewed its request for a preliminary injunction against PUCO in federal court. If these challenges are not successful, Monongahela’s current rates for these customer classes will be fixed through December 31, 2005.
Since January 2004, Monongahela has been purchasing power at PJM market prices for these customers and anticipates that the price for that power will continue to be higher than the current retail generation rates it charges customers. Monongahela has expensed $12.0 million of costs in excess of its rates for 2004, pending the final outcome of Monongahela’s legal challenges.
EMPLOYEES
All of the registrants’ officers and employees are employed by AESC, except for certain employees who are directly employed by Mountaineer effective January 1, 2005. As of December 31, 2004, AESC employed approximately 5,100 employees. Of these employees, approximately 30% are subject to collective bargaining arrangements. Approximately 77% of the unionized employees are at the Distribution Companies and approximately 23% are at AE’s other subsidiaries. Approximately 1,080 employees are represented by System Local 102 of the Utility Workers Union of America (the “UWUA”), and 105 employees are represented by other locals of the UWUA. Approximately 160 employees are represented by locals of the Paper, Allied-Industrial, Chemical, and Energy Workers International Union. Approximately 185 employees are represented by locals of the International Brotherhood of Electrical Workers (the “IBEW”). The collective bargaining arrangements with certain locals of the IBEW expired and have been extended while the parties negotiate a new contract. Other collective bargaining arrangements expire at various dates through the last quarter of 2007. Each of the registrants believes that current relations between it and its unionized and non-unionized employees are satisfactory.
ENVIRONMENTAL MATTERS
The operations of Allegheny’s owned facilities, including its generation stations, are subject to regulation by various federal, state and local authorities as to air and water quality, hazardous and solid waste disposal and other environmental matters.
Information regarding capital expenditures and estimated capital expenditures associated with known environmental standards is provided in “Capital Expenditures” above. Additional legislation or regulatory control requirements have been proposed and, if enacted, will require modification, supplementation or replacement of equipment at existing stations at substantial additional cost.
Air Standards
Allegheny currently meets applicable standards for particulate matter emissions at its generation stations through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and emission allowances and, at times, through reduction of output. From time to time, minor excursions of stack emission opacity, that are normal to fossil fuel operations, are experienced and are accommodated by the regulatory process.
Allegheny meets current emission standards for SO2 by using scrubbers, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and utilizing emission allowances.
Allegheny’s compliance with the Clean Air Act has required, and may require in the future, that Allegheny install expensive post-combustion control technologies on many of its generation stations.
The Clean Air Act mandates annual reductions of SO2 and created a SO2 emission allowance trading program. AE Supply and Monongahela comply with current SO2 emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Allegheny continues to study the use of allowances, additional emission controls and low sulfur fuel to meet future SO2 compliance obligations. Allegheny estimates that it may purchase allowances for up to 50,000 tons for 2005 and an average of approximately 100,000 tons per year for 2006 through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities. Allegheny currently expects that its plan to increase its use of lower sulfur coal and implement other environmental control improvements should reduce allowance purchase requirements over this time period.
In 1998, the EPA finalized its Nitrogen Oxide (“NOx”) State Implementation Plan (“SIP”) call rule (known as the “NOx SIP call”), which addressed the regional transport of ground-level ozone and required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Pennsylvania, Maryland and West Virginia. Compliance with the NOx SIP call was required beginning in May 2004. Pennsylvania and Maryland implemented their respective SIP call rules in May 2003. West Virginia’s SIP call rules were effective as of May 2004.
AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. These NOx controls include selective catalytic reduction at the Harrison and Pleasants generation stations and selective noncatalytic reduction at the Hatfield’s Ferry and Fort Martin generation stations, as well as burner modifications at the Mitchell generation station. The NOx compliance plan functions on a system-wide basis, similar to the SO2 compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. AE Supply estimates that its emission control activities, in concert with its inventory of banked allowances, will facilitate its compliance with NOx limits established by the SIP through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the types of fuel used by its generation facilities.
In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation stations, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these generation stations. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the NSR standards of the Clean Air Act, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. AE has provided responsive information to this and a subsequent request. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues.
Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings in most cases. AE believes that its subsidiaries’ generation facilities have been operated in accordance with the Clean Air Act and the rules implementing it. The experience of other energy companies, however, suggests that, in recent years, the EPA has narrowed its view regarding the scope of the definition of “routine maintenance” under its rules, thereby broadening the range of actions subject to compliance with NSR standards. Section 114 information requests concerning facility modifications are often followed by enforcement actions.
If NSR standards are applied to Allegheny’s generation stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. There are two federal district court decisions interpreting the application of NSR standards to utilities, the Ohio Edison decision and the Duke Energy decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy decision supports the industry’s understanding of NSR requirements. The final Routine Maintenance, Repair and Replacement Rule (“RMRR”) released by the EPA is more consistent with the energy industry’s historical compliance approach. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the RMRR, which was scheduled to go into effect on December 26, 2003. The stay delays implementation of the RMRR. At this time, AE and its subsidiaries are not able to determine the effect that these actions may have on them.
On February 2, 2004, the EPA informed AE that it intended to provide the New York Attorney General, pursuant to his request, certain records that AE provided to the EPA pursuant to its request under Section 114 of the Clean Air Act. On April 23, 2004, the PADEP notified AE Supply that the PADEP had requested that the EPA provide it with these records.
On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from PADEP. The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation stations in Pennsylvania and identifies PADEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal district court in West Virginia on January 6, 2005. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia are in compliance with the Clean Air Act. The Attorneys General have filed a motion to dismiss the declaratory judgment action. If the action is dismissed based upon their motion, the Attorneys General may file an enforcement action against Allegheny in federal court in Pennsylvania. It is also possible that the EPA and other state authorities may join in the current declaratory judgment action or, if it is dismissed, a new action filed by the Attorneys General.
On February 16, 2005, Citizens for Pennsylvania’s Future, an environmental group, sued Allegheny in the U.S. District Court for the Western District of Pennsylvania. The action alleges violations of operating limits and particulate matter emission limits at the Hatfield’s Ferry generation facility.
Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.
Pending Initiatives
On March 10, 2004, the EPA issued the Clean Air Interstate Rule (“CAIR”), which imposes additional NOx and SO2 controls over power plant emissions. CAIR requires significant reductions of NOx and SO2 by 2010 (for Phase I) and 2015 (for Phase II) under a cap and trade program similar to the EPA’s acid rain program, and will be implemented through the state SIP program. The effect on Allegheny of these regulations is unknown at this time, but could be substantial.
The EPA promulgated revisions to particulate matter and ozone standards in July 1997. Litigation over the revised particulate matter and ozone standards has recently been resolved, and these requirements could impose substantial costs on Allegheny. Allegheny does not anticipate final regulations before 2008. The EPA has also promulgated final regional haze regulations to improve visibility in national parks and wilderness areas, which are currently the subject of litigation. The effect on Allegheny of these regulations is unknown at this time, but could be substantial.
On December 15, 2003, the EPA proposed a rule to regulate power plant mercury emissions. The EPA plans to finalize a mercury emissions standard by March 15, 2005. Based on this schedule, it is unlikely that the implementation of mercury controls would be required before 2007 or 2008. The effect on Allegheny of these regulations is unknown at this time, but could be substantial.
The Kyoto Protocol went into effect on February 15, 2005. The Kyoto Protocol, which was signed by the Clinton Administration, but not ratified by the U.S. Senate, would require drastic reductions in greenhouse gas emissions in the United States in response to the perceived threat of global warming. If ratified and implemented by the United States, this treaty would likely require extensive mitigation efforts by Allegheny to reduce greenhouse gas emissions at its electric generation facilities and would raise considerable uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities. The Bush Administration has rejected the Kyoto Protocol and has proposed voluntary programs to reduce greenhouse gas intensity over the next decade. Various legislative proposals are under consideration at the federal and state level. The ultimate outcome of the global climate change debate and the Kyoto Protocol, which cannot be predicted at this time, could have a significant effect on Allegheny.
The Clear Skies Act of 2005 (the “Clear Skies Bill”) has been introduced in the 109th Congress. The legislation is intended to eliminate Title IV of the Clean Air Act Amendments of 1990 and replace it with provisions designed to take a comprehensive and integrated approach to air emissions regulation. The Clear Skies Bill and alternative legislation have been the focus of Congressional committee action on multi-emission legislation. The Clear Skies Initiative does not include carbon dioxide reductions, but focuses on SO2, NOx and mercury. Hearings on multi-emissions legislation have been held in both the Senate and the House of Representatives, but the bill remains in committee.
Water Standards
Under the National Pollutant Discharge Elimination System (the “NPDES”), permits for all of Allegheny’s stations and disposal sites are in place, and its facilities are generally in compliance with all permit terms, conditions and effluent limitations. However, as permits are renewed, more stringent permit limitations are often
applied. To date, Allegheny has successfully developed, and scientifically justified to the satisfaction of the regulatory agencies, acceptable regulatory mixing zones or alternate site-specific water quality criteria or has installed passive constructed wetland treatment technology, thus avoiding significant capital costs and potential liabilities of advanced wastewater treatment. However, there is significant activity at the federal level on issues relating to the Clean Water Act (the “CWA”). The results of several pending long-term initiatives could cause Allegheny and its customers to incur material and substantial costs.
Rulemakings regarding the Total Maximum Daily Load Program, water quality standards, antidegradation review, human health and aquatic life water quality criteria, mixing zones and a final rulemaking concerning the CWA Section 316(b) Cooling Water Intake Structure are pending. In addition, the EPA is developing new policies concerning protection of endangered species under the CWA and imposition of new CWA requirements to address sediment and biological water quality criteria contamination. The outcome of these rulemakings will fundamentally change the traditional water quality management program from a chemical-specific control of point sources to a comprehensive and integrated watershed management program. This regulatory shift will result in more restrictions on facility discharges, as well as nonpoint source runoff, resulting from land use practices such as agriculture and forestry, and will ultimately address water quality impairment caused by atmospheric deposition.
Cooling Water Intake
On July 9, 2004, the EPA finalized the Section 316(b) Phase II Cooling Water Intake Structure Rule. The requirements of the final rule will be implemented through National Pollutant Discharge Elimination System Permits. The rule requires site-specific comprehensive demonstration studies to determine the best technology available (as defined in the rule) for achieving compliance with national performance standards. Allegheny is currently developing compliance strategies for its affected facilities. The effect on Allegheny of these regulations is unknown at this time but could be substantial.
RESEARCH AND DEVELOPMENT
Allegheny spent approximately $7.2 million and $0.6 million for research in 2002 and 2003, respectively. Allegheny’s expenditures for research in 2004 were minimal. In 2004, Allegheny’s research and development activity addressed air emissions issues, and Allegheny expects that its research and development activity in 2005 will continue to address these issues.
ITEM 2.
ITEM 2. PROPERTIES
Substantially all of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations consisting of approximately $1.04 billion of bank debt restructured in October 2004 (of which $982 million remained outstanding as of December 31, 2004) and $344 million of notes that were restructured in February 2003. Substantially all of Monongahela’s and Potomac Edison’s properties are held subject to the lien of indentures securing their first mortgage bonds. Certain of the properties and other assets owned by AE Supply and Monongahela that were financed by solid waste disposal and pollution control notes are subject to liens securing the obligations under those notes. In many cases, the properties of Monongahela, Potomac Edison and other AE subsidiaries may be subject to certain reservations, minor encumbrances and title defects that do not materially interfere with their use. The indenture under which AGC’s unsecured debentures are issued prohibits AGC, with certain limited exceptions, from incurring or permitting liens to exist on any of its properties or assets unless the debentures are contemporaneously secured equally and ratably with all other debt secured by the lien. Most T&D lines, some substations and switching stations and some ancillary facilities at power stations are on lands of others, in some cases by sufferance but, in most instances, pursuant to leases, easements, rights-of-way, permits or other arrangements, many of which have not been recorded and some of which are not evidenced by formal grants. In some cases, no examination of titles has been made as to lands on which T&D lines and substations are located. Each of the Distribution Companies possesses the power of eminent domain with respect to its public utility operations.
Allegheny’s principal corporate headquarters are located in Greensburg, Pennsylvania, in a building that is owned by West Penn. Allegheny also has a corporate center located in Fairmont, West Virginia, in a building owned by Monongahela. Additional ancillary offices exist throughout the Distribution Companies’ service territories.
MGS owns more than 300 natural gas wells and has net revenue interests in about 100 additional wells located throughout West Virginia. MGS has active leaseholds that cover more than 86,000 acres. In addition to its production assets, MGS owns approximately 125 miles of high-pressure transmission facilities running from Jackson County, West Virginia, west to Huntington, West Virginia, where it terminates at various delivery locations, and approximately 400 miles of gathering lines located in the same general vicinity.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Putative Class Actions Under California Statutes
Eight related putative class action lawsuits were filed against and served on AE Supply and more than two dozen other named defendant power suppliers in various California superior courts during 2002. These class action suits were removed from state court and transferred to the U.S. District Court for the Southern District of California. Seven of the suits were commenced by consumers of wholesale electricity in California. The eighth, Millar v. Allegheny Energy Supply Co., et al., was filed on behalf of California consumers and taxpayers. The complaints allege, among other things, that AE Supply and the other defendant power suppliers violated California’s antitrust statute and the California unfair business practices statutes by manipulating the California electricity market. The suits also challenge the validity of various long-term power contracts with the State of California, including the CDWR contract.
On August 25, 2003, the U.S. District Court granted AE Supply’s motion to dismiss the seven consumer class actions with prejudice. On February 25, 2005, the United States Court of Appeals for the Ninth Circuit affirmed the District Court’s judgment dismissing the seven class actions with prejudice.
The District Court separately granted plaintiffs’ motion to remand in the eighth action, Millar, on July 9, 2003. On December 18, 2003, the plaintiffs filed an amended complaint in California state court, solely on behalf of consumers, naming certain additional defendants, including The Goldman Sachs Group, Inc. (“Goldman Sachs”). The case was removed to federal court based on the amended complaint. On January 11, 2005, the federal district court remanded the case back to the state court.
Under the terms of the agreement relating to the sale of the CDWR contract, AE Supply and one of its affiliates have agreed to indemnify Goldman Sachs and its affiliate J. Aron & Company, under certain conditions, for any losses arising out of the class action litigation up to the amount of the purchase price. AE Supply issued a guarantee to J. Aron & Company in connection with this indemnification obligation.
AE Supply intends to vigorously defend against these actions but cannot predict their outcomes.
Nevada Power Contracts
On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with FERC against AE Supply seeking FERC action to modify prices payable to AE Supply under three trade confirmations between Merrill Lynch and NPC. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with Merrill Lynch under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers. On December 19, 2002, the Administrative Law Judge (“ALJ”) issued findings that no contract modification was warranted. The ALJ determined in favor of NPC that AE Supply, rather than Merrill Lynch, was a proper subject of NPC’s complaint.
On June 26, 2003, FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others, and did not render a decision on whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, FERC issued an order, on rehearing, affirming its conclusion that the long-term contracts should not be modified. Snohomish County and other parties filed petitions for review of FERC’s June 26, 2003 order with the U.S. Court of Appeals for the Ninth Circuit (the “NPC Petitions”). On December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. The Ninth Circuit heard oral argument in these cases on December 8, 2004. The NPC Petitions were consolidated in the Ninth Circuit. AE Supply intends to vigorously defend against these actions but cannot predict their outcomes.
Sierra/Nevada
On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (the “Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted claims against AE and AE Supply for: (1) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (2) conspiracy and (3) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada filed an amended complaint on May 30, 2003, which asserted a fourth cause of action against AE and AE Supply for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys’ fees and seeks in excess of $850 million under the RICO count. AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. AE Supply intends to vigorously defend against this action but cannot predict its outcome.
Litigation Involving Merrill Lynch
AE and AE Supply entered into an asset purchase agreement with Merrill Lynch and affiliated parties in 2001, under which AE and AE Supply purchased Merrill Lynch’s energy marketing and trading business for approximately $489 million and an equity interest in AE Supply of nearly 2%. The asset purchase agreement provided that Merrill Lynch would have the right to require AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest calculated from March 16, 2001 in the event that certain conditions were not met.
On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the U.S. District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million. On September 25, 2002, AE and AE Supply filed an action against Merrill Lynch in New York state court. The complaint in that action alleged that Merrill Lynch fraudulently induced AE to enter into the purchase agreement and that Merrill Lynch breached certain representations and warranties contained in the agreement.
On May 29, 2003, the U.S. District Court for the Southern District of New York denied AE’s motion to stay Merrill Lynch’s action and ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York state court, as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply dismissed the New York state action and filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the U.S. District Court for the Southern District of New York. The counterclaims, as amended, allege that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, that Merrill Lynch negligently misrepresented certain facts relating to the purchase agreement and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims seek damages in excess of $605 million, among other relief.
On November 24, 2003, the court dismissed AE and AE Supply’s counterclaim for rescission and struck their demand for a jury trial. AE and AE Supply’s counterclaims for fraudulent inducement, breach of contract, negligent misrepresentation and breach of fiduciary duty and their request for punitive damages with respect to certain counterclaims remain in place.
On February 2, 2005, the parties filed separate motions for summary judgment, which were opposed and have been fully briefed. The trial has been scheduled for May 2005.
The federal government is holding certain assets of Daniel L. Gordon, the former head of energy trading for AE Supply. Both AE and Merrill Lynch have filed petitions with the U.S. District Court for the Southern District of New York claiming rights to the funds. On August 13, 2004, the U.S. Attorney filed a motion to dismiss the petitions filed by AE and Merrill Lynch on the grounds that neither AE nor Merrill Lynch had an interest in the specific property seized by the government at the time Gordon committed his offense. On September 30, 2004, AE filed an opposition to the government’s motion to dismiss.
AE and AE Supply intend to vigorously pursue these matters but cannot predict their outcomes.
Putative Shareholder, Benefit Plan Class Actions and Derivative Action
From October 2002 through December 2002, plaintiffs claiming to represent purchasers of AE’s securities filed 14 putative class action lawsuits against AE and several of its former senior managers in U.S. District Courts for the Southern District of New York and the District of Maryland. The complaints alleged that AE and senior management violated federal securities laws when AE purchased Merrill Lynch’s energy marketing and trading business with the knowledge that the business was built on illegal wash or round-trip trades with Enron, which the complaints alleged artificially inflated trading revenue, volume and growth. The complaints asserted that AE’s fortunes fell when Enron’s collapse exposed what plaintiffs claim were illegal trades in the energy markets. All of the securities cases were transferred to the District of Maryland and consolidated. The plaintiffs filed an amended complaint on May 3, 2004 that alleged that the defendants violated federal securities laws by failing to disclose weaknesses in Merrill Lynch’s energy marketing and trading business, as well as other internal control and accounting deficiencies. The amended complaint seeks unspecified compensatory damages and equitable relief. On July 2, 2004, the defendants moved to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding.
In February and March 2003, two putative class action lawsuits were filed against AE in U.S. District Courts for the Southern District of New York and the District of Maryland. The suits alleged that AE and a senior manager violated the Employee Retirement Income Security Act of 1974 (“ERISA”) by: (1) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (2) failing to diversify plan assets; (3) failing to monitor investment alternatives; (4) failing to avoid conflicts of interest and (5) violating fiduciary duties. The ERISA cases were consolidated in the District of Maryland. On April 26, 2004, the plaintiffs in the ERISA cases filed an amended complaint, adding a number of current and former directors of AE as defendants and clarifying the nature of their claims. On June 25, 2004, the defendants filed a motion to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding.
In June 2003, a shareholder derivative action was filed against AE’s Board of Directors and several former senior managers in the Supreme Court of the State of New York for the County of New York. The suit alleges that the Board and senior management breached fiduciary duties to AE that have exposed AE to the securities class action lawsuits. The derivative action has been stayed pending the commencement of discovery in the securities cases.
AE intends to vigorously defend against these actions but cannot predict their outcomes.
Claims Related to Alleged Asbestos Exposure
The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of
historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties in these actions are seeking an allocation of responsibility for historic and potential future asbestos liability.
During the pendency of these actions, Allegheny will continue to receive payments from one of its insurance companies in the amount of $625,000, payable on each of July 1, 2005 and 2006. During 2004 and 2003, Allegheny received insurance proceeds of approximately $960,000 and $1.8 million, respectively, in connection with these cases. Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2004, Allegheny had 1,504 open cases remaining. Allegheny intends to vigorously defend against these actions, but cannot predict their outcomes.
Suits Related to the Gleason Generating Facility
Allegheny Energy Supply Gleason Generating Facility, LLC, a subsidiary of AE Supply, is the defendant in a suit brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generation facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the generation facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generation facility. They seek a restraining order with respect to the operation of the plant and damages of $200 million. A mediation session was held on June 17, 2004, but the parties did not reach settlement. AE has undertaken property purchases and other mitigation measures. AE intends to vigorously defend against this action but cannot predict its outcome.
AE Supply has demanded indemnification from Siemens Westinghouse, the manufacturer of the turbines used in the Gleason Generating Facility, pursuant to the terms of the related equipment purchase agreement. On October 17, 2002, Siemens Westinghouse filed a declaratory judgment action in the Court of Common Pleas of Allegheny County, Pennsylvania, against AE Supply and its subsidiary seeking a declaration that the prior owner released Siemens Westinghouse from this liability through a release executed after AE Supply purchased the Gleason facility. On May 6, 2004, AE Supply filed a motion for summary judgment to dismiss the declaratory judgment action. The motion for summary judgment was granted on September 7, 2004. On October 6, 2004, Siemens Westinghouse appealed the dismissal of the declaratory judgment action. Allegheny intends to vigorously defend against this action but cannot predict its outcome.
SEC Matters
On October 9, October 25 and November 5, 2002, AE received subpoenas from the SEC. The subpoenas principally concerned: (1) the departure of Daniel L. Gordon; (2) AE’s litigation with Merrill Lynch; (3) AE Supply’s valuation and management of its trading business; (4) AE’s November 4, 2002 press release concerning its financial statements; (5) the departure of AE’s and its subsidiaries’ Controller, Thomas Kloc, in June 2002 and (6) AE’s acquisition of power plants from Enron. AE and AE Supply responded to the subpoenas.
On January 16, 2004, the SEC requested that AE voluntarily produce certain documents in connection with an informal investigation of AE, and the SEC has since requested the voluntary production of additional documents. AE has responded to the SEC’s request for documents. The SEC also has taken testimony from several current and former employees and has expressed an intention to take testimony from several additional current and former employees. AE is cooperating fully with the SEC.
EPMI Adversary Proceeding
AE Supply and Enron Power Marketing, Inc. (“EPMI”) were involved in an adversary proceeding which EPMI filed on May 9, 2003. Following mediation, a settlement was reached resolving all outstanding issues and a settlement agreement was executed and filed with the Bankruptcy Court for its approval. The terms of the settlement are confidential. The Bankruptcy Court approved the settlement on December 2, 2004 and dismissed EPMI’s complaint with prejudice on December 16, 2004.
LTI Arbitration
On April 22, 2004, Leasing Technologies International, Inc. and its shareholders (collectively, “LTI”) filed a demand for arbitration against Allegheny Ventures and AE before the American Arbitration Association. In December 2000, Allegheny Ventures entered into an agreement to acquire LTI, an equipment leasing company. Allegheny Ventures terminated the agreement on May 4, 2003. LTI alleges that the termination of the agreement was unjustified and seeks damages in an unspecified amount for breach of the agreement, as well as other consequential damages. On June 11, 2004, AE and Allegheny Ventures filed an answer to LTI’s demand, denying all claims. The arbitration hearing is scheduled to begin on May 16, 2005. Allegheny intends to vigorously defend against the claims in the arbitration, but cannot predict its outcome.
Ordinary Course of Business
The registrants are from time to time involved in litigation and other legal disputes in the ordinary course of business. Each registrant is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders of AE, AGC or Potomac Edison during the fourth quarter of 2004. At the annual meeting of Monongahela’s shareholders held on December 7, 2004, votes were taken for the election of directors. The total number of votes cast was 5,891,000, with all votes being cast for the election of Paul J. Evanson, John P. Campbell, Joseph H. Richardson and Jeffrey D. Serkes.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANTS’ COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
AE’s common stock is publicly traded. There are no established trading markets for the common equity securities of AGC, Monongahela or Potomac Edison.
AE
“AYE” is the trading symbol for AE’s common stock on the New York, Chicago and Pacific Stock Exchanges. As of March 7, 2005, there were 28,360 holders of record of AE’s common stock. The table below shows the high and low sales prices of AE’s common stock on the New York Stock Exchange for the periods indicated:
AE did not pay any dividends on its common stock during 2003 or 2004. The terms of AE’s credit facilities and the indenture governing its convertible preferred securities do not permit the payment of dividends. AE is also subject to regulatory constraints concerning dividend payments, including under PUHCA.
In July 2003, AE’s Board of Directors voted to redeem the share purchase rights issued under AE’s Stockholder Protection Rights Agreement (the “Rights Agreement”). AE terminated the Rights Agreement, effective December 6, 2004, and the share purchase rights issued under it became null and void.
Monongahela
AE owns 100% of the outstanding shares of common stock of Monongahela. Monongahela paid dividends on its common stock of approximately $8.2 million, $5.0 million, $9.0 million and $11.0 million on March 31, 2004, June 30, 2004, September 30, 2004 and December 31, 2004, respectively. Monongahela paid dividends on its common stock of approximately $8.7 million, $7.7 million, $10.2 million and $17.0 million on March 31, 2003, June 30, 2003, September 30, 2003 and December 31, 2003, respectively. Monongahela’s charter limits the payment of dividends on common stock. Monongahela is also subject to regulatory constraints under PUHCA concerning dividend payments on common stock.
Potomac Edison
AE owns 100% of the outstanding common stock of Potomac Edison. Potomac Edison paid dividends on its common stock of approximately $8.7 million, $8.1 million, $12.1 million and $14.1 million on March 31, 2004, June 30, 2004, September 30, 2004 and December 31, 2004, respectively. Potomac Edison paid dividends on its common stock of approximately $9.0 million, $7.8 million, $5.6 million and $8.1 million on March 31, 2003, June 30, 2003, September 30, 2003 and December 31, 2003, respectively.
AGC
Monongahela and AE Supply own approximately 23% and 77%, respectively, of the outstanding shares of common stock of AGC. AGC paid dividends on its common stock of approximately $5.5 million and $7.0 million on March 31, 2004 and June 30, 2004, respectively. AGC did not pay any dividends on its common stock for the third and fourth quarters of 2004. AGC paid dividends on its common stock of approximately $3.5 million, $3.5 million, $3.5 million and $2.0 million on March 31, 2003, June 30, 2003, September 30, 2003 and December 31, 2003, respectively.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
Notes:
(a)
See Notes 1-11, 14, 27 and 28 to the Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2001, 2002, 2003 and 2004.
(b)
Certain amounts for years prior to 2002 have been reclassified for comparative purposes, including the effects of Emerging Issues Task Force Issue No. 02-3 “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” (“EITF 02-3”) as discussed in Note 5, “Wholesale Energy Activities,” to the Consolidated Financial Statements.
(c)
In 2004, AE and certain of its subsidiaries entered into agreements to sell, or made the decision to sell, certain non-core assets. The results of operations related to these assets have been reclassified to discontinued operations for all prior periods presented. See Note 4, “Assets Held for Sale and Discontinued Operations,” to the Consolidated Financial Statements for additional information.
(d)
Long-term debt at December 31, 2002 of $3,662.2 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003, the debt was reclassified as long-term.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Notes:
(a)
See Notes 1-7, 9, 20 and 21 to Monongahela’s Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2001, 2002, 2003 and 2004.
(b)
In 2004, Monongahela entered into agreements to sell, or made the decision to sell, certain non-core assets. The results of operations related to these assets have been reclassified to discontinued operations for all prior periods presented, as applicable. See Note 4, “Assets Held for Sale and Discontinued Operations,” to Monongahela’s Consolidated Financial Statements for additional information.
(c)
Long-term debt at December 31, 2002 of $690.1 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003, the debt was reclassified as long-term.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Notes:
(a)
See Notes 1-8 and 18 to Potomac Edison’s Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2001, 2002, 2003 and 2004.
(b)
Long-term debt at December 31, 2002 of $416.0 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003, the debt was reclassified as long-term.
ALLEGHENY GENERATING COMPANY
Notes:
(a)
See Notes 1-5 and 14 to AGC’s Consolidated Financial Statements for factors and transactions that affect trends and comparability of financial data for the years 2001, 2002, 2003 and 2004.
(b)
Long-term debt at December 31, 2002 of $99.3 million was classified as short-term as a result of debt covenant violations. As of December 31, 2003, the debt was reclassified as long-term.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
Allegheny is an integrated energy business that owns and operates electric generation facilities and delivers electric and natural gas services to customers in Pennsylvania, West Virginia, Maryland, Virginia and Ohio. AE, Allegheny’s parent holding company, was incorporated in Maryland in 1925 and is registered as a holding company under PUHCA. Allegheny operates its business primarily through AE’s various directly and indirectly owned subsidiaries.
Allegheny has two business segments:
•
The Delivery and Services segment includes Allegheny’s electric and natural gas T&D operations.
•
The Generation and Marketing segment includes Allegheny’s power generation operations.
The Delivery and Services Segment
The principal companies and operations in AE’s Delivery and Services segment include the following:
•
The Distribution Companies include Monongahela (excluding its West Virginia generation assets), Potomac Edison and West Penn. Each of the Distribution Companies is a public utility company and does business under the trade name Allegheny Power. The Distribution Companies’ principal businesses are the operation of electric and natural gas public utility systems.
•
Monongahela conducts an electric T&D business in northern West Virginia and an adjacent portion of Ohio. Monongahela also conducts a natural gas T&D business, primarily through Mountaineer. In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia, subject to certain conditions. The sale is expected to be completed in mid- to late-2005. Monongahela also has generation assets, which are included in the Generation and Marketing Segment. See “The Generation and Marketing Segment” below.
•
Potomac Edison operates an electric T&D system in portions of Maryland, Virginia and West Virginia.
•
West Penn operates an electric T&D system in southwestern, north and south-central Pennsylvania.
In April 2002, the Distribution Companies transferred operational control over their transmission systems to PJM. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.
•
Allegheny Ventures is a nonutility, unregulated subsidiary of AE that engages in telecommunications and unregulated energy-related projects. Allegheny Ventures has two principal wholly owned subsidiaries, ACC and AE Solutions. ACC develops fiber-optic projects, including fiber and data services. AE Solutions manages energy-related projects.
The Generation and Marketing Segment
The principal companies and operations in AE’s Generation and Marketing segment include the following:
•
AE Supply owns, operates and manages electric generation facilities. AE Supply also purchases and sells energy and energy-related commodities, although it no longer engages in speculative trading activities.
•
Monongahela’s West Virginia generation assets are included in the Generation and Marketing segment.
•
AGC was incorporated in Virginia in 1981. AGC is owned approximately 77% by AE Supply and approximately 23% by Monongahela. All of AGC’s revenues are derived from sales of its 985 MW share of generation capacity from the Bath County generation station to AE Supply and Monongahela.
AE Supply is obligated under long-term contracts to provide the Distribution Companies with the power that they need to meet a majority of their PLR obligations. The Generation and Marketing segment sells power into PJM and purchases power from PJM to meet its obligations to the Distribution Companies under these contracts. See “The PJM Market and the Distribution Companies’ PLR Obligations” below.
Although most of the Generation and Marketing segment’s generation capacity participates in the PJM system, it owns generation capacity outside of PJM, including AGC’s interest in the Bath County generation station and generation facilities in Gleason, Tennessee and Wheatland, Indiana. The Gleason and Wheatland generation facilities have been classified as held for sale, and their results have been presented as discontinued operations in the accompanying Consolidated Statements of Operations.
The Generation and Marketing segment also purchases and sells power in wholesale markets. However, AE Supply exited its speculative trading activities in the Western U.S. trading markets and elsewhere in 2003 and has implemented a strategy to focus on asset based optimization and hedging within its geographic region.
For more information regarding the AE segments and subsidiaries discussed above, see “Business-Overview.”
Intersegment Services
AESC was incorporated in Maryland in 1963 as a service company for AE. AE, AE Supply, AGC, the Distribution Companies, Allegheny Ventures and their respective subsidiaries have no employees. These companies reimburse AESC at cost for services provided to them by AESC’s employees. AESC had approximately 5,100 employees as of December 31, 2004.
The PJM Market and the Distribution Companies’ PLR Obligations
Allegheny’s business has been significantly influenced by state and federal deregulation initiatives, including the implementation of retail choice and plans to transition from cost-based to market-based rates, as well as by the development of wholesale electricity markets and RTOs, such as PJM.
Each of the states in Allegheny’s service territory, other than West Virginia, has, to some extent, deregulated its electric power industry. Pennsylvania, Maryland, Virginia and Ohio have instituted retail customer choice and are transitioning to market-based, rather than cost-based, pricing. In West Virginia, the rates charged to retail customers are regulated by the West Virginia PSC and are determined through traditional, cost-based, regulated utility rate-making. See “Business-Regulatory Framework Affecting Allegheny-State Legislation, Rate Matters and Regulatory Developments.”
The Distribution Companies have PLR obligations to their customers in Pennsylvania, Maryland, Virginia and Ohio. As “providers of last resort,” the Distribution Companies must supply power to retail customers who have not chosen alternative providers (or have chosen to return to Allegheny service) at rates that are capped at various levels during the applicable transition period. While these capped rates were determined based on the cost of producing power, they are generally lower than recent prevailing market prices for power.
In April 2002, the Distribution Companies transferred functional control of their transmission assets to PJM. PJM is the largest wholesale electricity market in the world and acts as an RTO, coordinating the movement of electricity over the transmission grid in all or portions of Delaware, Illinois, Maryland, New Jersey, Pennsylvania, West Virginia, Ohio, Virginia and the District of Columbia. The Distribution Companies have adopted PJM’s transmission pricing methodology, including PJM’s congestion management system.
The Distribution Companies have long-term contracts with AE Supply under which AE Supply provides the Distribution Companies with a majority of the power necessary to meet their PLR retail obligations. These
contracts have both fixed-price and market-based pricing components. The amount of power purchased under these contracts subject to the market-based pricing component increases each year through the applicable transition period. Not all of these costs can be passed on to customers.
Allegheny has a generation fleet that is anchored by 10 base-load coal-fired units. Most of Allegheny’s generation assets participate in the PJM system. The Generation and Marketing segment sells the power that it generates into PJM and purchases through PJM the power necessary to meet its obligations to the Distribution Companies. Historically, the Distribution Companies’ PLR obligations have absorbed the majority of Allegheny’s generation capacity. The Generation and Marketing segment sells power into PJM at prices determined through a competitive bidding process. The prices that it receives in the PJM market vary depending upon demand and other market conditions. Prices generally are higher at times of peak demand and lower during off-peak periods.
PJM directs, or “dispatches,” individual generation stations within its system to produce power. Depending on market conditions, line congestion, plant availability and other factors across the PJM system, an individual generation station within PJM may be available but may not be dispatched, if power is available from another station at a lower cost. Thus, at any given time, the Generation and Marketing segment’s generation facilities may or may not be dispatched, without regard to the PLR or other obligations of the Distribution Companies.
Challenges and Response
Prior to 1999, Allegheny functioned as an integrated regulated utility within its service area. In response to federal and state deregulation initiatives, however, Allegheny separated its energy generation business from its T&D business by transferring the majority of its generation assets to AE Supply. Allegheny’s former senior management sought to transform AE Supply into a national power merchant in order to capitalize on these regulatory and other energy industry trends. As part of this strategy, AE Supply acquired generation assets, which collectively expanded Allegheny’s owned or controlled generation capacity by nearly one-third. AE Supply also began construction of new generation facilities. In addition, AE Supply purchased the energy trading division of Merrill Lynch in 2001. With this acquisition, the focus of AE Supply’s energy trading shifted from asset backed, short-term trading in and around its generation assets to more speculative trading activities. This expansion was financed primarily through debt.
Beginning in 2002, difficult market conditions, changes in the regulatory environment and Allegheny’s worsening credit profile placed Allegheny in a weakened financial position, which continued during 2003 and into 2004. Beginning in 2003, Allegheny’s new senior management implemented recovery plans and new long-term strategies.
Allegheny’s long-term strategy is to focus on its core generation and T&D businesses. Allegheny’s management believes that this emphasis will enable Allegheny to take advantage of its regional presence, operational expertise and market knowledge. Specific goals for enhancing long-term value include:
•
Restoring Financial Strength. Beginning in 2003, Allegheny significantly improved its liquidity and overall financial strength. Allegheny’s management believes that it can continue this trend by:
•
Focusing on the Core Business. Allegheny has reoriented its business to focus on its core businesses and assets. In 2003, Allegheny exited its speculative trading activities in the Western U. S. and other energy markets. In addition, Allegheny has sold, or is seeking to sell, non-core assets.
•
Substantially Reducing and Proactively Managing Debt. Between December 1, 2003 and January 31, 2005, Allegheny repaid approximately $1.2 billion of debt. Allegheny’s goal is to reduce its debt by an additional $300 million by the end of 2005. Allegheny intends to continue its debt reduction efforts by applying some of its cash flow from operations and the proceeds from asset sales to the repayment of debt. The extent to which Allegheny utilizes these alternatives will depend upon the terms that are available to it and their impact on its financial condition, long-term value and overall strategy.
•
Improving Liquidity. Allegheny is improving its liquidity through prudent cash management, opportunistic sales of non-core assets, cutting costs and expenses, extending debt maturities and obtaining a revolving credit facility. For example, in December 2004, AE Supply completed the sale of its Lincoln Generating Facility and an accompanying tolling agreement for $175.0 million in cash, subject to certain post-closing adjustments. Also in December 2004, AE sold a portion of its interest in OVEC for $102 million in cash, $96 million of which was received at the closing of the transaction and the remaining $6 million of which is expected to be paid after March 13, 2006, upon the satisfaction of certain conditions. The proceeds from these transactions were used to repay debt. AE and AE Supply also completed refinancings in 2004 that extended the maturities and lowered the interest rates of much of their debt and established a revolving credit facility for AE. See “Financial Condition, Requirements and Resources-Liquidity and Capital Requirements.”
•
Maximizing Operational Efficiency. Allegheny is working to maximize the availability and operational efficiency of its physical assets, particularly its supercritical generation plants. In addition, Allegheny is seeking to optimize operations and maintenance costs for its generation facilities and T&D assets and related corporate functions, to reduce costs and to pursue other productivity improvements necessary to build a high-performance organization.
•
Maximizing Generation Value. Allegheny is working to maximize the value of the power that it generates by ensuring full recovery of its costs and a reasonable return through the traditional rate-making process for its regulated utilities, as well as through the transition to market-based rates for AE Supply and its subsidiaries.
•
Managing Environmental Compliance and Risks. Allegheny is working to effectively manage its environmental compliance efforts to ensure continuing compliance with applicable federal and state regulations while controlling its compliance costs, reducing emissions levels and minimizing its risk exposure.
•
Rebuilding the Management Team. Allegheny rebuilt its management team in 2003 and 2004.
Key Indicators and Performance Factors
The Delivery and Services Segment
Allegheny monitors the financial and operating performance of its Delivery and Services segment using a number of indicators and performance statistics, including the following:
Revenue per MWh sold. This measure is calculated by dividing total revenues from retail sales of electricity by total MWhs sold to retail customers. Revenue per MWh sold in 2004, 2003 and 2002 was as follows:
Operations and maintenance costs (“O&M”). Management closely monitors and manages O&M in absolute terms, as well as in relation to total revenues.
Capital expenditures. Management manages and prioritizes capital expenditures to meet operational needs and regulatory requirements within available cash flow constraints.
Heating degree-days (“HDD”) and cooling degree-days (“CDD”). HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65 degrees Fahrenheit, which is considered normal. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65 degrees Fahrenheit. The regulated utility operations of the Distribution
Companies are weather sensitive. Weather conditions directly influence the customer demand for electricity (or natural gas) delivered by the regulated utility. In addition, regulated utility rates are determined, in part, on the basis of expected normal weather conditions. Accordingly, deviations in weather from normal levels can affect Allegheny’s financial performance. Normal (historical) HDD are 5,605 and normal (historical) CDD are 776, calculated on a weighted-average basis across the geographic areas served by the Distribution Companies. The following table shows actual HDD and CDD for the years indicated:
The Generation and Marketing Segment
Allegheny monitors the financial and operating performance of its Generation and Marketing segment using a number of indicators and performance statistics, including the following:
kWh generated. This is a measure of the total physical quantity of electricity generation and is monitored at the individual unit level, as well as various unit groupings.
Equivalent availability factor (“EAF”). The EAF is a measure of a generation unit’s availability to generate electricity. A unit’s availability is commonly less than 100%, primarily as a result of unplanned outages or scheduled outages for planned maintenance. Allegheny monitors EAF by individual unit, as well as by various unit groupings. One such grouping is all “supercritical” units. A supercritical unit utilizes steam pressure in excess of 3,200 psi. This design characteristic enables these units to be larger and more efficient than other generation units. Fort Martin, Harrison, Hatfield’s Ferry and Pleasants are supercritical units. These units generally operate at high capacity for extended periods of time.
Station operations and maintenance costs (“Station O&M”). Station O&M includes base maintenance, operations and special maintenance. Base maintenance and operations costs consist of normal recurring expenses related to the day-to-day on-going operation of the generation station. Special maintenance includes outage, outage related or system projects that relate to all of the generation stations. In addition, special maintenance includes cost of removal and loss from retirement of assets of the unregulated portion of the Generation and Marketing segment.
Capital expenditures. Management manages and prioritizes capital expenditures to meet operational needs and regulatory requirements within available cash flow constraints.
The following table shows kWhs generated, EAFs and Station O&M for supercritical units and for all generating units:
Contracted coal position. This measure represents the physical quantity of coal available under firm purchase contracts in force, expressed as a percentage of the estimated quantity of coal that will be consumed in future periods. As of February 17, 2005, Allegheny’s contracted coal positions into 2005, 2006 and 2007 were approximately 95%, 65% and 55%, respectively.
Primary Factors Affecting Allegheny’s Performance
The principal business, economic and other factors that affect Allegheny’s operations and financial performance include:
•
changes in regulatory policies and rates,
•
changes in the competitive electricity marketplace,
•
coal plant availability,
•
weather conditions,
•
environmental compliance costs,
•
changes in the PJM market, rules and policies,
•
availability and access to liquidity and changes in interest rates,
•
cost of fuel (natural gas and coal), and
•
labor costs.
Operating Statistics
The following table provides kWh sales information for electricity.
*
includes retail and wholesale and other
The following table provides cubic feet sales information, excluding transportation and wholesale for the natural gas operations, which are reflected in discontinued operations at December 31, 2004.
Critical Accounting Estimates
The following represent the critical accounting estimates for Allegheny and its consolidated subsidiaries, where applicable.
Use of Estimates: The preparation of financial statements in accordance with GAAP requires Allegheny to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the period covered. The estimates that require management’s most difficult, subjective and complex judgments involve the fair value of commodity contracts and derivative instruments, goodwill, unbilled revenues, regulatory assets and liabilities, pension and other postretirement benefit costs, long-lived assets and contingent liabilities. Significant changes in these estimates could have a material effect on Allegheny’s consolidated results of operations, cash flows and financial position.
Commodity Contracts: Allegheny has commodity contracts that are recorded at their fair value. Changes in the fair value of these contracts are recognized in earnings under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133-an amendment of FASB Statement No. 133,” (“SFAS No. 137”), SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities-an amendment of FASB Statement No. 133,” (“SFAS No. 138”) and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” (“SFAS No. 149”) (collectively referred to as “SFAS No. 133”). Fair values for exchange-traded instruments, principally futures and certain options, are based on actively quoted market prices. Management estimates the fair value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options and swaps, using available and estimated market data and pricing models. These estimates may change from time to time.
Inputs to the pricing models may include estimated forward natural gas and electricity prices, interest rates, estimates of market volatility for natural gas and electricity prices, the correlation of natural gas and electricity prices and other factors, such as generation unit availability and location, as appropriate. These inputs require significant judgments and assumptions. Allegheny also adjusts the fair value of commodity contracts to reflect uncertainty in prices, operational risks related to generation facilities and risks related to the performance of counterparties. These inputs and adjustments become more challenging, and the models become less precise, the further into the future these estimates are made. Actual effects on Allegheny’s consolidated financial position, cash flows and results of operations may vary significantly from expected results if the judgments and assumptions underlying the inputs to these models are wrong or the models prove to be unreliable.
During 2003, Allegheny exited its trading positions in the Western U.S. and other national energy markets. In conjunction with its exit from these positions, Allegheny recognized significant realized and unrealized losses during 2003. As of December 31, 2004, the majority of the fair value included in Allegheny’s trading portfolio was related to interest rate swap agreements and commodity cash flow hedges.
Allegheny’s accounting for commodity contracts is discussed in Note 5, “Wholesale Energy Activities,” to the Consolidated Financial Statements. Also, see Note 10, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements and “Financial Condition, Requirements and Resources-Derivative Instruments and Hedging Activities” below, for additional information regarding Allegheny’s accounting for derivative instruments under SFAS No. 133.
Excess of Cost Over Net Assets Acquired (Goodwill): As of December 31, 2004, Allegheny’s intangible asset for acquired goodwill was $367.3 million related to the acquisition of its energy marketing and trading business from Merrill Lynch in March 2001. Allegheny tests goodwill for impairment at least annually. In 2002, Allegheny recorded a goodwill impairment charge of $130.5 million related to its Delivery and Services segment. The estimation of the fair value of Allegheny’s reporting units (an operating segment or one level below an operating segment) involves the use of present value measurements and cash flow models. This process
involves judgments on a broad range of information, including, but not limited to, market pricing assumptions for future electricity revenues, future generation output and projected operating expenses and capital expenditures. Significant changes in the fair value estimates could have a material effect on Allegheny’s results of operations and financial position.
Unbilled Revenues: Unbilled revenues are primarily associated with the Distribution Companies. Energy sales to individual customers are based on their meter readings, which are performed on a systematic basis throughout the month. At the end of each month, the amount of energy delivered to each customer after the last meter reading is estimated, and the Distribution Companies recognize unbilled revenues related to these amounts. The unbilled revenue estimates are based on daily generation, purchases of electricity and natural gas, estimated customer usage by customer type, weather effects, electric and natural gas line losses and the most recent consumer rates. A significant change in these estimates and assumptions could have a material effect on Allegheny’s consolidated results of operations and financial position.
Regulatory Assets and Liabilities: The Distribution Companies charge cost-based rates that are regulated by various federal and state regulatory agencies. As a result, the Distribution Companies qualify for the application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”), which recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets or liabilities arise as a result of a difference between GAAP, excluding the effects of rate regulation, and the economic effect of decisions by regulatory agencies. Regulatory assets generally represent incurred costs that have been deferred, because they are likely to be recovered through customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for various reasons.
The Distribution Companies recognize regulatory assets and liabilities in accordance with the rulings of their federal and state regulators. Future regulatory rulings may affect the carrying value and accounting treatment of Allegheny’s regulatory assets and liabilities at each balance sheet date. Allegheny assesses whether the regulatory assets are likely to be recovered in the future by considering factors such as changes in the regulatory environment, recent rate orders issued by the applicable regulatory agencies and the status of any pending or potential deregulation legislation. Assumptions and judgments used by regulatory authorities continue to have an effect on the recovery of costs, the rate of return on invested capital and the timing and amount of assets to be recovered by rates. A change in these assumptions may have a material effect on Allegheny’s results of operations, cash flows and financial position.
Accounting for Pensions and Postretirement Benefits Other Than Pensions: Allegheny accounts for pensions under SFAS No. 87, “Employers’ Accounting for Pensions,” (“SFAS No. 87”) and other postretirement benefits under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” (“SFAS No. 106”). Under these rules, certain assumptions are made that represent significant estimates. There are many factors and significant assumptions involved in determining Allegheny’s pension and other postretirement benefit obligations (“OPEB”) and costs each period, such as employee demographics (including, among others, age, life expectancies and compensation levels), discount rates, expected rates of return on plan assets, estimated rates of future compensation increases, medical inflation and the fair value of assets funded for the plan. See Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to the Consolidated Financial Statements for additional information concerning these assumptions. Changes made to provisions for pension or other postretirement benefit plans may also affect current and future pension and OPEB costs. Allegheny’s assumptions are supported by historical data and reasonable projections and are reviewed annually with an outside actuarial firm.
In determining its net periodic cost for pension benefits and for OPEB for 2004, Allegheny utilized a 6.0% discount rate and an expected long-term rate of return on plan assets of 8.5%. The discount rate for 2003 was 6.5%, and the expected long-term rate of return on plan assets for 2003 was 9.0%. The expected long-term rate of return on plan assets and the discount rate used to develop the net periodic benefit costs for 2005 are 8.5% and 5.9%, respectively. See Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to the Consolidated Financial Statements for additional assumptions used in determining net periodic benefit costs for these benefit plans.
In determining its liability, also referred to as the “benefit obligation,” for OPEB at September 30, 2004 (the measurement date), Allegheny utilized a 5.9% discount rate and an expected long-term rate of return on plan assets of 8.5%. The discount rate was 6.0% in 2003. The expected long-term rate of return on plan assets was 8.5% in 2003. See Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions,” to the Consolidated Financial Statements for additional assumptions used in determining the benefit obligations for these benefit plans.
In selecting an assumed discount rate, Allegheny reviews various Aa bond yields. Allegheny also performs a yield-curve equivalent rate analysis to derive the discount rate that most accurately matches the observed yields in the market for various maturities of debt to the duration of our liabilities. The 8.5% expected rate of return on plan assets for 2005 is based on projected long-term equity and bond returns and asset allocations. The following table shows the effect that a one percentage point increase or decrease in the 5.9% discount rate and the 8.5% expected rate of return on plan assets for 2005 would have on Allegheny’s pension and other postretirement benefits obligations and costs:
Long-Lived Assets: Allegheny’s Consolidated Balance Sheets include significant long-lived assets that are not subject to recovery under SFAS No. 71. As a result, Allegheny must generate future cash flows from these assets in a non-regulated environment to ensure that the carrying values of these assets are not impaired. Some of these assets are the result of capital investments that have been made in recent years and have not yet reached a mature life cycle. Allegheny assesses the carrying amount and potential impairment of these assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors Allegheny considers in determining if an impairment review is necessary include significant underperformance of the assets relative to historical or projected future operating results, a significant change in Allegheny’s use of the assets or business strategy related to the assets and significant negative industry or economic trends. When Allegheny determines that an impairment review is necessary, it compares the expected undiscounted future cash flows to the carrying amount of the asset. If the carrying amount of the asset is larger, Allegheny recognizes an impairment loss equal to the amount by which the carrying amount of the asset exceeds the fair value of the asset. In these cases, Allegheny determines fair value by the use of quoted market prices, appraisals or valuation techniques, such as expected discounted future cash flows. Allegheny must make assumptions regarding these estimated future cash flows and other factors to determine the fair value of the asset. Significant changes to these assumptions could have a material effect on Allegheny’s consolidated results of operations and financial position.
Contingent Liabilities: Allegheny has established reserves for estimated loss contingencies when management has determined that a loss is probable and the amount can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known, or circumstances change, that affect the previous assumptions with respect to the likelihood or the amount of loss. Reserves for contingent liabilities are based upon management’s assumptions and estimates and advice of legal counsel or other third parties regarding the probable outcomes of the matter. If the ultimate outcome were to differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be recognized. Contingent liabilities for Allegheny include, but are not limited to, restructuring liabilities, legal, environmental and other commitments and contingencies.
ALLEGHENY ENERGY, INC.-RESULTS OF OPERATIONS
Income (Loss) Summary
ALLEGHENY ENERGY, INC.-CONSOLIDATED RESULTS OF OPERATIONS:
This section is an overview of AE’s consolidated results of operations, which are discussed in greater detail for each segment in “Allegheny Energy, Inc.-Discussion of Segment Results of Operations” below.
Operating Revenues
Total operating revenues for 2004, 2003 and 2002, after the reclassification of operating revenues related to discontinued operations as more fully described in Note 4, “Assets Held for Sale and Discontinued Operations,” to the Consolidated Financial Statements were as follows:
*
In accordance with EITF 02-3, revenues related to energy trading are reported net, which resulted in negative revenue amounts in 2003 and 2002. See Note 5, “Wholesale Energy Activities,” to the Consolidated Financial Statements for additional information.
Operating Income
Operating income increased $785.7 million for 2004, primarily as a result of a $516.4 million increase in wholesale and other revenue, a $211.8 million decrease in operating expenses and a $66.1 million increase in retail electric revenue. Wholesale revenue increased due to a reduction in energy trading losses, primarily as a result of AE Supply’s exit from trading activities in the Western U.S. energy markets in 2003. Operating expenses decreased primarily due to decreases in salaries and wages, employee benefits, outside services and other expenses. Retail electric revenue increased due to higher kWh sales resulting from increases in the average number of customers served and customer usage.
Operating loss decreased $276.1 million for 2003, primarily due to write-offs during 2002 related to cancelled generation projects and other investments determined to be impaired, as well as workforce reduction expenses recorded in 2002.
Continuing Operations
Income from continuing operations before income taxes and minority interest increased $726.8 million for 2004, primarily due to the $785.7 million increase in operating income discussed above and a $22.6 million decrease in interest expense and preferred dividends, partially offset by an $81.5 million decrease in other income. Interest expense decreased as a result of lower interest rates and lower average debt outstanding. Other income decreased primarily as a result of a $75.8 million gain recognized during 2003 on the reapplication of SFAS No. 71 by Monongahela and Potomac Edison.
Loss from continuing operations before income taxes and minority interest decreased $274.1 million for 2003, primarily due to a $276.1 million decrease in operating loss and a $153.5 million increase in other income, partially offset by a $155.5 million increase in interest expense and preferred dividends.
Income Tax Expense
The effective tax rates for Allegheny’s continuing operations were 37.3%, 39.4% and 39.8% for 2004, 2003 and 2002, respectively. The effective tax rates for 2004, 2003 and 2002 are higher than the federal statutory tax rate, primarily as a result of state income taxes. The effective tax rate for 2003 is higher than the federal statutory rate as a result of the reapplication of SFAS No. 71 and the amortization of deferred investment tax credits. The effective tax rate for 2002 is higher than the federal statutory rate as a result of the amortization of deferred investment tax credits.
Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. Management believes that Allegheny’s accrued tax liabilities are adequate and does not expect any settlement related to this examination to have a material impact on Allegheny’s consolidated statement of operations, financial position or cash flow.
See Note 15, “Income Taxes,” to the Consolidated Financial Statements for additional information.
Discontinued Operations
Allegheny recorded losses from discontinued operations of $440.3 million, $25.3 million and $36.4 million for the years ended December 31, 2004, 2003 and 2002, respectively, related to agreements to sell, or decisions to sell, certain non-core assets. See Note 4, “Assets Held for Sale and Discontinued Operations,” to the Consolidated Financial Statements for additional information.
Other Comprehensive Income (Loss)
The components of other comprehensive income (loss) include an adjustment related to the recognition of a minimum pension liability and changes in the fair value of available-for-sale securities and cash flow hedges. Other comprehensive income (loss) for 2004 was $16.5 million and included a $14.6 million adjustment related to the minimum pension liability and an increase in the unrealized loss on cash flow hedges of $2.1 million, net of $0.1 million representing the ineffective portion of the cash flow hedges. The adjustment related to the minimum pension liability was due in part to a decrease in the discount rate used to determine the benefit obligation from 6.0% in 2003 to 5.9% in 2004. Other comprehensive income (loss) for 2003 was $61.8 million, representing an adjustment related to the minimum pension liability. This adjustment was primarily due to an increase in the pension obligation caused by a 33.7% increase in the actuarial loss and a decrease in the discount rate used to determine the benefit obligation from 6.5% in 2002 to 6.0% in 2003.
ALLEGHENY ENERGY, INC.-DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:
AE’s Delivery and Services Segment
Operating Revenues
Retail electric revenues increased $66.1 million for 2004, primarily due to increases in residential, commercial and industrial sales of $30.8 million, $16.7 million and $18.4 million, respectively. Residential and commercial revenues increased due to higher MWh sales resulting from increases in customer usage and in the average number of customers served. The increase in residential and commercial customer usage was primarily due to an increase in cooling degree-days, partially offset by a decrease in heating degree-days. Industrial revenues increased due to higher MWh sales resulting from increases in customer usage and in the average number of customers served.
Retail electric revenues increased $40.2 million for 2003, primarily due to increased residential sales resulting from increases in the average number of customers served and in customer usage. The increase in usage was primarily due to an increase in average heating degree-days.
Retail electric revenues include T&D revenues from customers who chose alternate electricity generation suppliers. Approximately 0.1% of Allegheny’s regulated customers in Pennsylvania, Maryland, Virginia and Ohio in 2003 and 2004 chose alternate electricity generation suppliers.
The return of customers to full service results in an increase in revenues due to the addition of a generation charge that Allegheny had not collected while the customers were using an alternative electricity supplier. The return of customers to PLR service does not affect T&D sales, because Allegheny determines sales on the basis of kWh delivered to customers, regardless of their electricity supplier.
Transmission services and bulk power revenues decreased $7.8 million for 2004, primarily due to a $13.1 million decrease in wholesale revenues as a result of the expiration of certain wholesale contracts in 2003 and a $1.6 million decrease in bulk power revenues as a result of outages. These decreases were partially offset by a $6.9 million increase in transmission revenues due to an increase in PJM transmission service revenue. The Delivery and Services segment’s transmission services and bulk power revenues decreased $26.4 million for 2003, primarily due to decreases in affiliated bulk power revenue and wholesale revenue.
On April 2, 2002, the Distribution Companies transferred functional control of their transmission assets to PJM. As part of its approval of the transfer of control, FERC permitted a transmission rate surcharge designed to allow the Distribution Companies to recover $85.0 million in revenues that would otherwise not be collectible once they joined PJM. In 2004, 2003 and 2002, the Distribution Companies recovered approximately $35.0 million, $27.0 million and $23.0 million of these surcharges, respectively. These amounts are included in transmission services and bulk power revenues. FERC also allowed the Distribution Companies to collect a surcharge to recover the costs associated with Allegheny’s integration into PJM, which expired at the end of 2004. Accordingly, the Distribution Companies have fully recovered all of these surcharges as of December 31, 2004.
Unregulated services revenues decreased $2.6 million for 2004, primarily due to the timing of revenues related to progress on the construction of generation facilities for the Southern Mississippi Electric Power
Association (“SMEPA”), which is accounted for under the percentage of completion method of accounting. The Delivery and Services segment’s unregulated services revenues decreased $605.7 million for 2003, primarily as a result of the sale of Alliance Energy Services, LLC (“Alliance Energy Services”) in December 2002.
Operating Expenses
Purchased Power and Transmission: Purchased power and transmission represents power purchases from, and exchanges with, other companies (primarily AE Supply) as well as purchases from qualified facilities under PURPA. Purchased power and transmission consists of the following items:
Purchased power and transmission from PURPA generation increased $1.4 million for 2004, primarily due to a $7.7 million increase in expenses as a result of the receipt during 2003 of a contractually required payment from one of the PURPA generation facilities that supplies power to Monongahela, which did not recur in 2004. This increase was partially offset by a $4.7 million decrease in expenses at West Penn due to lower prices and MWhs purchased. The increase in purchased power and transmission from PURPA generation was also partially offset by a $1.7 million decrease in expenses at Potomac Edison due to lower MWhs purchased resulting from increased outages and lower MWhs generated at lower average prices.
Purchased power and transmission from PURPA generation decreased $3.8 million for 2003, primarily due to the receipt of contractually required payment from the PURPA generation facility described above. This amount was partially offset by an overall 6.1% increase in MWhs generated by other PURPA generation facilities. The PURPA cost on a cents per kWh basis reflected in the table above does not reflect the receipt of the contractually required payment in 2003.
Other purchased power primarily consists of the Distribution Companies’ purchases of energy from AE Supply. The Distribution Companies have long-term power sales agreements with AE Supply, under which AE Supply provides them with the majority of the power necessary to meet their PLR obligations. These agreements have both fixed-price and market-based pricing components. The amount of power purchased under these agreements that is subject to the market-based pricing component increases each year through the applicable transition periods. Other purchased power increased $68.4 million for 2004, primarily due to an increase in prices resulting from the market-based pricing component of these agreements and an increase in volume. The increase in volume was due to higher MWhs purchased in response to increased demand from the Distribution Companies. Other purchased power increased $38.9 million for 2003, primarily due to an increase in AE Supply’s prices resulting from the market-based pricing component of the power sales agreements. The market-based pricing component of these agreements has no overall effect on Allegheny’s consolidated operating income.
Cost of Natural Gas Sold: Cost of natural gas sold for 2004, 2003 and 2002 was as follows:
Cost of natural gas sold represents the cost of natural gas for delivery to customers. No such cost was incurred for 2004 or 2003. Cost of natural gas sold decreased $526.3 million for 2003 due to the sale of Alliance Energy Services in December 2002. Alliance Energy Services historically accounted for a majority of the cost of natural gas sold. Cost of natural gas sold attributable to Monongahela’s West Virginia natural gas operations has been reclassified to discontinued operations for all periods presented.
Workforce Reduction Expenses: Workforce reduction expenses of $51.1 million for 2002 were allocated to the Delivery and Services segment. See Note 9, “Restructuring Charges and Workforce Reduction Expenses,” to the Consolidated Financial Statements for additional information.
Deferred Energy Costs, Net: Deferred energy costs net, for 2004, 2003 and 2002 were as follows:
Deferred energy costs, net, increased $1.8 million for 2004. Deferred energy costs, net, are related to the recovery of net costs associated with purchases from the AES Warrior Run Cogeneration Facility. For a detailed discussion of the AES Warrior Run cogeneration facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for Potomac Edison. These deferred energy costs are offset by similar amounts included in operating revenues or operating expenses and have no impact on operating income.
Operations and Maintenance: Operations and maintenance expenses for 2004, 2003 and 2002 were as follows:
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 decreased $50.2 million for 2004. This decrease was due to a $15.4 million decrease in insurance expense, a $15.2 million decrease in outside services and contract work expense, an $11.3 million decrease in employee benefits expense and a $7.4 million decrease in salaries and wages expense. The decrease in insurance expense was due to a reduction in costs for potential claims alleging exposure to asbestos. The decrease in outside service and contract work expense was the result of decreased use of independent contractors and consultants. The decrease in employee benefits expense reflects a $10.0 million decrease in SERP and Executive Life Insurance Plan (“ELIP”) expenses, primarily due to costs recorded in 2003 for certain executives, and a $6.3 million decrease in disability costs, principally related to costs recorded in 2003 in accordance with SFAS No. 112, Employers’ Accounting for Postemployment Benefits-an Amendment of FASB Statements No. 5 and No. 43” (“SFAS No. 112”). These amounts were partially offset by a $5.4 million increase in pension expense resulting from reductions in both the discount rate and expected long-term rate of return on pension plan assets. The decrease in salaries and wages expense was the result of a decrease in the number of employees.
Operations and maintenance expenses decreased $39.8 million for 2003. This decrease was primarily due to a $57.6 million decrease in expenses, primarily as a result of reductions in equipment procurement and subcontracting costs associated with Allegheny Energy Solutions’ engineering and construction project for SMEPA. This amount was partially offset by a $14.6 million increase in contract work and outside services expense and a $13.3 million increase in employee benefits expense.
Depreciation and Amortization: Depreciation and amortization expenses for 2004, 2003 and 2002 were as follows:
Depreciation and amortization expense decreased $3.4 million for 2004, primarily due to an adjustment to the remaining useful life of software and a decrease in the amortization of regulatory assets. These decreases were partially offset by increased depreciation and amortization resulting from additions to property, plant and equipment.
Total depreciation and amortization expenses increased $6.9 million for 2003. This increase was primarily due to additions of property, plant and equipment.
Taxes Other Than Income Taxes: Taxes other than income taxes for 2004, 2003 and 2002 were as follows:
Taxes other than income taxes primarily include gross receipts taxes, payroll taxes and property taxes. Taxes other than income taxes increased $8.7 million for 2003, primarily as a result of increased gross receipts taxes due to an increase in regulated utility revenues.
Other Income and Expenses, Net
Other income and expenses, net for 2004, 2003 and 2002 were as follows:
Other income and expenses, net, represent non-operating income and expenses before income taxes. Other income and expenses, net, decreased $19.0 million for 2004, primarily as a result of a gain recognized in 2003 related to the reapplication of the provisions of SFAS No. 71 by Potomac Edison to generation assets in West Virginia and sales of land.
Other income and expenses, net, increased $84.9 million for 2003, primarily due to decreased losses related to equity earnings in non-affiliates, decreased losses on disposal of assets and a gain recognized in 2003 related to the reapplication of SFAS No. 71. See Note 14, “Accounting for the Effects of Price Regulation” and Note 23, “Other Income and Expenses, Net,” to the Consolidated Financial Statements for additional details.
Interest Expense and Preferred Dividends
Interest expense and preferred dividends for 2004, 2003 and 2002 were as follows:
Interest expense and preferred dividends increased $2.4 million for 2004, primarily due to an $8.5 million increase in interest expense associated with the July 2003 issuance, by AE Capital Trust I (“Capital Trust”), a wholly owned special purpose finance subsidiary of AE, of mandatorily-convertible trust preferred securities and a $4.3 million increase in interest expense on first mortgage bonds. The increase in interest expense on first mortgage bonds is due primarily to Monongahela’s bridge loan, which was refinanced with proceeds from its June 2004 issuance of first mortgage bonds, and the one-month overlaps between Monongahela’s and Potomac Edison’s issuances of new first mortgage bonds and their redemptions of outstanding first mortgage bonds. These increases were partially offset by a $10.5 million decrease in interest expense as a result of the repayment of notes and bonds by West Penn.
Interest expense and preferred dividends decreased $1.4 million for 2003, primarily as a result of decreased average debt outstanding during 2003, resulting from the repayment and redemption of debt during the year.
For additional information regarding Allegheny’s short-term and long-term debt, see the Consolidated Statements of Capitalization, Note 3, “Capitalization,” and Note 16, “Short-Term Debt,” to the Consolidated Financial Statements. Also, see “Financial Condition, Requirements and Resources-Liquidity and Capital Requirements” for additional information concerning Allegheny’s debt and financing transactions.
Minority Interest in Net Loss
Minority interest in net loss was $2.0 million for 2002, which primarily represents The Energy Corporation of America’s minority interest in Alliance Energy Services. Alliance Energy Services was sold on December 31, 2002.
Discontinued Operations
The Delivery and Services segment recorded losses from discontinued operations of $14.0 million for 2004 and income from discontinued operations of $9.2 million and $1.3 million for 2003 and 2002, respectively. These amounts related to the agreement to sell Monongahela’s West Virginia natural gas operations. Comparative information has been reclassified to reflect these results as discontinued operations. See Note 4, “Assets Held For Sale and Discontinued Operations,” to the Consolidated Financial Statements for additional information.
Cumulative Effect of Accounting Changes, Net
In connection with their adoption of SFAS No. 143 on January 1, 2003, entities within Allegheny’s Delivery and Services segment recorded charges of $1.2 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2003. See Note 11, “Asset Retirement Obligations,” to the Consolidated Financial Statements for additional information.
In connection with their adoption of SFAS No. 142 on January 1, 2002, entities within Allegheny’s Delivery and Services segment recorded a charge of $130.5 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2002. See Note 8, “Goodwill and Other Intangible Assets,” to the Consolidated Financial Statements for additional information.
AE’s Generation and Marketing Segment:
Operating Revenues
Operating revenues for the Generation and Marketing segment were as follows:
*
Amounts are net of energy trading losses as described in Note 5, “Wholesale Energy Activities,” to the Consolidated Financial Statements. Energy trading losses include unrealized losses of $5.7 million, $468.4 million and $358.4 million for 2004, 2003 and 2002, respectively.
Operating revenues increased by $582.5 million for 2004. This increase was primarily due to a decrease in energy trading losses in 2004 as a result of AE Supply’s exit from speculative energy trading activities in the Western U.S. energy markets during 2003. Allegheny estimates that operating revenues for 2004 were reduced by approximately $130 million as a result of the unplanned plant outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1 during the first half of the year. Operating revenues for 2004 include $68.1 million of proceeds associated with the sale of the CDWR contract and related hedge transactions that were released from escrow in 2004.
Revenue from affiliates: Revenue from affiliates results primarily from the sale of power to the Distribution Companies.
The Distribution Companies have long-term power sales agreements with AE Supply under which AE Supply provides the Distribution Companies with a majority of the power necessary to meet their PLR obligations. These agreements have both fixed-price and market-based pricing components. The amount of
power purchased under these agreements that is subject to the market-based pricing component increases each year through the applicable transition period. Monongahela’s West Virginia generation facilities also provide power at fixed prices to Monongahela’s Delivery and Services segment to meet its PLR obligations.
The average rate at which the Generation and Marketing segment sold power to the Distribution Companies was $32.41, $31.80 and $31.11 per MWh for the years ended December 31, 2004, 2003 and 2002, respectively.
Revenue from affiliates increased $66.1 million and $30.8 million for 2004 and 2003, respectively, primarily due to increased sales volume and increased prices under long-term power sales agreements with the Distribution Companies.
Wholesale and other revenues, net: The table below describes the significant components of wholesale revenues in 2004. Wholesale revenues have been accumulated in these categories beginning in 2004 in connection with the Generation and Marketing segment’s change in strategy to eliminate speculative trading. Comparative amounts for these components are not available for 2003 and 2002.
*
Does not include a $45.0 million loss on a contract with an affiliate that was included in affiliated revenues. The net trading gain, including this affiliated transaction, was $16.7 million. This contract expired on December 31, 2004 and was not renewed.
Wholesale and other revenues increased $516.4 million for 2004. This increase was primarily due to a decrease in energy trading losses in 2004 as a result of AE Supply’s exit from speculative trading activities in the Western U.S. energy markets in 2003. Revenues in 2004 include $68.1 million in proceeds associated with escrow proceeds related to the sale of the CDWR contract and related hedge transactions that were released from escrow in 2004. The net PJM purchases component of 2004 revenues was negatively impacted by outages at the Hatfield’s Ferry and Pleasants generation stations.
The realized and unrealized components of wholesale and other revenues in 2003 and 2002 were as follows:
Wholesale and other revenues increased $11.9 million in 2003 primarily due to a decrease in trading losses. The net realized and unrealized losses for 2003 resulted primarily from speculative trading activities in the Western U.S. energy markets, which AE Supply exited in 2003. For further information, see “Roll Forward of Fair Value” below.
The table below outlines components of total trading losses associated with exiting the Western U.S. energy markets. These losses were partially offset by trading gains associated with trading and wholesale operations in other national energy markets, net of trading losses associated with terminating or selling other energy trading positions.
Fair Value of Contracts: During 2003 and 2002, AE Supply engaged in the trading of electricity, natural gas, oil, coal and other energy-related commodities in a number of different markets. During 2003, AE Supply implemented a revised strategy to focus on its core generation business and, accordingly, did not enter into new speculative trading positions. AE Supply is currently qualifying certain of its new contracts under the “normal purchase and normal sale” scope exception under SFAS No. 133, and thereby accounts for these contracts on the accrual method, rather than marking these contracts to market value. AE uses derivative accounting for contracts that do not qualify under the scope exception. These contracts are recorded at fair value in the Consolidated Balance Sheets. The realized and unrealized revenues from energy trading activities are recorded on a net basis in “Operating revenues” in the Consolidated Statements of Operations in accordance with EITF 02-3. As a result of AE Supply’s exit from the Western U.S. energy markets and the related termination or sale of trading positions in other national energy markets in 2003, the fair value of the remaining trading portfolio consists primarily of interest rate swap agreements and commodity cash flow hedges as of December 31, 2004.
The fair values of trading contracts, which represent the net unrealized gain and loss on open positions, are recorded as assets and liabilities, after applying the appropriate counterparty netting agreements in accordance with FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts-an Interpretation of APB Opinion No. 10 and FASB Statement No. 105.” At December 31, 2004, the fair values of trading contract assets and liabilities were $17.2 million and $97.3 million, respectively. At December 31, 2003, the fair values of trading contract assets and liabilities were $29.9 million and $102.6 million, respectively.
The following table disaggregates the net fair values of derivative contract assets and liabilities as of December 31, 2004, based on the underlying market price source and the contract settlement periods. The table excludes non-derivatives such as AE Supply’s generation assets, PLR requirements and SFAS No. 133 scope exceptions under the normal purchase and normal sale election:
In the table above, each contract is classified by the source of fair value, based upon the individual settlement dates within an entire contract. Therefore, portions of a single contract may be assigned to multiple
classifications based upon the source of the underlying market prices used to determine the fair value of the contract. AE Supply determines fair value based on prices actively quoted from various industry services, broker quotes and the New York Mercantile Exchange. Electricity markets are generally liquid for approximately one year, and most natural gas markets are generally liquid for approximately three years. Thereafter, some market prices can be observed, but market liquidity is less robust. A majority of the fair value of the contracts included in the table above are interest rate swaps and commodity cash flow hedges.
Approximately $1.4 million of AE Supply’s contracts were classified as “prices based on models,” even though a portion of these contracts is valued based on observable market prices. The most significant variables to the models that AE Supply uses to value these contracts are the forward prices for both electricity and natural gas. These forward prices are based on observable market prices to the extent prices are available in the market. Generally, electricity forward prices are actively quoted for about one year, and some observable market prices are available for about three years. After three years, the forward prices for electricity are based on the forward price of natural gas and a marginal heat rate for generation (based on more efficient natural gas-fired generation) to convert natural gas into electricity. For natural gas, forward prices are generally actively quoted for about three years, and some observable market prices are available for about five years. Beyond five years, natural gas prices escalate based on trends in prior years.
For settlements of less than one year, the fair value of AE Supply’s contracts was a net liability of $27.3 million, primarily related to interest rate swaps and commodity cash flow hedges. See Note 10, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements for additional information.
Roll Forward of Fair Value: Net unrealized losses of $5.7 million for 2004 and $468.4 million (excluding the cumulative effect of accounting change attributable to EITF 02-3 of $19.7 million) for 2003 were recorded on the Consolidated Statements of Operations in “Operating revenues” to reflect the change in fair value of the trading contracts. The following table provides a roll forward of the net fair value, or trading contract assets less trading contract liabilities, of AE Supply’s contracts for 2004 and 2003:
*
Amounts reflect $(2.3) million and $14.3 million of option premium expirations for 2004 and 2003, respectively.
As shown in the table above, the net fair value of AE Supply’s trading contracts decreased by $7.4 million. This decrease was primarily the result of the effect of price movements on commodity contracts, partially offset by scheduled periodic payments related to interest rate swaps and commodity contracts that were settled in 2004. The 2003 decrease in the net fair value of AE Supply’s trading contracts was primarily the result of net unrealized losses associated with AE Supply’s exit from speculative trading activities in the Western U.S. energy markets during 2003.
During 2003, AE Supply also refocused its trading operations in order to reduce the volatility and cash collateral requirements associated with that business by exiting unfavorable tolling agreements, engaging in mutual terminations and close-outs to reduce open trading positions and assigning and/or disposing of non-core trading positions.
There has been, and may continue to be, significant volatility in the market prices for electricity and natural gas at the wholesale level, which will affect AE Supply’s operating results and cash flows. Similarly, volatility in interest rates will affect AE Supply’s operating results and cash flows.
Operating Expenses
Fuel Consumed in Electric Generation: Fuel consumed in electric generation represents the cost of coal, natural gas, oil, lime and other materials consumed in the generation of power and emission allowances.
Total fuel expenses increased by $22.4 million for 2004, primarily due to a $34.1 million increase in natural gas costs for the gas-fired units, an $8.5 million increase due to the consolidation of Hunlock Creek Energy Ventures, LLC (“Hunlock Creek”) in 2004 and a $7.1 million increase in emission allowances. These increases were partially offset by a $27.4 million decrease in costs for coal and oil fired units, primarily due to reduced generation and increased efficiency, which were partially offset by a 2.1% increase in average fuel prices. Allegheny estimates that fuel costs for 2004 were reduced by approximately $37 million as a result of the outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1. Total fuel expenses increased by $15.4 million for 2003, primarily due to a 4.0% increase in average fuel prices.
Purchased Power and Transmission: Purchased power and transmission includes power purchases and gas pipeline transmission costs.
Purchased power and transmission increased $10.1 million for 2004, primarily due to an increase of $10.8 million related to the release to a third party of Kern River pipeline capacity. AE Supply’s election of normal purchase and normal sale scope exception in accordance with SFAS No. 133 also contributed to the increase in purchased power and transmission. However, this increase was offset by the impact of the consolidation of Hunlock Creek in accordance with FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities.” See Note 26, “Variable Interest Entities,” to the Consolidated Financial Statements for additional information.
Purchased power and transmission decreased $56.3 million for 2003, primarily due to a decrease in wholesale market prices and additional generation capacity available for sale in the PJM market, as well as AE Supply’s exit from the retail energy business in 2002.
Gain on Sale of OVEC Power Agreement and Shares: On December 31, 2004, AE sold a 9% equity interest in OVEC to Buckeye. In addition, AE Supply assigned to Buckeye all of its rights and obligations under a new OVEC inter-company power agreement that is effective on March 13, 2006. However, AE Supply will retain its rights under the current agreement to 9% of the power from the OVEC electric generation facilities through March 12, 2006. The sale resulted in a gain of $94.8 million, before income taxes ($60.0 million, net of income taxes), which is recorded in “Gain on sale of OVEC power agreement and shares” on the Consolidated Statements of Operations. AE recorded a gain of $6.2 million, before income taxes ($4.0 million, net of income taxes), and AE Supply recorded a gain of $88.6 million, before income taxes ($56.0 million, net of income taxes). Cash proceeds from the sale were $102.0 million, of which $6 million is expected to be received in March
2006 upon the fulfillment of certain post-closing obligations. The remaining $96.0 million in proceeds was used to reduce debt in January 2005. AE retained a 3.5% equity interest in OVEC, and Monongahela retained its rights to 3.5% of OVEC’s power output.
Workforce Reduction Expenses: Workforce reduction expenses of $56.2 million were allocated to the Generation and Marketing Segment in 2002. See Note 9, “Restructuring Charges and Workforce Reduction Expenses,” to the Consolidated Financial Statements for additional information.
Operations and Maintenance: Operations and maintenance expenses for 2004, 2003 and 2002 were as follows:
Operations and maintenance expenses decreased $114.1 million for the Generation and Marketing segment for 2004, primarily due to a decrease of $41.1 million in outside services expense. In addition, operations and maintenance expense for 2003 included $33.5 million in impairment charges related to assets held for sale and $32 million of contract termination costs, which did not recur in 2004.
Operations and maintenance expenses decreased $163.2 million for 2003, primarily due to impairment charges of $272.9 million recorded in 2002 related to cancelled generation projects and the reorganization and relocation of Allegheny’s trading division, neither of which recurred in 2003. In addition, reduced rent expenses and other charges associated with the relocation of the segment’s energy trading operations contributed to the decrease. These decreases were partially offset by additional lease termination costs and higher costs associated with outside services and employee benefits.
Depreciation and Amortization: Depreciation and amortization expenses for 2004, 2003 and 2002 were as follows:
Depreciation and amortization expense increased $16.6 million for 2004, primarily due to additions of facilities, including the Springdale generation facility, which was placed in service in July 2003, and the installation of environmental control equipment.
Total depreciation and amortization expenses increased $13.3 million for 2003. This increase was primarily due to additions of facilities, including the Springdale generation facility, which was placed in service in July 2003.
Taxes Other Than Income Taxes: Taxes other than income taxes for 2004, 2003 and 2002 were as follows:
Taxes other than income taxes decreased $3.5 million for 2004, primarily due to decreases in property taxes as a result of lower assessed values and tax settlements. These amounts were partially offset by increases in business and occupation taxes and payroll taxes.
Taxes other than income taxes decreased $9.4 million for 2003, primarily due to a $3.8 million reduction in capital stock and franchise taxes, a $3.1 million reduction in business and occupation taxes, a $1.6 million reduction in gross receipts taxes and a $1.2 million reduction in payroll taxes.
Other Income and Expenses, Net
Other income and expenses, net for 2004, 2003 and 2002 were as follows:
Other income and expenses, net, represent non-operating income and expenses before income taxes. Other income and expenses, net, increased in 2003 and decreased in 2004, primarily as a result of a $61.7 million gain recognized in 2003 related to the reapplication of provisions of SFAS No. 71 by Monongahela to its generation assets in West Virginia.
Interest Expense and Preferred Dividends
Interest expense and preferred dividends for 2004, 2003 and 2002 were as follows:
Interest expense and preferred dividends decreased $24.8 million for 2004, primarily due to interest expense savings of $57.9 million resulting from lower interest rates and lower average debt outstanding. These savings were partially offset by $11.6 million of increased interest expense associated with Capital Trust’s July 2003 issuance of mandatorily-convertible trust preferred securities, a $9.8 million increase in the amortization of debt expenses resulting from the write-off of deferred financing costs due to the refinancing of credit facilities in 2004 and a $12.0 million decrease in capitalized interest primarily resulting from the Springdale generation facility, which was placed in service in July 2003.
Interest expense and preferred dividends increased $151.9 million for 2003, primarily as a result of an increase in average long-term and short-term debt outstanding. The increase in average outstanding debt was the result of financing AE Supply’s trading losses and generation facilities in Springdale, Pennsylvania and St. Joseph, Indiana, as well as higher interest rates resulting from Allegheny’s lower credit rating. The increase in average long-term debt outstanding was primarily the result of AE and AE Supply refinancing their debt in February and March 2003.
For additional information regarding Allegheny’s short-term and long-term debt, see the Consolidated Statements of Capitalization, Note 3, “Capitalization,” and Note 16, “Short-Term Debt,” to the Consolidated Financial Statements. Also, see “Financial Condition, Requirements and Resources-Liquidity and Capital Requirements” for additional information concerning Allegheny’s debt restructuring in 2004 and 2003.
Minority Interest in Net Loss
Minority interest in net loss was $0.9 million, $7.2 million and $11.5 million for 2004, 2003 and 2002, respectively, which primarily represents Merrill Lynch’s equity interest in AE Supply.
Discontinued Operations
The Generation and Marketing segment recorded losses from discontinued operations of $426.4 million, $34.5 million and $37.7 million in 2004, 2003 and 2002. The loss for 2004 was primarily related to the write-down to fair value of the Lincoln, Gleason and Wheatland gas-fired generation facilities, resulting from the Company’s decision to sell these non-core assets, as well as operating losses at these facilities. The losses in 2003 and 2002 primarily related to operating losses at the Lincoln, Gleason and Wheatland facilities. Results of operations of these facilities have been reclassified to discontinued operations for all periods presented. See Note 4, “Assets Held For Sale and Discontinued Operations,” to the Consolidated Financial Statements for additional information.
Cumulative Effect of Accounting Changes, Net
In connection with its adoption of SFAS No. 143, AE Supply recorded a charge of $7.4 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2003. See Note 11, “Asset Retirement Obligations,” to the Consolidated Financial Statements for additional information.
In connection with its adoption of EITF 02-3, AE Supply recorded a charge of $12.2 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2003. See Note 5, “Wholesale Energy Activities,” to the Consolidated Financial Statements for additional information.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES-RESULTS OF OPERATIONS
Income (Loss) Summary
MONONGAHELA POWER COMPANY-CONSOLIDATED RESULTS OF OPERATIONS:
This section is an overview of Monongahela’s consolidated results of operations, which are discussed in greater detail for each segment in “Monongahela Power Company-Discussion of Segment Results of Operations” below.
Operating Revenues
Total operating revenues for 2004, 2003 and 2002, after the reclassification of operating revenues related to discontinued operations as more fully described in Note 4, “Assets Held for Sale and Discontinued Operations” to Monongahela’s Consolidated Financial Statements, were as follows:
Operating Income
Operating income decreased $38.3 million for 2004, primarily due to a decrease in the Generation and Marketing segment’s operating revenues, partially offset by an increase in the Delivery and Services segment’s operating revenues. The decrease in the Generation and Marketing segment’s operating revenues was due to lower bulk power sales and affiliated sales to AE Supply. These sales were lower primarily as a result of decreases in the quantity of electricity produced, due in part to the outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1. The increase in the Delivery and Services segment’s operating revenues was primarily due to an increase in customer sales.
Operating income increased $11.1 million for 2003, primarily due to an increase in Generation and Marketing segment’s operating revenues, which were partially offset by an increase in operating expenses. The increase in the Generation and Marketing operating revenues was primarily a result of increased sales of excess generation to AE Supply at higher average rates.
Continuing Operations
Income from continuing operations before income taxes decreased $98.6 million for 2004, primarily due to decreases in operating revenues and other income and expenses, net.
Income from continuing operations before income taxes increased $70.5 million for 2003, primarily due to an increase in operating revenues, workforce reduction expenses that occurred in 2002 and did not recur in 2003 and an increase in other income and expenses, net. These amounts were partially offset by an increase in operating expenses.
The cumulative effect of accounting change in 2002 of $115.4 million, net of income taxes, reflects a charge for the impairment of goodwill related to the acquisitions of Mountaineer and WVP.
Income Tax Expense
Allegheny allocates income tax expense or benefit to its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause significant fluctuations in the effective income tax rates from the statutory rates for the subsidiaries depending on the level of pre-tax profitability.
The effective tax rates for Monongahela’s continuing operations were (30.2)%, 35.3% and 20.4% for 2004, 2003 and 2002, respectively. The negative effective tax rate for 2004 was primarily due to state tax benefits and investment tax credits applied to a low level of pre-tax income for the year. The 2003 effective tax rate did not significantly differ from the federal statutory tax rate. The 2002 effective tax rate was lower than the federal statutory tax rate, primarily due to tax benefits derived from adjustments to nondeductible reserves, amortization of deferred investment tax credits and the allocation of consolidated tax savings to Monongahela.
See Note 10, “Income Taxes,” to Monongahela’s Consolidated Financial Statements for additional information.
Discontinued Operations
Monongahela recorded a loss from discontinued operations of $13.9 million in 2004 and income from discontinued operations of $9.2 million and $1.3 million in 2003 and 2002, respectively, related to an agreement to sell its West Virginia natural gas operations. Comparative information has been reclassified for all prior periods to reflect these results as discontinued operations. See Note 4, “Assets Held for Sale and Discontinued Operations,” to Monongahela’s Consolidated Financial Statements for additional information.
MONONGAHELA POWER COMPANY-DISCUSSION OF SEGMENT RESULTS OF OPERATIONS:
Monongahela’s Delivery and Services Segment
Operating Revenues
Total operating revenues for 2004, 2003 and 2002, after the reclassification of operating revenues related to discontinued operations as more fully described in Note 4, “Assets Held for Sale and Discontinued Operations,” to Monongahela’s Consolidated Financial Statements, were as follows:
Retail electric revenues increased $12.2 million for 2004, due primarily to increases in residential, commercial and industrial sales resulting from increases in customer usage. The increased usage by residential and commercial customers was due primarily to an increase in cooling degree-days, partially offset by a decrease in heating degree-days. Total revenues remained relatively consistent for 2003.
The following table shows heating degree-days and cooling degree-days, as well as their variance from prior periods and from normal.
Operating Expenses
Purchased Power and Transmission: Purchased power and transmission represents power purchases from, and exchanges with, other companies and purchases from qualified facilities under PURPA. Purchased power and transmission consists of the following items:
Purchased power and transmission from PURPA generation increased $7.7 million for 2004, primarily as a result of the receipt during 2003 of a contractually required payment from one of the PURPA generation facilities that supplies power to Monongahela. This increase was partially offset by lower MWhs generated at lower average prices.
Purchased power and transmission from PURPA generation decreased $11.5 million for 2003, primarily as a result of the receipt of the contractually required payment from the PURPA generation facility described above and an unscheduled shutdown of a PURPA generation facility. These decreases were partially offset by an overall 33.5% increase in MWh generated at two other PURPA generation facilities. The PURPA costs reflected in the table above do not reflect the receipt of the contractually required PURPA payment to Monongahela in 2003.
Other purchased power increased $13.8 million for 2004 and $13.7 million for 2003, primarily due to increases in both the rates for, and volume of, purchased power. Purchased power and transmission for 2004 included $12.0 million of costs associated with serving commercial and industrial customers in Ohio. See “Business-Regulatory Framework Affecting Allegheny-State Legislation, Rate Matters and Regulatory Developments,” for additional information.
Workforce Reduction Expenses: Workforce reduction expenses for 2002 were $17.7 million. See Note 6, “Restructuring Charges and Workforce Reduction Expenses,” to Monongahela’s Consolidated Financial Statements for additional information.
Operations and Maintenance: Operations and maintenance expenses for 2004, 2003 and 2002 were as follows:
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 decreased $27.5 million for 2004. This decrease was primarily due to a $6.4 million decrease in insurance expense, a $5.9 million decrease in costs related to uncollectible accounts, a $5.4 million decrease in employee benefits expense and a $3.2 million decrease in outside service and contract work expense. The decrease in insurance expense was primarily due to lower workers’ compensation expense and lower costs for potential claims alleging exposure to asbestos. The decrease in uncollectible accounts expense was due to bankruptcy expenses recorded for certain customers in 2003. The decrease in employee benefits expense reflects a $3.0 million decrease in SERP and ELIP expenses due to costs recorded in 2003 for certain executives, a $2.8 million decrease in disability costs principally related to costs recorded in 2003 in accordance with SFAS No. 112 and a $1.5 million decrease in costs for other postretirement benefits. These amounts were partially offset by a $1.3 million increase in pension expense resulting from the reductions in the discount rate and expected long-term rate of return on pension plan assets. Contract work and outside services decreased as a result of decreased use of independent contractors and consultants.
Operations and maintenance expenses increased $27.0 million for 2003. This increase was primarily due to actuarially determined reserves for potential claims alleging exposure to asbestos, higher costs related to uncollectible accounts, employee benefits, outside services and actuarially determined workers compensation costs.
Depreciation and Amortization: Depreciation and amortization expenses for 2004, 2003 and 2002 were as follows:
Depreciation and amortization expense increased $1.6 million for 2004, primarily due to increased depreciation as a result of additions to property, plant and equipment.
Taxes Other Than Income Taxes: Taxes other than income taxes for 2004, 2003 and 2002 were as follows:
Taxes other than income taxes primarily include business and occupation taxes, payroll taxes and property taxes. Taxes other than income taxes increased $5.0 million for 2004, primarily due to an increase in business and occupation taxes due to increased taxable kWh sales and a favorable sales and use tax settlement in 2003 that did not recur in 2004. Taxes other than income taxes decreased $1.1 million in 2003, primarily due to a favorable sales tax audit settlement, lower property taxes resulting from a favorable court ruling and lower payroll taxes. These decreases were partially offset by an increase in revenue-based taxes resulting from higher taxable revenues.
Interest Expense
Interest expense for 2004, 2003 and 2002 was as follows:
Interest expense increased $2.6 million for 2004, primarily due to the annual revision in segment allocation factors. Monongahela allocates interest expense between its segments based on a number of factors, including the relative amount of each segment’s identifiable assets. Interest expense increased for the Delivery and Services segment and decreased for the Generation and Marketing segment in 2004 due to a change in the relative amounts of identifiable assets held in each segment.
Interest expense decreased $1.7 million for 2003, primarily due to an increase in the allowance for borrowed funds used during construction and interest capitalized.
Discontinued Operations
Monongahela recorded losses from discontinued operations of $13.9 million for 2004 and income from discontinued operations of $9.2 million and $1.3 million for 2003 and 2002, respectively, related to an agreement to sell its West Virginia natural gas operations. Comparative information has been reclassified for 2003 and 2002 to reflect these results as discontinued operations. See Note 4, “Assets Held For Sale and Discontinued Operations,” to Monongahela’s Consolidated Financial Statements for additional information.
Cumulative Effect of Accounting Change, Net
On January 1, 2002, Monongahela adopted SFAS No. 142 and determined that approximately $195.0 million of goodwill related to its acquisitions of Mountaineer and WVP was impaired. As a result, Monongahela recorded a charge of $115.4 million, net of income taxes, as the cumulative effect of an accounting change as of January 1, 2002. See Note 5, “Goodwill and Other Intangible Assets,” to Monongahela’s Consolidated Financial Statements for additional information.
Monongahela’s Generation and Marketing Segment
Operating Revenues
Total operating revenues for 2004, 2003 and 2002 were as follows:
Revenues represent energy and ancillary services sales to Monongahela’s Delivery and Services segment and energy sales to, net of energy purchases from, AE Supply. Total revenues decreased $38.1 million for 2004, primarily due to decreases in the quantity of electricity produced, including as a result of outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1.
Total operating revenues increased $31.1 million for 2003, primarily as a result of increased sales of excess generation to AE Supply at higher average prices.
Operating Expenses
Fuel Consumed in Electric Generation: Fuel consumed in electric generation represents primarily the cost of coal, lime and other materials consumed in the generation of power and emission allowances.
Total fuel expenses decreased $16.0 million for 2004, primarily due to a 12.4% decrease in kWhs generated as a result of the outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1, partially offset by a 1.7% increase in average fuel prices. Total fuel expenses increased $6.2 million for 2003, primarily due to a 6.1% increase in average fuel prices offset by a 2.3% decrease in kWhs generated.
Purchased Power and Transmission: Purchased power and transmission represents power purchases from, and exchanges with, other companies. Purchased power and transmission for 2004, 2003 and 2002 was as follows:
Purchased power and transmission increased $12.4 million for 2004. This increase was primarily due to increased market purchases resulting from decreases in MWhs generated. The decrease in MWhs generated was a consequence of reduced generation of certain plants due to market conditions and the outages at Hatfield’s Ferry Unit No. 2 and Pleasants Unit No. 1. Purchased power and transmission increased $6.7 million for 2003. This increase was primarily due to higher transmission charges associated with Monongahela joining PJM and increased non-affiliated energy purchases at increased prices.
Workforce Reduction Expenses: Workforce reduction expenses for 2002 were $10.1 million. See Note 6, “Restructuring Charges and Workforce Reduction Expenses,” to Monongahela’s Consolidated Financial Statements for additional information.
Operations and Maintenance: Operations and maintenance expenses for 2004, 2003 and 2002 were as follows:
Operations and maintenance expenses increased $13.0 million for 2004. This increase was primarily due to an increase in contract work related to the generation plant outages during the first six months of 2004.
Operations and maintenance expenses increased $7.6 million for 2003. This increase was primarily due to higher costs associated with employee benefits and outside services.
Depreciation and Amortization: Depreciation and amortization expenses for 2004, 2003 and 2002 were as follows:
Depreciation and amortization expenses increased $1.9 million for 2003, primarily due to increased depreciation resulting from additions to property, plant and equipment.
Taxes Other Than Income Taxes: Taxes other than income taxes for 2004, 2003 and 2002 were as follows:
Taxes other than income taxes primarily include business and occupation taxes, payroll taxes and property taxes. Taxes other than income taxes increased $3.3 million for 2004, primarily due to increases in business and occupation taxes resulting from a tax credit that expired in 2003 and property taxes as a result of a favorable court settlement in 2003 that did not recur in 2004. Taxes other than income taxes decreased $2.8 million for 2003, primarily due to lower property taxes resulting from a favorable court ruling and lower payroll taxes resulting from lower taxable payroll expense, offset by an increase in business and occupation tax resulting from lower available tax credits.
Other Income and Expenses, Net
Other income and expenses, net, for 2004, 2003 and 2002 were as follows:
Other income and expenses, net, represent non-operating income and expenses before income taxes. Other income and expenses, net, decreased $60.3 million for 2004, primarily due to the recognition of a $61.7 million gain related to the reapplication of the provisions of SFAS No. 71 to generation assets in West Virginia that was recorded in the first quarter of 2003.
Other income and expenses, net, increased $63.0 million for 2003, primarily due to the recognition of a gain related to the reapplication of SFAS No. 71 to generation assets in West Virginia. See Note 9, “Accounting for the Effects of Price Regulation,” and Note 16, “Other Income and Expenses, Net,” to Monongahela’s Consolidated Financial Statements for additional details.
Interest Expense
Interest expense for 2004, 2003 and 2002 was as follows:
Interest expense decreased $2.7 million for 2004, primarily due to the annual revision in segment allocation factors. Monongahela allocates interest expense between its segments based on a number of factors, including the relative amount of each segment’s identifiable assets. Interest expense decreased for the Generation and Marketing segment and increased for the Delivery and Services segment in 2004 due to a change in the relative amounts of identifiable assets held in each segment.
Interest expense for 2003 increased $4.4 million, primarily due to a reduction in the allowance for borrowed funds used during construction and interest capitalized.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES-RESULTS OF OPERATIONS
Income Summary
Net income decreased $2.5 million for 2004. This decrease was primarily due to the recognition, during the first quarter of 2003, of a $14.1 million pre-tax gain for the reapplication of SFAS No. 71, which was recorded in other income, a $1.2 million increase in interest expense and a $14.2 million increase in income tax expense. These amounts were partially offset by a $27.1 million increase in operating income, which was primarily the result of increased operating revenue and lower operations and maintenance expense.
Net income increased $7.8 million for 2003. This increase was primarily due to a $19.9 million increase in other income and a $2.1 million decrease in interest expense. These amounts were partially offset by a $9.1 million decrease in operating income and a $5.0 million increase in income tax expense.
Operating Revenues
Total operating revenues for 2004, 2003 and 2002 were as follows:
Operating revenues increased $19.2 million for 2004, primarily due to increased residential and commercial regulated electric revenues, which were partially offset by decreased transmission and bulk power revenues. Residential and commercial revenues increased due to an increase in MWh sales resulting from an increase in the average number of customers served and an increase in customer usage. Transmission and bulk power revenues decreased $10.3 million for 2004, primarily as a result of the expiration of certain bulk power contracts in June 2003.
Operating revenues increased $35.0 million for 2003, primarily due to increased residential and industrial revenues, partially offset by decreased transmission services and bulk power revenues. Residential revenues increased $20.3 million for 2003 due to an increase in kWh sales reflecting an increase in customers served, and an increase in heating degree days. Industrial revenues increased $15.7 million for 2003, primarily as a result of contract renegotiations with customers whose contracts had expired in 2002.
One customer, Eastalco Aluminum Company, accounted for 12.9% and 10.5% of Potomac Edison’s 2004 and 2003 operating revenues, respectively.
The following table shows heating degree-days and cooling degree-days, as well as their variance from prior periods and from normal.
To satisfy its obligations under PURPA, Potomac Edison entered into a long-term contract to purchase capacity and energy from the AES Warrior Run cogeneration facility through the beginning of 2030. Effective July 1, 2000, Potomac Edison was authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run cogeneration 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 on Potomac Edison’s Consolidated Balance Sheets as deferred energy costs, pending subsequent recovery from, or return to, customers through adjustments to the AES Warrior Run Surcharge. Because the AES Warrior Run Surcharge represents a dollar-for-dollar recovery of net contract costs, AES Warrior Run Surcharge revenues or revenues from sales of AES Warrior Run output do not impact Potomac Edison’s net income. Through a competitive bidding process approved by the Maryland PSC, AE Supply was awarded the contract to purchase the output of the AES Warrior Run facility for the period from January 1, 2002 through December 31, 2004. This contract expired and Potomac Edison awarded a new contract to a non-affiliated third party. Revenues from the AES Warrior Run contract are reflected under “Transmission services and bulk power” in the table above.
Effective with bills issued on or after January 8, 2002, distribution rates for Maryland customers decreased. This decrease or “Customer Choice Credit” is a result of rate reductions called for by a settlement agreement approved by the Maryland PSC in December 1999. The Customer Choice Credit will remain in effect until a total of $72.8 million (approximately $10.4 million annually) has been credited to residential customers and a total of $10.5 million (approximately $1.5 million annually) has been credited to commercial and industrial customers. The distribution rate, however, increased in January 2005 due to the expiration of rate caps. This increase will allow for the recovery of a service fee and for an increase in the environmental surcharge.
Operating Expenses
Purchased Power and Transmission: Purchased power and transmission represents power purchases primarily from AE Supply and qualified facilities under PURPA. Purchased power and transmission for 2004, 2003 and 2002 was as follows:
Purchased power and transmission expense increased $3.1 million for 2004, primarily due to a $3.6 million increase in transmission expense and a $1.2 million increase in purchased power, partially offset by a $1.7 million decrease in PURPA expenses. The increase in transmission expense is primarily due to an increase in affiliated company transmission charges and an increase in PJM administration expenses. The increase in purchased power was primarily due to a $0.7 million increase in purchased power from affiliates resulting from higher MWh purchased from AE Supply to service the increased residential, commercial and industrial load. The decrease in PURPA expense was primarily the result of lower generation due to outages.
Purchased power and transmission increased $35.3 million for 2003, primarily due to a 7.7% increase in the price paid per MWh to AE Supply and, to a lesser extent, a 3.8% increase in the MWhs purchased from AE Supply.
Under a revised rate schedule effective January 1, 2001, a portion of the electricity purchased by Potomac Edison from AE Supply is now subject to market-based pricing. Potomac Edison incurred additional purchased electricity costs due to the market-based pricing component of the revised rate schedule of $6.7 million, $12.7 million and $10.8 million in 2004, 2003 and 2002, respectively. See “Quantitative and Qualitative Disclosure About Market Risk,” for additional information.
Deferred Energy Costs, Net: Deferred energy costs, net, are related to the recovery of net costs associated with purchases from the AES Warrior Run cogeneration facility. See “Operating Revenues” above, for additional details.
Workforce Reduction Expenses: Potomac Edison recorded workforce reduction expenses of $12.4 million, before income taxes ($7.5 million, net of income taxes) for 2002. See Note 6, “Restructuring Charges and Workforce Reduction Expenses” to Potomac Edison’s Consolidated Financial Statements.
Operations and Maintenance: Operations and maintenance expenses for 2004, 2003 and 2002 were as follows:
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 decreased $10.2 million for 2004 due to a $3.6 million decrease in insurance expense, a $2.7 million decrease in outside services and contract work, a $2.3 million decrease in salaries and wages expense and a $2.1 million decrease in employee benefits expense. The decrease in insurance expense was due to a reduction in costs for potential claims alleging exposure to asbestos and lower workers’ compensation insurance expense. The decrease in contract work and outside services was a result of a decrease in the use of independent contractors and consultants. The decrease in salaries and wages expense was the result of a decrease in the number of employees. The decrease in employee benefits expense reflects a $2.9 million decrease in SERP and ELIP expenses, primarily due to costs recorded in 2003 for certain executives, and a $1.2 million decrease in disability costs, which were principally related to costs recorded in 2003 in accordance with SFAS No. 112. These amounts were partially offset by a $1.6 million increase in pension expense resulting from reductions in the discount rate and expected long-term rate of return on pension plan assets.
Operations and maintenance expenses increased $15.5 million for 2003, primarily due to actuarially determined reserves for potential claims alleging exposure to asbestos and higher costs associated with employee benefits and outside services.
Depreciation and Amortization: Depreciation and Amortization expenses for 2004, 2003 and 2002 were as follows:
Depreciation and amortization expense increased $1.3 million and $2.1 million for 2004 and 2003, respectively, primarily due to increased depreciation resulting from additions to property, plant and equipment.
Taxes Other Than Income Taxes: Taxes other than income taxes for 2004, 2003 and 2002 were as follows:
Taxes other than income taxes primarily include gross receipts taxes, payroll taxes and property taxes. Taxes other than income taxes decreased by $4.0 million for 2004, primarily due to a $4.9 million adjustment recorded in 2003 for Maryland gross receipts tax and a $1.8 million decrease in property tax, partially offset by a $1.9 million increase in fuel taxes.
Taxes other than income taxes increased $8.0 million for 2003, primarily due to an adjustment for Maryland gross receipts tax and the recognition, in 2002, of a Maryland coal credit subject to gross receipts tax and increased fuel taxes in 2003, partially offset by reduced payroll taxes.
Other Income and Expenses, Net
Other income and expenses, net for 2004, 2003 and 2002 were as follows:
Other income and expenses, net, represent non-operating income and expenses before income taxes. Other income and expenses, net, decreased $14.4 million for 2004, primarily due to the recognition of a $14.1 million gain related to the reapplication of SFAS No. 71 in 2003.
Other income and expenses, net, increased $19.9 million for 2003, primarily due to the recognition of a $14.1 million gain related to the reapplication of SFAS No. 71 and a gain on the sale of land. See Note 8, “Accounting for the Effects of Price Regulation,” and Note 14, “Other Income and Expenses, Net,” to Potomac Edison’s Consolidated Financial Statements for additional information.
Interest Expense
Interest expense for 2004, 2003 and 2002 were as follows:
Interest expense increased $1.2 million for 2004, primarily due to the one month period between the November 2004 issuance of a new series of first mortgage bonds and the December 2004 redemption of an outstanding series of first mortgage bonds, during which time both series were outstanding. Total interest expense decreased $2.1 million in 2003, due primarily to the reduction in short-term debt, including notes payable to affiliates.
Income Tax Expense
Allegheny allocates income tax expense or benefit to its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause significant fluctuations in the effective income tax rates from the statutory rates for the subsidiaries depending on the level of pre-tax profitability.
The effective income tax rates for the years ended December 31, 2004, 2003 and 2002 were 47.8%, 33.7% and 32.4%, respectively. The changes in the effective income tax rates were primarily the result of amortization of regulatory assets, adjustments to reflect differences between filed tax returns and prior estimates and a reduction in Maryland tax credits. See Note 9, “Income Taxes,” to Potomac Edison’s Consolidated Financial Statements for additional information.
ALLEGHENY GENERATING COMPANY-RESULTS OF OPERATIONS
Income Summary
Net income increased $6.6 million for 2004, primarily due to a $4.0 million decrease in interest expense and a $4.7 million decrease in income tax expense. These amounts were partially offset by a $2.0 million decrease in operating income as a result of decreased operating revenues and increased operations and maintenance expense.
Net income increased $2.2 million for 2003 as a result of increased revenues, partially offset by increased income taxes, which resulted from higher pre-tax income.
Operating Revenues
AGC’s only operating asset is an undivided 40% interest in the Bath County, Virginia pumped-storage hydroelectric station and its connecting transmission facilities. During 2004 and 2003, AGC increased its investment in these facilities through expenditures of $9.1 million and $8.7 million, respectively, for the upgrade and overhaul of the Bath County station. Approximately $7.7 million of these capital expenditures were classified as in-service during 2004. The remaining capital expenditures are included within “Construction work in progress” on AGC’s Balance Sheet at December 31, 2004. AGC has no plans for construction of any other major facilities.
Pursuant to an agreement, AE Supply and Monongahela purchase all of AGC’s capacity at prices based on a “cost-of-service formula” wholesale rate schedule (the “revenue requirements”) approved by FERC. AE Supply and Monongahela purchase power from AGC on a proportional basis, based on their respective equity ownership of AGC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment.
Operating revenues decreased $1.3 million for 2004. This decrease was primarily due to a decrease in revenue received from AE Supply and Monongahela resulting from a reduction in the return on debt component. This reduction was attributable to a decrease in debt as a result of repayments of affiliated debt in 2004 and other long-term debt repayments in 2003. Operating revenues increased $6.4 million for 2003, primarily as a result of an additional capital contribution of $40 million from AE Supply and Monongahela.
Operating Expenses:
Operations and Maintenance: Operations and maintenance expenses primarily include salaries and wages, employee benefits, contract work, outside services and other expenses. Operations and maintenance expenses increased $1.0 million for 2004, primarily as the result of an inventory write-down.
Taxes Other Than Income Taxes: Taxes other than income taxes primarily include property taxes.
Interest Expense
Interest expense decreased $4.0 million for 2004, primarily due to $15.0 million in affiliated long-term debt repayments during 2004 and repayments of other long-term debt in 2003.
Income Tax Expense
Allegheny allocates income tax expense or benefit to its subsidiaries pursuant to its consolidated tax sharing agreement. This corporate allocation may cause significant fluctuations in the effective income tax rates from the statutory rates for the subsidiaries depending on the level of pre-tax profitability.
The effective tax rates were 21.0%, 36.5% and 28.8% for 2004, 2003 and 2002, respectively. The effective income tax rates differ from the statutory tax rates primarily due to the effect of state income taxes, benefits derived from the allocation of consolidated tax savings to AGC, the amortization of deferred investment tax credits and depreciation.
See Note 6, “Income Taxes,” to AGC’s Financial Statements for additional information.
FINANCIAL CONDITION, REQUIREMENTS AND RESOURCES
Liquidity and Capital Requirements
To meet cash needs for operating expenses, the payment of interest, retirement of debt and acquisitions and construction programs, Allegheny has historically used internally generated funds (net cash provided by operations less common and preferred dividends) and external financings, including the sale of common and preferred stock, debt instruments, installment loans and lease arrangements. The timing and amount of external financings depend primarily upon economic and financial market conditions and Allegheny’s cash needs and capital structure objectives. The availability and cost of external financings depend upon the financial condition of the companies seeking those funds and upon market conditions.
AE and AE Supply refinanced their bank debt on March 8, 2004. This refinancing provided AE with a $300 million unsecured credit facility, including a $200 million revolving credit facility and a $100 million term loan facility. The $100 million term loan facility remained outstanding at December 31, 2004. There were $11.5 million of outstanding letters of credit drawn against the revolving credit facility resulting in available revolving credit capacity of $188.5 million at December 31, 2004. The March 2004 refinancing also provided AE Supply with $1.25 billion of secured term loans. AE Supply refinanced the outstanding amounts of these loans in October 2004. For more information regarding the March and October refinancings, see “2004 Activity” below.
At December 31, 2004 and 2003, AE had cash and cash equivalents of $189.5 million and $528.6 million, respectively.
Restricted cash balances were $228.9 million and $120.9 million at December 31, 2004 and 2003, respectively. These restricted cash balances include transition charges collected by West Penn and collateral deposits posted as security related to certain contractual obligations. The December 31, 2004 balance also includes $198.3 million of the proceeds from the sale of the Lincoln Generating Facility and the assignment of the OVEC power agreement. These proceeds were used to reduce outstanding debt in January 2005. The December 31, 2003 balance also included $70.8 million of collateral placed in escrow related to the sale of the CDWR contract, which was released in March 2004.
AE had collateral deposits of $88.7 million and $51.2 million at December 31, 2004 and 2003, respectively. These deposits are posted as security with counterparties for various transactions. These amounts are included in “Current assets” on the Consolidated Balance Sheets. Additionally, there were $0.2 million of collateral deposits at December 31, 2004 posted as security with counterparties that is included in “Assets held for sale” on the Consolidated Balance Sheets.
AE also had posted cash collateral of $39.1 million and $39.0 million at December 31, 2004 and 2003, respectively, as security for surety bonds issued by a third party. These funds are invested in a temporary investment fund and are included in the caption “Other” within the “Investments and Other Assets” section of the Consolidated Balance Sheets.
Allegheny’s consolidated capital structure, including short-term debt and liabilities associated with assets held for sale and excluding minority interest, as of December 31, 2004 and 2003, was as follows:
2004 Activity
On March 8, 2004, AE and AE Supply refinanced approximately $1.7 billion of long-term debt with new borrowings in an aggregate amount of $1.55 billion. These new borrowings consisted of a $750 million secured Term B Loan and a $500 million secured Term C Loan (collectively, the “AE Supply Loans”) at AE Supply and unsecured revolving and term loan facilities at AE in the aggregate amount of $300 million (the “New AE Facility” and together with the AE Supply Loans, the “New Loan Facilities”). See Note 3, “Capitalization,” for additional information concerning the March 8, 2004 refinancing and the debt covenants contained in the New Loan Facilities. As discussed below, the AE Supply Loans were refinanced in October 2004.
On June 9, 2004, Monongahela issued $120 million of 6.70% First Mortgage Bonds, which mature on June 15, 2014. The net proceeds of the bond issuance were used to repay Monongahela’s $53.6 million short-term bridge loan in June 2004 and to fund the July 2004 redemption of $40 million of 8.375% First Mortgage Bonds due 2022 and $25 million of 7.25% First Mortgage Bonds due 2007. Interest on the 6.70% First Mortgage Bonds is payable semi-annually in arrears on each June 15 and December 15, commencing December 15, 2004. The bonds are redeemable at Monongahela’s option and rank equally in right of payment with its existing or future first mortgage bonds.
On October 5, 2004, Allegheny sold 10 million shares of its common stock at a price of $15.15 per share directly to institutional investors in a private placement. The proceeds of the sale, and cash on hand, were used to reduce $200 million of debt at AE Supply.
On October 28, 2004, AE Supply refinanced the remaining $1.04 billion outstanding under the AE Supply Loans. In connection with the refinancing of the AE Supply Loans, the Term B Loan and the Term C Loan were consolidated into one loan (the “Refinanced AE Supply Loan”). The Refinanced AE Supply Loan bore interest at a rate per annum equal to LIBOR plus 2.75%. Following the repayment of $200 million of the outstanding balance of the Refinanced AE Supply Loan on January 14, 2005, the per annum interest rate on the Refinanced AE Supply Loan was reduced to LIBOR plus 2.50%. The Refinanced AE Supply Loan will mature on March 8, 2011. See Note 3, “Capitalization,” to the Consolidated Financial Statements for additional information regarding the October 2004 refinancing and the debt covenants contained in the Refinanced AE Supply Loan.
On November 22, 2004, Potomac Edison issued $175 million of 5.35% First Mortgage Bonds, which mature on November 15, 2014. The net proceeds of the bond issuance were used to fund the December 2004 redemption of $55.0 million of 8.0% First Mortgage Bonds due 2022, $45.0 million of 7.75% First Mortgage Bonds due 2023 and $75.0 million of 8.0% First Mortgage Bonds due 2024. Interest on the 5.35% First Mortgage Bonds is payable semi-annually in arrears on each May 15 and November 15, commencing May 15, 2005. The bonds are redeemable at Potomac Edison’s option and rank equally in right of payment with its existing or future unsubordinated indebtedness.
The aggregate amount of debt issued, by entity, during 2004 is shown below:
Redemptions of debt, by entity, during 2004 are listed below:
Certain amounts have been excluded from the tables above as they relate to liabilities associated with assets held for sale as of December 31, 2004. During 2004, there were no issuances and $3.3 million of redemptions of “other notes” related to liabilities associated with assets held for sale.
Allegheny currently anticipates contributing approximately $58 million to fund its pension plans, including $0.3 million to the SERP during 2005. Allegheny also currently anticipates contributing an amount ranging from approximately $27 million to $32 million during 2005 to fund postretirement benefits other than pensions. These anticipated contributions will change if Allegheny’s actuarial assumptions or asset valuation methods change in the future.
Allegheny may seek to engage in further financings to support capital expenditures and to maintain working capital. In addition, Allegheny’s asset optimization, fuel procurement and risk management activities require direct and indirect credit support. As of December 31, 2004, Allegheny had total debt of $5.01 billion, including liabilities associated with assets held for sale.
2003 Activity
During 2003, AE, AE Supply, Monongahela and West Penn entered into agreements with various credit providers to refinance and restructure the bulk of AE, AE Supply and Monongahela’s short-term debt (the “Borrowing Facilities”). The aggregate amount of debt issued under the Borrowing Facilities, is shown below. See Note 3, “Capitalization,” to the Consolidated Financial Statements for additional information regarding the Borrowing Facilities and the defined terms.
The aggregate amount of debt issued, by entity, during 2003 is shown below:
AE repaid $25.0 million of its unsecured credit facility in July 2003 and $33.0 million of its $305.0 million unsecured credit facility during 2003. AE Supply repaid $250 million of its $420 million credit facility in December 2003. Monongahela renegotiated its $10 million unsecured credit facility as part of a $55 million revolving facility of which $53.6 million was drawn and has since been repaid.
Redemptions of debt, by entity, during 2003 are listed below:
On July 24, 2003, Allegheny raised $291 million ($275 million after deducting various fees and placement agents’ commissions) from the issuance to Capital Trust, of units consisting of $300 million principal amount of 11 7/8% Notes due 2008 and warrants for the purchase of up to 25 million shares of AE’s common stock, exercisable at $12 per share. The warrants are mandatorily exercisable if AE’s common stock price equals or exceeds $15 per share over a specified averaging period occurring after June 15, 2006. As of June 15, 2006, AE has the right to redeem the notes at the redemption price of 105.9375% of the principal amount. The warrants are attached to the notes and may be exercised only through the tender of the notes. Capital Trust obtained the proceeds required to purchase the units by issuing $300 million total liquidation amount of its 11 7/8% Mandatorily-Convertible Trust Preferred Securities to investors in a private placement. The preferred securities entitle the holders to receive distributions on a corresponding principal amount of notes and to direct the exercise of warrants attached to the notes in order to effect the conversion of the preferred securities into AE common stock. AE guarantees Capital Trust’s payment obligations on the preferred securities. In accordance with GAAP, the Consolidated Balance Sheets reflect the notes as long-term debt. The notes and AE’s guarantee of the preferred securities are subordinated only to the AE debt under the New AE Facility.
2004 Asset Sales
Lincoln Generating Facility. During the third quarter of 2004, AE Supply recorded a charge against earnings to write-down its investment in the Lincoln Generating Facility to the expected net proceeds from the sale. The write-down resulted in a charge against earnings of $209.4 million, before income taxes ($129.2 million, net of income taxes). This write-down is included in “Loss from discontinued operations, net of tax” in the Consolidated Statements of Operations. The Lincoln Generating Facility is a component of Allegheny’s Generation and Marketing segment. On December 15, 2004, AE Supply sold the Lincoln Generating Facility, together with an associated tolling agreement, to an affiliate of ArcLight Capital Partners, LLC. The sale resulted in a gain of $1.8 million, before income taxes ($1.1 million, net of income taxes), which is recorded in “Loss from discontinued operations, net of tax” on the Consolidated Statements of Operations. Cash proceeds from the sale were $175.0 million, which were used to reduce debt in December 2004 and January 2005.
OVEC. On December 31, 2004, AE sold a 9% equity interest in OVEC to Buckeye. In addition, AE Supply assigned to Buckeye all of its rights and obligations under a new OVEC inter-company power agreement that is expected to become effective on March 13, 2006. However, AE Supply will retain its rights under the current agreement to 9% of the power from the OVEC electric generation facilities through March 12, 2006. The sale resulted in a gain of $94.8 million, before income taxes ($60.0 million, net of income taxes), which is recorded in “Gain on sale of OVEC power agreement and shares” on the Consolidated Statements of Operations. AE recorded a gain of $6.2 million, before income taxes ($4.0 million, net of income taxes) and AE Supply recorded a gain of $88.6 million, before income taxes ($56.0 million, net of income taxes). Cash proceeds from the sale were $102.0 million, of which $6 million is expected to be received in March 2006 upon the fulfillment of certain post-closing obligations. The remaining $96.0 million in proceeds was used to reduce debt in January 2005.
Land Sales. In 2004, West Penn and its subsidiaries completed land sales for aggregate proceeds of $11.1 million.
2003 Asset Sales
Conemaugh Generating Station. On June 27, 2003, AE Supply sold its 83 MW share of the coal-fired Conemaugh Generating Station, located near Johnstown, Pennsylvania, to a subsidiary of UGI Corporation, for approximately $46.3 million in cash and a contingent amount of $5.0 million, which was received on March 3, 2004 after satisfaction of certain post-closing obligations. The sale resulted in a loss to AE Supply of $28.5 million before income taxes in 2003, without considering the contingent amount. In March 2004, AE Supply issued a guarantee to a counterparty in respect of performance under a put option as part of the sale of this asset. The guarantee has a two year term and was determined using a probability weighted cash flow approach. AE Supply recorded a liability of $6.4 million based on the value determined under this approach.
Land Sales. In July 2003, West Penn completed land sales for aggregate proceeds of $9.6 million.
Fellon-McCord and Alliance Energy Services, LLC. In 2002, Allegheny Ventures sold Fellon-McCord, its natural gas and electricity consulting and management services firm and Alliance Energy Services, a provider of natural gas supply and transportation services, to Constellation Energy Group for approximately $21.8 million. The proceeds from this sale were received in January 2003.
Anticipated Asset Sales
Allegheny has made the decision to sell certain non-core assets and has classified these assets as held for sale. See Note 4, “Assets Held for Sale and Discontinued Operations,” for additional information relating to these assets.
Terminated Trading Payments
In 2002, AE Supply was in default under its principal credit agreement after it declined to post additional collateral in favor of several trading counterparties. This default caused 24 trading counterparties to terminate trades with Allegheny by December 31, 2002. Allegheny settled with nine of these trading counterparties for a net cash inflow of $6.8 million in 2002. As of December 31, 2002, Allegheny had recorded accounts receivable of $9.0 million for payments due from terminated trading counterparties and had recorded accounts payable of $40.6 million due to terminated trading counterparties. In 2003, Allegheny established payment schedules with the remaining counterparties, settled the $40.6 million of accounts payable amounts and collected the $9.0 million of accounts receivable amounts. There were no amounts outstanding as of, or since, December 31, 2003 related to this matter.
Dividends
AE did not pay dividends on its common stock in 2004 or 2003. Monongahela paid dividends on its common stock of approximately $33.2 million during 2004 and approximately $43.6 million during 2003. Monongahela paid dividends on its preferred stock of approximately $5.0 million in 2004 and 2003. Potomac Edison paid dividends on its common stock of approximately $43.0 million in 2004 and $30.5 million in 2003. AGC paid aggregate dividends on its common stock to AE Supply and Monongahela of approximately $12.5 million in 2004 and $12.5 million in 2003.
Other Matters Concerning Liquidity and Capital Requirements
Allegheny has various obligations and commitments to make future cash payments under debt instruments, lease arrangements, fuel agreements and other contracts. The tables below summarize the payments due by period for these obligations and commitments, by entity, as of December 31, 2004. The tables below do not include contingent liabilities, liabilities associated with assets held for sale and contractual commitments that were accounted for under fair value accounting. For more information regarding fair value accounting, see “Allegheny Energy, Inc.-Discussion of Segment Results of Operations-AE’s Generation and Marketing Segment.”
Allegheny
*
Does not include debt associated with assets held for sale, unamortized debt expense, discounts, premiums and terminated interest rate swaps that were accounted for as fair value hedges under SFAS No. 133. See Note 10, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements.
**
Does not include amounts associated with assets held for sale.
Allegheny estimates that its capital expenditures for 2005 and 2006 will be $291.2 million and $378.5 million, respectively. These estimates include expenditures of $52.1 million and $129.3 million, respectively, for environmental control technology. See Note 27, “Commitments and Contingencies” to the Consolidated Financial Statements for additional information.
Monongahela
*
Does not include debt associated with assets held for sale, unamortized debt expense, discounts and premiums.
**
Does not include amounts associated with assets held for sale.
Monongahela estimates that its capital expenditures for 2005 and 2006 will be $66.6 million and $80.6 million, respectively. These estimates include expenditures of $12.2 million and $27.2 million, respectively, for environmental control technology. See Note 19, “Commitments and Contingencies,” to Monongahela’s Consolidated Financial Statements for additional information.
Potomac Edison
*
Does not include unamortized debt expense, discounts and premiums.
Potomac Edison estimates that its capital expenditures for 2005 and 2006 will be $72.4 million and $75.8 million, respectively. See Note 18, “Commitments and Contingencies,” to Potomac Edison’s Consolidated Financial Statements for additional information.
AGC
*
Does not include unamortized debt expense, discounts and premiums.
AGC estimates that its capital expenditures for 2005 and 2006 will be $11.7 million and $10.0 million, respectively. See Note 14, “Commitments and Contingencies,” to AGC’s Financial Statements for additional information.
AE Supply
*
Does not include unamortized debt expense, discounts, premiums and terminated interest rate swaps that were accounted for as fair value hedges under SFAS No. 133 See Note 10, “Derivative Instruments and Hedging Activities,” to the Consolidated Financial Statements.
AE Supply estimates that its capital expenditures for 2005 and 2006 will be $91.2 million and $149.1 million, respectively. These estimates include expenditures of $39.9 million and $102.1 million, respectively, for environmental control technology.
West Penn
*
Does not include unamortized debt expense, discounts and premiums.
West Penn estimates that its capital expenditures for 2005 and 2006 will be $60.0 million and $72.0 million, respectively.
Assets Held For Sale
Contractual cash obligations and commitments related to assets held for sale at December 31, 2004 have been excluded from the tables above. The table below provides a summary of the payments due by period for these obligations and commitments.
Off-Balance Sheet Arrangements
None of the registrants has any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on their financial condition, revenues, expenses, results of operation, liquidity, capital expenditures or capital resources.
Cash Flows
Allegheny
Allegheny’s cash flows from operating activities primarily result from the sale of electricity and gas. Future cash flows will be affected by, among other things, the impact that the economy, weather, customer choice and future regulatory proceedings have on revenues, future demand and market prices for energy, as well as Allegheny’s ability to produce and supply its customers with power at competitive prices.
Operating Activities: Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation and amortization expense is a significant component of cash flows from operating activities.
Cash flows from operating activities for 2004 were $506.7 million, consisting of discontinued operations and non-cash charges of $797.5 million and changes in certain assets and liabilities of $19.8 million, partially offset by a net loss of $310.6 million. Cash flows from operating activities for 2003 were $370.1 million, consisting of non-cash charges of $592.5 million and changes in certain assets and liabilities of $132.6 million, partially offset by a net loss of $355.0 million.
Significant cash flows related to operating activities for 2004 included $88.6 million in net proceeds related to the 2004 sale of the OVEC tolling agreement, $70.8 million in proceeds related to the 2003 sale of the CDWR contract and related hedges to J. Aron & Company as a result of the exit from Western U.S. energy markets, $28 million in final scheduled payments in connection with the termination of the tolling agreement with Williams Energy Marketing & Trading Company and $55.8 million in payments to Allegheny’s pension and other post-retirement benefit plans, primarily as a result of contributing amounts to satisfy the funding requirements of these benefits plans.
The changes in certain assets and liabilities for 2004 resulted in an increase in operating cash flows of $19.8 million. Operating cash flows were primarily generated by a $97.6 million change in taxes receivable/accrued, net and a $26.9 million decrease in accounts receivable, net, related to seasonal timing of payments received and revenues generated. These amounts were partially offset by cash flows used for operating activities primarily due to a $37.5 million increase in collateral deposits held as security for certain contracts and a $27.6 million decrease in accounts payable as a result of timing differences associated with the payment of certain working capital obligations.
The changes in certain assets and liabilities for 2003 resulted in a net increase in operating cash flows of $132.6 million. Operating cash flows were primarily generated by a $186.9 million change in taxes receivable/accrued, net, primarily as a result of tax refunds received and a $116.8 million decrease in accounts receivable, net, related to seasonal timing of payments received and revenues generated. These amounts were partially offset by operating cash flows used primarily for a $92.3 million decrease in accounts payable as a result of timing differences associated with the payment of certain working capital obligations and $47.7 million in payments to terminate various energy trading contracts as a result of AE Supply’s exit from Western U.S. energy markets.
Investing Activities: Cash flows used in investing activities for 2004 and 2003 were $248.3 million and $546.2 million, respectively.
Significant cash flows used in investing activities for 2004 included $265.6 million of capital expenditures in accordance with planned capital improvements for the year and a $183.8 million increase in restricted funds related primarily to funds required to be used to repay debt. These amounts were partially offset by the receipt of $199.1 million in proceeds from the sale of various non-core assets.
Significant cash flows used in investing activities for 2003 included $318.4 million paid for the acquisition of the Springdale, Pennsylvania generation facility, $254.5 million in other capital expenditures and a $42.7
million increase in restricted funds. These amounts were partially offset by $57.6 million in proceeds from the sale of non-core assets.
Financing Activities: Cash flows used in financing activities for 2004 were $597.6 million. Cash flows from financing activities for 2003 were $500.5 million.
Significant cash flows used in financing activities for 2004 included $3,506.0 million in payments for the retirement of long-term debt and $53.6 million in payments for the retirement of short-term debt. The sources of the funds for these payments included $2,811.6 million (net of $30.5 million related to original issue discounts and debt issuance costs) in proceeds from the issuance of long-term debt and $151.4 million in proceeds from the private placement of common stock.
Significant cash flows provided by financing activities for 2003 included $2,320.4 million in proceeds from the issuance of debt under the Borrowing Facilities. These funds were primarily used for $1,079.2 million in net repayments of short-term debt, $694.4 million in payments for the retirement of long-term debt and $46.3 million in payments for costs associated with the Borrowing Facilities.
Monongahela
Monongahela’s cash flows from operating activities primarily result from the sale of electricity and gas. Future cash flows will be affected by, among other things, the impact that the economy, weather, customer choice and future regulatory proceedings have on revenues, future demand and market prices for energy, as well as Monongahela’s ability to obtain and provide its customers with power at competitive prices.
Internal generation of cash, consisting of cash flows from operating activities reduced by common and preferred dividends, was $62.1 million for 2004 compared with $69.3 million for 2003.
Operating Activities: Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation and amortization expense is a significant component of cash flows from operating activities.
Cash flows from operating activities for 2004 were $100.4 million, consisting of discontinued operations and non-cash charges of $75.5 million, changes in certain assets and liabilities of $22.4 million and net income of $2.5 million. Cash flows from operating activities for 2003 were $117.9 million, consisting of $80.7 million of net income, non-cash charges of $19.4 million and changes in certain assets and liabilities of $17.8 million.
The changes in certain assets and liabilities for 2004 resulted in an increase in operating cash flows of $22.4 million. Operating cash flows were primarily generated by a $17.2 million increase in accounts payable to affiliates, net, as a result of timing differences associated with the payment of certain obligations and a $7.4 million change in taxes receivable/accrued, net.
The changes in certain assets and liabilities for 2003 resulted in an increase in operating cash flows of $17.8 million. Operating cash flows were primarily generated by a $35.2 million change in taxes receivable/accrued, net, primarily as a result of tax refunds received and a $6.0 million increase in accounts payable to affiliates, net, as a result of timing differences associated with the payment of certain obligations. These amounts were partially offset by cash flows used for operating activities primarily due to a $30.3 million increase in fuel inventory as a result of seasonality.
Investing Activities: Cash flows used in investing activities for 2004 and 2003 were $54.1 million and $78.7 million, respectively. Significant cash flows used in investing activities for both periods were for capital expenditures. The amount for 2003 also included a $9.2 million contribution paid to an affiliate.
Financing Activities: Cash flows used in financing activities for 2004 and 2003 were $45.2 million and $50.4 million, respectively.
Significant cash flows used in financing activities for 2004 included $66.3 million in payments for the retirement of long-term debt, $53.6 million in payments for the retirement of short-term debt and $38.3 million in cash dividends paid on capital stock. The source of the funds for these payments was $117.2 million (net of $2.8 million related to an original issue discount and debt issuance costs) in proceeds from the issuance of first mortgage bonds.
Significant cash flows used in financing activities for 2003 included $63.1 million in payments for the retirement of long-term debt and $48.6 million in cash dividends paid on capital stock. The source of the funds for these payments included $52.8 million in net borrowings of short-term debt and an $8.5 million payment on a note receivable issued to an affiliate.
Potomac Edison
Potomac Edison’s cash flows from operating activities primarily result from the sale of electricity. Future cash flows will be affected by, among other things, the impact that the economy, weather, customer choice and future regulatory proceedings have on revenues, future demand and market prices for energy, as well as Potomac Edison’s ability to obtain and provide its customers with power at competitive prices.
Internal generation of cash, consisting of cash flows from operating activities reduced by common dividends, was $82.7 million for 2004 compared with $89.8 million for 2003.
Operating Activities: Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation and amortization expense is a significant component of cash flows from operating activities.
Cash flows from operating activities for 2004 were $125.7 million, consisting of non-cash charges of $71.5 million, net income of $38.0 million and changes in certain assets and liabilities of $16.2 million. Cash flows from operating activities for 2003 were $120.3 million, consisting of changes in certain assets and liabilities of $55.2 million, net income before cumulative effect of accounting change of $40.6 million and non-cash charges of $24.5 million.
The changes in certain assets and liabilities for 2004 resulted in an increase in operating cash flows of $16.2 million. Operating cash flows were primarily generated by a $9.7 million increase in collateral deposits held related to an intercompany power agreement and a $3.5 million change in taxes receivable/accrued, net.
The changes in certain assets and liabilities for 2003 resulted in an increase in operating cash flows of $55.2 million. Operating cash flows were primarily generated by a $14.7 million change in taxes receivable/accrued, net, a $12.3 million increase in non-current income taxes payable, an $11.5 million decrease in accounts receivable, net, primarily due to the timing and volume of unbilled utility revenues, a $8.9 million increase in accounts payable to affiliates, net, and a $6.0 million increase in accounts payable, each as a result of timing differences associated with the payment of certain obligations.
Investing Activities: Cash flows used in investing activities for 2004 and 2003 were $76.0 million and $52.7 million, respectively. Significant cash flows used in investing activities for both periods were for capital expenditures. The 2004 amount also includes the use of $9.7 million resulting from an increase in restricted funds due to additional collateral requirements.
Financing Activities: Cash flows used in financing activities for 2004 and 2003 were $65.3 million and $38.9 million, respectively.
Significant cash flows used in financing activities for 2004 included $180.6 million for the retirement of long-term debt, $43.0 million in cash dividends paid on common stock and $14.4 million for the issuance of a note receivable to an affiliate. The source of the funds for these payments included $172.7 million (net of $2.3 million related to an original issue discount and debt issuance costs) from the issuance of first mortgage bonds.
Significant cash flows used in financing activities for 2003 included $8.5 million for payments on notes payable to affiliates and $30.4 million in cash dividends paid on common stock.
AGC
AGC’s cash flows from operating activities primarily result from the sale of electricity. Future cash flows will be affected by, among other things, the impact that the economy and weather have on revenues, future demand and market prices for energy.
Internal generation of cash, consisting of cash flows from operating activities reduced by common dividends, was $29.3 million for 2004 compared with $43.9 million for 2003.
Operating Activities: Changes in cash flows from operations are generally consistent with changes in results of operations and are further impacted by changes in working capital. Net income before depreciation and amortization expense is a significant component of cash flows from operating activities.
Cash flows from operating activities for 2004 were $41.8 million, consisting of net income of $27.4 million, non-cash charges of $12.3 million and changes in certain assets and liabilities of $2.1 million. Cash flows from operating activities for 2003 were $56.4 million, consisting of changes in certain assets and liabilities of $23.6 million, net income of $20.8 million and non-cash charges of $12.0 million.
The changes in certain assets and liabilities for 2004 resulted in an increase in operating cash flows of $2.1 million. Operating cash flows were primarily generated by a $1.5 million change in accounts receivable due from/payable to affiliates, net, as a result of timing differences associated with the payment of certain obligations and a $0.7 million change in taxes receivable/accrued, net, primarily as a result of timing differences associated with the payment of tax obligations.
The changes in certain assets and liabilities for 2003 resulted in an increase in operating cash flows of $23.6 million. Operating cash flows were primarily generated by a $14.3 million change in taxes receivable/accrued, net, primarily as a result of tax refunds received and a $10.8 million change in accounts receivable due from/payable to affiliates, net, as a result of timing differences associated with the payment of certain obligations.
Investing Activities: Cash flows used in investing activities for 2004 and 2003 were $9.1 million and $8.7 million, respectively, consisting of capital expenditures.
Financing Activities: Cash flows used in financing activities for 2004 and 2003 were $27.5 million and $47.5 million, respectively.
Significant cash flows used in financing activities for 2004 included a $15.0 million payment on a note payable to parent and $12.5 million in cash dividends paid on common stock.
Significant cash flows used in financing activities for 2003 included $55.0 million in net repayments of short-term debt, $50.0 million for the retirement of long-term debt and $12.5 million in cash dividends paid on common stock. The source of funds for these payments included a $40.0 million contribution from the parent companies and a net $30.0 million received from a parent in exchange for the issuance of a note payable.
Financing
AE Common Stock
On October 5, 2004, AE sold 10 million shares of its common stock at a price of $15.15 per share directly to institutional investors in a private placement. In addition, AE issued approximately 405,000 shares during 2004 in accordance with its Dividend Reinvestment and Stock Purchase Plan, Long-Term Incentive Plan and Employee Stock Ownership and Savings Plan. AE issued approximately 373,000 shares of its common stock during 2003 in accordance with these plans. AE issued approximately 1.3 million shares of its common stock under these plans during 2002.
There were no shares of common stock repurchased in 2004 and 2003.
Long-term Debt
See Note 3, “Capitalization,” to the Consolidated Financial Statements for information regarding debt issued and redeemed during 2004, 2003 and 2002, the New Loan Facilities and the Refinanced AE Supply Loan.
Short-term Debt
Allegheny had no short-term debt outstanding at December 31, 2004. Allegheny had $53.6 million of short-term debt outstanding at December 31, 2003, which represented a bridge loan outstanding at Monongahela that had a term of 364 days and was issued in September 2003. As described above under “Liquidity and Capital Requirements-2004 Activity,” in June 2004, Monongahela issued $120 million of first mortgage bonds, the net proceeds of which were used to repay, among other debt, Monongahela’s $53.6 million short-term bridge loan which was due in September 2004. See Note 16, “Short-Term Debt,” to the Consolidated Financial Statements for additional details regarding short-term debt activity during 2004 and 2003.
Operating Lease Transactions
In November 2001, AE Supply entered into an operating lease transaction to finance construction of a 630 MW generation facility in St. Joseph County, Indiana. As of December 31, 2002, AE Supply recorded the facility on its Consolidated Balance Sheet as a result of lessor reimbursement for construction expenditures. AE Supply recorded approximately $415.5 million of debt related to this obligation, including costs associated with terminating the project, on its Consolidated Balance Sheet at December 31, 2002. In February 2003, AE Supply purchased the project by assuming $380.0 million of the lessor’s long-term debt and paying an additional $35.5 million. See Note 3, “Capitalization” to the Consolidated Financial Statements for additional information. Following the purchase of the facility, Allegheny terminated the project resulting in a write-off of $192.0 million, before income taxes ($118.4 million, net of income taxes).
In November 2000, AE Supply entered into an operating lease transaction to finance construction of a 540 MW generation facility in Springdale, Pennsylvania. In February 2003, AE Supply purchased the facility for $318.4 million financed with debt, which was part of the Borrowing Facilities. The facility went into commercial operation in July 2003. This facility includes two natural gas-fired combustion turbines and one steam turbine. The Springdale facility was the final active new facility construction project in AE Supply’s pipeline. AE Supply has suspended or terminated all other new facility construction activities.
Change in Credit Ratings
On January 28, 2004, Moody’s Investor Service (“Moody’s”) affirmed its credit ratings of AE, AE Supply and other subsidiaries and revised their outlook to stable from negative. On February 12, 2004, Moody’s assigned credit ratings to the New Loan Facilities and upgraded its credit rating for AE Supply’s Statutory Trust Secured Debt to “B1” from “B2.”
On February 12, 2004, Fitch IBCA Ratings Services (“Fitch”) affirmed its credit ratings of AE, AE Supply and other subsidiaries and revised their outlook to stable from negative. In addition, Fitch assigned credit ratings to the New Loan Facilities and upgraded its credit rating for AE Supply’s Statutory Trust Secured Debt to “BB-” from “B+.”
On February 17, 2004, Standard and Poor’s Ratings Services (“S&P”) reaffirmed its credit ratings, revised the outlook to stable from negative and provided credit ratings for the New Loan Facilities.
On May 26, 2004, Fitch revised Monongahela’s, outlook to negative from stable.
On August 13, 2004, Moody’s revised the outlook for AE, AE Supply and AGC to positive from stable.
On August 20, 2004, S&P upgraded its credit rating of AE to “B+” from “B.” In addition, S&P upgraded its credit ratings of the majority of AE’s subsidiaries one notch. S&P also revised the outlook of AE and its subsidiaries to positive from stable.
On September 10, 2004, Fitch revised Monongahela’s outlook to stable from negative.
On February 17, 2005, S&P upgraded its credit rating of AE Supply’s Term B Loan (referred to as the Refinanced AE Supply Loan) and the secured portion of the Amended A-Notes to “BB-” from “B+.” S&P’s outlook for AE and its subsidiaries remains positive.
On February 24, 2005, Moody’s upgraded its credit rating for AE’s senior unsecured debt to “B1” from “B2.” Moody’s also upgraded its credit rating for AE Supply’s senior secured debt to “Ba3” from “B1” and upgraded its credit rating for AE Supply’s unsecured debt to “B2” from “B3.” Moody’s also upgraded its credit rating for AGC’s unsecured debt to “B2” from “B3.” Moody’s upgraded its outlook for Monongahela, Potomac Edison and West Penn to positive from stable, making the rating outlook for all of Allegheny’s rated entities positive.
On February 25, 2005, Fitch revised its outlook of AE, AE Supply and AGC to positive from stable.
The following table lists Allegheny’s credit ratings, as of March 7, 2005:
(a)
Outlook positive for AE, AE Supply and AGC. All other entities are stable.
Derivative Instruments and Hedging Activities
Allegheny follows SFAS No. 133 for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The standards require that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in earnings or other comprehensive income (loss) and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
The fair value of AE Supply’s trading portfolio is primarily comprised of interest rate swap agreements and commodity cash flow hedges, which represented a net liability of $80.1 million and $72.7 million as of December 31, 2004 and 2003, respectively. These are accounted for at fair value on the Consolidated Balance Sheets.
On March 19, 2002, AE Supply entered into two treasury lock agreements to hedge its exposure to changing United States Treasury interest rates on the forecasted issuance of long-term, fixed-rate debt in April 2002. These treasury lock agreements were accounted for as cash flow hedges. In April 2002, these contracts were settled at a loss of $1.6 million, before income taxes ($1.0 million, net of income taxes). The unrealized loss was recorded in other comprehensive income (loss). In April 2002, AE Supply began reclassifying to earnings the amounts in accumulated other comprehensive income (loss) for these treasury lock agreements over the life of the 10-year debt. For 2004, 2003 and 2002, $0.2 million, before income taxes ($0.1 million, net of income taxes), was reclassified from accumulated other comprehensive income (loss) to earnings.
On August 1, 2000, Allegheny issued a $165.0 million, 7.75% fixed-rate note and a $135.0 million, 7.75% fixed-rate note. Each note matures on August 1, 2005 and requires semi-annual interest payments on August 1 and February 1. On April 24, 2002, Allegheny entered into an interest rate swap to convert the fixed rates to variable rates for the remaining term of the notes. Under the term of the swap, Allegheny received interest at a fixed rate of 7.75% and paid interest at a variable rate equal to the three-month LIBOR plus a fixed spread. Allegheny designated the swap as a fair-value hedge of changes in the general level of market interest rates. During September 2002, Allegheny terminated the interest rate swap at its fair value of $11.3 million. As a result, Allegheny has discontinued its fair value hedge accounting. The increase in the carrying amount of the fixed-rate notes of $11.3 million as a result of the fair value hedge accounting is being amortized over the remaining life of the notes. For 2004, 2003 and 2002, $3.8 million, $3.8 million and $1.5 million, respectively, before income taxes ($2.4 million, $2.3 million and $0.9 million, respectively, net of income taxes), was amortized to the Consolidated Statements of Operations.
During 2002, AE Supply recognized a net unrealized loss of $2.6 million related to derivative instruments associated with the delivery of electricity that did not qualify for the normal purchase and normal sale exception under SFAS No. 133.
Fellon-McCord and Alliance Energy Services-Sold in 2002
On November 1, 2001, Allegheny Ventures completed the acquisition of Fellon-McCord and Alliance Energy Services. Effective December 31, 2002, Allegheny Ventures sold Fellon-McCord and Alliance Energy Services. Alliance Energy Services was engaged in the purchase, sale and marketing of natural gas and other energy-related services to various commercial and industrial customers across the United States. Alliance Energy Services, on behalf of its customers, used both physical and financial derivative contracts, including forwards, NYMEX futures, options and swaps, in order to manage price risk associated with its purchase and sales activities. These derivative contracts were accounted for as cash flow hedges.
Alliance Energy Services’ primary strategy was to minimize its market risk exposure with respect to its forecasted physical natural gas sales contracts to its customers by entering into offsetting financial and physical
natural gas purchase and transportation contracts. The transactions executed under this strategy were accounted for as cash flow hedges, with the fair value of the offsetting contracts recorded as assets and liabilities on the Consolidated Balance Sheets and changes in fair value for these contracts were recorded to other comprehensive income (loss). For 2002, an unrealized gain of $31.2 million, net of reclassifications to earnings, income taxes and minority interest, was recorded to other comprehensive income (loss) for these contracts. These hedges were highly effective during 2002.
Additionally, as a service to its customers, Alliance Energy Services offered price risk intermediation services in order to mitigate the market risk associated with natural gas. Under this program, Alliance Energy Services would execute positions with the customer and enter into offsetting positions with a third counterparty. These transactions did not qualify for hedge accounting under SFAS No. 133 and were accounted for on a mark-to-market basis.
As a result of Allegheny Ventures’ sale of Fellon-McCord and Alliance Energy Services, the Consolidated Balance Sheets as of December 31, 2004 and 2003, do not include any amounts for the fair value of Alliance Energy Services’ derivative instruments.
NEW ACCOUNTING STANDARDS
Allegheny adopted FASB Interpretation No. 46 (Revised December 2003), “Consolidation of Variable Interest Entities” (“FIN 46R”), as of March 31, 2004. FIN 46R requires Allegheny to consolidate entities or contracts that represent a variable interest in a variable interest entity (“VIE”) if Allegheny is determined to be the primary beneficiary of the VIE. Under FIN 46R, Allegheny consolidated Hunlock Creek as of March 31, 2004. This entity operates two plants that produce and sell electricity to Allegheny and a third party. The consolidation resulted in an increase in total assets as of March 31, 2004 of $16.5 million. Consolidation of this entity had no impact on Allegheny’s net income or stockholders’ equity. Allegheny determined that West Penn and Potomac Edison each has a long-term electricity purchase contract with an unrelated independent power producer (“IPP”) that represents a variable interest under FIN 46R. These would be consolidated if either West Penn or Potomac Edison is determined to be the primary beneficiary of the applicable VIE. Based on a qualitative analysis, Allegheny does not believe that either West Penn or Potomac Edison is the primary beneficiary of either of these VIEs. Allegheny continues to pursue, but has been unable to obtain, certain quantitative information from the IPPs necessary to fully support this position. West Penn and Potomac Edison have estimated power purchases for 2005 from these two IPPs in the amount of $50 million and $96 million, respectively. West Penn recovers a portion, and Potomac Edison recovers the full amount, of the cost of the applicable power contract in their rates charged to consumers. Neither West Penn nor Potomac Edison is subject to any risk of loss associated with the applicable VIE, because neither of them has any obligation to the applicable IPP other than to purchase the power that the VIE produces according to the terms of the applicable electricity purchase contract.
In January 2004, the FASB issued FASB Staff Position (“FSP”) FAS 106-1 (“FSP 106-1”), “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (the “Medicare Act”). The Medicare Act introduced a prescription drug benefit under Medicare Part D and beginning in 2006, provides for the federal government to pay a subsidy for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. Allegheny has elected to follow the deferral provisions of FSP 106-1, which permitted employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until authoritative guidance on the accounting for the federal subsidy is issued. In May 2004, FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”). “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs-an amendment of ARB No. 43, Chapter 4” (“SFAS No. 151”). This Statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). This Statement requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, this Statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The Statement will be effective in January 2006. Allegheny is currently evaluating, but has yet to determine, the impact, if any, that the adoption of SFAS No. 151 will have on its Consolidated Financial Statements.
In November 2004, the EITF issued Issue No. 04-10, “Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds” (“EITF 04-10”). SFAS Statement No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS No. 131”) requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. At issue is how an enterprise should evaluate the aggregation criteria in paragraph 17 of SFAS No. 131 when determining whether operating segments that do not meet the quantitative thresholds may be aggregated in accordance with paragraph 19 of SFAS No. 131. Allegheny is currently evaluating, but has yet to determine, the impact, if any, that the adoption of EITF 04-10 will have on its Consolidated Financial Statements.
In December 2004, the FASB issued a revision of SFAS Statement No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123-R”). This revised Statement supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and its related implementation guidance. The revised Statement focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. The revised Statement requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Allegheny has not elected to early adopt SFAS No. 123-R. As a result, SFAS No. 123-R will be effective for Allegheny in the third quarter of 2005 and will apply to all of Allegheny’s outstanding, unvested share-based payment awards as of July 1, 2005 and all prospective awards. Allegheny has not determined the impact that SFAS No. 123-R will have on its Consolidated Financial Statements or which of the three transition methods permitted by SFAS No. 123-R will be elected.
In December 2004, the FASB issued SFAS Statement No. 153, “Exchanges of Nonmonetary Assets-an amendment of APB Opinion No. 29.” This Statement amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. A non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be effective in January 2006. Allegheny does not expect that the adoption of SFAS No. 153 will have a material impact on its Consolidated Financial Statements.
In addition the EITF issued No. 03-16, “Accounting for Investments in Limited Liability Companies” (“EITF 03-16”). APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock,” prescribes the accounting for investments in the common stock of corporations that are not consolidated. Limited liability companies (“LLCs”) have characteristics of both corporations and partnerships, but are dissimilar from both in certain respects. Due to those similarities and differences, diversity in practice exists with respect to accounting for non-controlling investments in LLCs. Allegheny has already accounted for its investments in LLCs in accordance with EITF 03-16. Therefore, no change or transition is required.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ALLEGHENY ENERGY, INC.
During 2004, Allegheny continued its focus on reducing risk, optimizing the value of its generation facilities, reducing the volatility of mark-to-market earnings and prudently managing and protecting the value associated with the existing positions in its wholesale energy markets transactions portfolio.
Allegheny remains exposed to market risks associated with commodity prices and interest rates. 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 interest rate swaps and variable- and fixed-rate debt. Allegheny has a program designed to systematically identify, measure, evaluate and actively manage and report market risks.
Allegheny’s Corporate Energy Risk Policy was adopted by its Board of Directors and is monitored by a Risk Management Committee chaired by its Chief Executive Officer and composed of senior management. An independent risk management group within Allegheny measures and monitors the risk exposures to ensure compliance with the policy and to ensure that the policy is periodically reviewed.
To manage the financial exposure to commodity price fluctuations in its wholesale transactions portfolio, fuel procurement, power marketing, natural gas supply and risk management activities, Allegheny, through AE Supply, enters into contracts, such as electricity and natural gas purchase and sale commitments, to hedge the risk exposure. However, Allegheny does not hedge the entire exposure of its operations from commodity price volatility for a variety of reasons. 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.
AE Supply’s wholesale energy business 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 electricity markets, including the generation, fuel procurement, power marketing and the purchase and sale of electricity. Allegheny’s wholesale activities principally consist of over-the-counter forward contracts for the purchase and sale of electricity and natural gas. The majority of these contracts represent commitments to purchase or sell electricity at fixed prices in the future. These forward contracts generally require physical delivery of electricity.
In 2004, Allegheny reduced its exposure to variable interest rates by repaying debt subject to variable interest rates. The exposure was further reduced in January 2005 as a result of the repayment of debt with the proceeds of asset sales. At December 31, 2004, AE’s outstanding debt subject to variable interest rates was $1.08 billion, compared to $1.69 billion of outstanding debt subject to variable interest rates at December 31, 2003. AE and AE Supply refinanced the Borrowing Facilities in March 2004 with the New Loan Facilities. The New Loan Facilities carry the same interest rate risks as the Borrowing Facilities. In October 2004, AE Supply refinanced the AE Supply Loans with the Refinanced AE Supply Loan. The Refinanced AE Supply Loan carries the same risks as the AE Supply Loans. Accordingly, a one percent increase in the variable interest rate under the New AE Facility and the Refinanced AE Supply Loan would increase Allegheny’s projected interest expense in 2005 by approximately $10.8 million, on an annual basis, based on the amount of outstanding debt as of December 31, 2004. For additional information regarding these financing activities, see “Financial Condition, Requirements and Resources-Liquidity and Capital Requirements.”
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 short-term energy trading 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 customers in the electric and natural gas utility industries, most of whom are viewed as above investment grade credit quality. This concentration of customers may affect Allegheny’s overall exposure to credit risk, either positively or negatively, because these customers may be similarly affected by changes in economic or other conditions.
AE Supply exited the Western U.S. energy markets and terminated or sold the majority of its speculative energy trading positions in all other national energy markets. Accordingly, AE Supply has refocused the composition of its trading portfolio. As of December 31, 2004, the fair value of Allegheny’s trading portfolio is comprised primarily of interest rate swap agreements with a single counterparty and commodity cash flow hedges. If the counterparty to these interest rate swap agreements does not perform, AE Supply may be exposed to greater costs. AE Supply, however, does not anticipate nonperformance by this counterparty, which is a multinational financial institution.
Additionally, AE Supply is a counterparty to certain long-term agreements for the transportation of natural gas. See “Business-Fuel, Power and Resource Supply.”
Market Risk
Market risk arises from the potential for changes in the value of energy related to price and volatility in the market. Allegheny reduces these risks by using its owned and contractually controlled generation assets to back positions on physical transactions. Allegheny monitors market risk exposure and credit risk limits within the guidelines of its Corporate Energy Risk Policy. Allegheny evaluates commodity price risk, operational risk and credit risk in establishing the fair value of commodity contracts.
Allegheny and AE Supply use various methods to measure their exposure to market risk on a daily basis, including a value at risk model (“VaR”). VaR is a statistical model that attempts to predict risk of loss based on historical market price and volatility data over a given period of time. The 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 by using a variance/covariance approach, in which the option positions are evaluated by using their delta equivalences. Due to inherent limitations of VaR, including the use of approximations to value options, subjectivity in the choice of liquidation period and reliance on historical data to calibrate the model, the VaR calculation may not accurately reflect Allegheny’s and AE Supply’s market risk exposure. As a result, changes in Allegheny’s and AE Supply’s market risk sensitive instruments could differ from the calculated VaR, and these changes could have a material effect on Allegheny’s and AE Supply’s consolidated results of operations and financial position. In addition to VaR, Allegheny and AE Supply routinely perform stress and scenario analyses to measure extreme losses due to exceptional events. Allegheny and AE Supply review the VaR and stress test results to determine the maximum expected reduction in the fair value of the entire energy markets portfolio.
AE Supply’s exit from the Western U.S. energy markets has decreased both the magnitude and length of AE Supply’s net open positions of its commodity contract trading portfolio, which had a corresponding decrease in calculated VaR. AE Supply calculated VaR using the full term of all remaining wholesale energy market positions that are accounted for as marked-to-market. This calculation is based upon management’s best estimates and modeling assumptions, which could materially differ from actual results. As of December 31, 2004 and 2003, this calculation yielded a VaR of $0.3 million and $0.2 million, respectively.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Monongahela is exposed to market risks associated with commodity prices that result from market fluctuations in the price and transportation costs of electricity and natural gas.
Monongahela is subject to capped rates in West Virginia. Monongahela agreed to terminate its fuel clause in West Virginia effective July 1, 2000. The purpose of the fuel clause, which allowed Monongahela to recoup certain fuel costs through customer rates, had been to offset fluctuations in the market price of fuel. In order to manage its financial exposure to these price fluctuations in the absence of a fuel clause, Monongahela enters into contracts, such as fuel purchase commitments. To the extent that Monongahela purchases fuel at significantly higher prices, Monongahela’s results of operations and cash flows could be adversely affected.
In connection with its restructuring plan in Ohio, Monongahela separated its rates in Ohio into three separate charges-a generation (or supply) charge, a Restructuring Transition Charge and T&D charges. Pursuant to a settlement, Monongahela’s transition period for large industrial, commercial and street lighting customers was scheduled to end on December 31, 2003, but has been extended by PUCO until December 31, 2005. Monongahela’s T&D rates are capped through the end of the transition period for all customers and, thereafter, are subject to traditional regulated utility rate-making (i.e. cost-based rates). See “Business-Regulatory Framework Affecting Allegheny.”
AE Supply provides Monongahela with a majority of the electricity needed to serve Monongahela’s PLR obligations to those Ohio customers who do not choose an alternative electricity generation supplier during the transition period. Monongahela’s PLR power supply agreement with AE Supply has both fixed-price and market-based pricing components. The amount of electricity purchased under these agreements that is subject to market prices escalates each year through 2005. To the extent that Monongahela purchases electricity from AE Supply at market prices that exceed the established fixed prices, Monongahela’s results of operations and cash flows could be adversely affected. In 2004 and 2003, Monongahela incurred $0.7 million and $5.0 million, respectively, of additional purchased electricity costs due to this market-based pricing component.
See “Business-Regulatory Framework Affecting Allegheny.”
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Potomac Edison is exposed to market risks associated with commodity prices that result from market fluctuations in the price of electricity as discussed below.
In connection with its restructuring plans in Maryland and Virginia, Potomac Edison separated its rates into two separate charges-a generation (or supply) charge and T&D charges. The generation rates apply to customers who do not choose an alternate electricity generation supplier during the applicable transition period. These rates are capped through the applicable transition period. The transition period for Potomac Edison’s Maryland residential customers extends through December 31, 2008.
The transition period for all other Maryland customers ended on December 31, 2004. Pursuant to a settlement, Potomac Edison will provide PLR service to residential customers through December 31, 2012, and will provide PLR service to other commercial and industrial customers for various periods through as late as December 31, 2008. Potomac Edison will procure wholesale electric supply services necessary to serve these PLR obligations (after the expiration of the transition period and before the expiration of the settlement period) through a competitive bidding process. In addition to the electric supply costs associated with the winning bids, Potomac Edison will also be allowed to recover its incremental costs for providing these services (including a return for its shareholder) through an administrative charge.
The transition period for all of Potomac Edison’s Virginia customers has been extended through December 31, 2010, subject to certain exceptions.
AE Supply provides Potomac Edison with a majority of the electricity needed to serve those customers who do not choose an alternative electricity generation supplier during the applicable transition period. Potomac Edison’s power supply agreements with AE Supply have both fixed-price and market-based pricing components. The amount of electricity purchased under these agreements that is subject to market prices escalates each year, through June 30, 2007 in Virginia and December 31, 2008 in Maryland. To the extent that Potomac Edison purchases electricity from AE Supply at market prices that exceed the established fixed prices, Potomac Edison’s results of operations and cash flows could be adversely affected. In 2004 and 2003, Potomac Edison incurred $6.7 million and $12.7 million, respectively, of additional purchased electricity costs due to this market-based pricing component. See “Business-Regulatory Framework Affecting Allegheny.”
ALLEGHENY GENERATING COMPANY
Not Applicable.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
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 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 Capitalization
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Stockholders’ Equity
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Comprehensive Loss
See accompanying Notes to Consolidated Financial Statements.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION
Allegheny Energy, Inc. (“AE”) is a holding company registered under the Public Utility Holding Company Act of 1935, as amended (“PUHCA”). AE operates primarily through directly and indirectly owned subsidiaries (collectively, “Allegheny”). Allegheny’s two business segments are the Delivery and Services segment and the Generation and Marketing segment.
The Delivery and Services segment primarily consists of AE’s regulated utility subsidiaries. These subsidiaries include Monongahela Power Company (“Monongahela”), excluding generation of electricity for its West Virginia customers, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”) (collectively, the “Distribution Companies”). These subsidiaries primarily operate electric and natural gas transmission and distribution (“T&D”) systems in Pennsylvania, West Virginia, Maryland, Virginia and Ohio. These subsidiaries are subject to federal and state regulation, including PUHCA.
The Generation and Marketing segment consists primarily of AE’s subsidiary, Allegheny Energy Supply Company, LLC (“AE Supply”), including 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. The Generation and Marketing segment also includes Monongahela’s generation of electricity for its West Virginia customers. The Generation and Marketing segment is subject to federal regulation, including PUHCA, but is not subject to state regulation of rates except for Monongahela which is subject to state regulation in West Virginia. As of December 31, 2004, the Generation and Marketing segment had 10,851 megawatts (“MW”) of generation capacity, which it owned or was committed to purchase.
Allegheny Energy Services Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who work at Allegheny. As of December 31, 2004, AESC employed approximately 5,100 employees, of which approximately 1,530 are subject to collective bargaining arrangements.
NOTE 2: BASIS OF PRESENTATION
During the third quarter of 2004, AE and certain of its subsidiaries entered into agreements to sell, or made the decision to sell, certain non-core assets. The results of operations relating to these assets have been reclassified to discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. In accordance with the provisions of the Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” (“SFAS No. 144”), the assets and liabilities associated with these discontinued operations have been reclassified as held for sale in the Consolidated Balance Sheets as of, and subsequent to, the date that held for sale criteria were met.
Certain amounts in the December 31, 2003 and 2002 Consolidated Statements of Operations and Consolidated Statements of Cash Flows and the December 31, 2003 Consolidated Balance Sheet have been reclassified for comparative purposes.
Significant accounting policies of Allegheny are summarized below.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires Allegheny to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
continuous basis, Allegheny evaluates its estimates, including those related to the calculation of the fair value of commodity contracts and derivative instruments, unbilled revenues, goodwill, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Allegheny bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.
Allegheny’s accounting for commodity contracts, which requires some of its more significant judgments and estimates used in the preparation of its Consolidated Financial Statements, is discussed under “Revenues” below and in Note 5, “Wholesale Energy Activities.” The accounting for derivative instruments is discussed in Note 10, “Derivative Instruments and Hedging Activities.”
Consolidation
The Consolidated Financial Statements include the accounts of AE and its wholly owned and controlled subsidiaries. All significant intercompany balances and transactions have been eliminated. The Consolidated Financial Statements have been prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of the Federal Energy Regulatory Commission (“FERC”) and applicable state regulatory commissions.
Revenues
Revenues from the sale of electricity and natural gas to customers of the regulated utility subsidiaries are recognized in the period that the electricity and natural gas are delivered and consumed by customers, including an estimate for unbilled revenues.
Revenues from the sale of unregulated generation are recorded in the period in which the electricity is delivered and consumed by customers.
Most of the power that Allegheny generates is sold into PJM Interconnection, L.L.C. (“PJM”), a regional transmission organization, and most of the power needed to meet the needs of customers of the Distribution Companies is purchased from PJM. These PJM purchases and sales are reported on a net basis in “Operating revenues.”
Allegheny records contracts entered into in connection with energy trading at fair value on the Consolidated Balance Sheets. Changes in fair value are recorded as a component of “Operating revenues” on the Consolidated Statements of Operations.
Fair values for exchange-traded instruments, principally futures and certain options, 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, over-the-counter options and swaps, management uses available market data and pricing models to estimate fair values. Estimating fair values of instruments which do not have quoted market prices requires management’s judgment in determining amounts which 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 ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Allegheny enters into physical energy commodity contracts and energy-related financial contracts. The sales and purchases made under commodity contracts for energy trading are recorded in operating revenues in accordance with Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” (“EITF 02-3”) and EITF Issue No. 03-11, “Reporting Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and Not Held for Trading Purposes.”
Allegheny has netting agreements with various counterparties, which 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 commodity contract assets and liabilities and accounts receivable and accounts payable with counterparties on a net basis.
See Note 5, “Wholesale Energy Activities,” for additional details regarding activities related to energy trading.
AE’s Delivery and Services segment is also constructing generation facilities for unrelated third parties. Construction revenues are recognized under the percentage of completion method. Under this method, revenue is recognized on a contract-by-contract basis determined by the percentage of costs incurred to date to total estimated costs. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Revenues from all other Delivery and Services segment activities are recorded in the period during which products or services are delivered and accepted by customers.
Natural gas production revenue is recognized as income when the natural gas is extracted, delivered and sold. Natural gas production revenue is primarily related to Mountaineer Gas Company (“Mountaineer”), the operations of which have been reclassified to discontinued operations as the result of the agreement to sell this asset.
Deferred Energy Costs, Net
Historically, the difference between the costs of fuel, purchased energy and certain other costs billed to regulated electric utility customers has been deferred until it is either recovered from or credited to customers under state fuel and energy cost-recovery procedures. With the exception of one power purchase agreement under the Public Utility Regulatory Policy Act of 1978 (“PURPA”) that remains subject to a deferred energy cost mechanism in Maryland, however, fuel and purchased energy costs for the regulated electric utilities have been expensed as incurred because the applicable state regulatory bodies eliminated their deferred energy cost mechanisms.
The difference between natural gas supply costs incurred and natural gas cost revenues collected from customers is deferred until recovered from, or credited to, customers under a Purchase Gas Adjustment (“PGA”) clause in effect in West Virginia.
Deferred energy costs, net, related to Monongahela’s West Virginia natural gas operations have been reclassified to assets held for sale and discontinued operations.
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 using the effective interest method.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Property, Plant and Equipment
Regulated Subsidiaries. Regulated property, plant and equipment are stated at original cost. Cost includes direct labor and materials, allowance for funds used during construction on regulated property for which construction work in progress is not included in rate base and indirect costs such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes and other benefits related to employees engaged in construction.
Upon normal retirement, the cost of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation with no gain or loss recorded.
Unregulated Subsidiaries. Unregulated property, plant and equipment are stated at original cost. West Penn’s, Potomac Edison’s and Monongahela’s Ohio and FERC generation assets were transferred to AE Supply at book value at various times from 1999 through June 2001. For the unregulated subsidiaries, gains or losses on asset dispositions and retirements are included in the determination of net income.
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 beginning upon a project’s completion.
Allegheny accounts for its natural gas exploration and production activities under the successful efforts method of accounting. The cost of Monongahela’s natural gas wells is being depleted using the units of production method. The results of operations for Monongahela’s West Virginia natural gas operations have been reclassified to discontinued operations as the result of the agreement to sell this asset.
Intercompany Transactions
AE and its various subsidiaries, including each registrant and their subsidiaries, may enter into various operating transactions with each other. It is Allegheny’s policy that the affiliated receivable and payable balances outstanding from these transactions are eliminated on the Consolidated Balance Sheets and Consolidated Statements of Cash Flows.
Common Transactions. Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for Allegheny in accordance with PUHCA. Each entity is responsible for its proportionate share of services provided by AESC.
AE and its subsidiaries file a consolidated federal income tax return. The consolidated income tax liability is 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. In accordance with this consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various registrants at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the intercompany balance.
An internal money pool accommodates intercompany short-term borrowing needs to the extent that certain of AE’s subsidiaries have funds available. The money pool provides funds to approved AE subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. AE and AE Supply can only lend money into the money pool. AGC can only borrow money from the money pool. Monongahela, Potomac Edison and West Penn can either lend money into, or borrow money from, the money pool.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
AE Supply. AE Supply supplies electricity to the Distribution Companies in accordance with agreements approved by FERC to meet the majority of the Distribution Companies’ retail provider-of-last-resort (“PLR”) obligations. AE Supply also records ancillary transmission revenue from the Distribution Companies in accordance with these agreements. AE Supply purchases power, under a market rate tariff and other agreements, from its regulated affiliates. AE Supply’s expenses for these purchases are reflected in “Purchased power and transmission” on its Consolidated Statements of Operations.
In November 2001, AE Supply entered into an agreement with Potomac Edison to purchase 180 MWs of unit contingent capacity, energy and ancillary services from January 1, 2002 through December 31, 2004, related to the AES Warrior Run generation facility. The Warrior Run agreement expired and was not renewed. The cost of purchasing power under this contract is reported net of associated energy trading revenues in “Operating revenues” on the Consolidated Statements of Operations in accordance with EITF 02-3.
Monongahela. Monongahela purchases the majority of the power necessary to serve its Ohio customers who do not choose an alternate electricity generation provider from its unregulated generation company affiliate, AE Supply, in accordance with agreements approved by FERC. Monongahela’s expense for these purchases is reflected in “Purchased power and transmission” on its Consolidated Statements of Operations.
Monongahela also sells electricity to AE Supply under a market rate tariff and other agreements.
Potomac Edison. Potomac Edison purchases the majority of the power necessary to serve its PLR obligations from AE Supply in accordance with agreements approved by FERC. Potomac Edison’s expense for these purchases is reflected in “Purchased power and transmission” on its Consolidated Statements of Operations. Before Potomac Edison joined PJM in April 2002, if Potomac Edison purchased more electricity than was needed to serve its customers, the excess electricity purchased was sold back to AE Supply and reflected in “Operating revenues” on Potomac Edison’s Consolidated Statements of Operations. When Potomac Edison joined PJM, operational changes were made so that Potomac Edison no longer has excess electricity to sell back to AE Supply.
West Penn. West Penn purchases the majority of the power necessary to serve its PLR obligation from AE Supply in accordance with agreements approved by FERC. West Penn’s expense for these purchases is reflected in “Purchased power and transmission” on its Consolidated Statements of Operations. Before West Penn joined PJM in April 2002, if West Penn purchased more electricity than was needed to serve its customers, the excess electricity purchased was sold back to AE Supply and reflected in “Operating revenues” on West Penn’s Consolidated Statements of Operations. When West Penn joined PJM, operational changes were made so that West Penn no longer has excess electricity to sell back to AE Supply.
West Penn also owns property, including buildings and software that it leases primarily to AESC for its use in providing services to Allegheny and its affiliates. These affiliated rent revenues are included in “Operating revenues” on the Consolidated Statements of Operations.
AGC. AE Supply and Monongahela purchase all of AGC’s capacity in the Bath County generation station priced under a “cost-of-service formula” wholesale rate schedule approved by FERC. AE Supply and Monongahela purchase power from AGC on a proportional basis, based on their respective equity ownership of AGC. Under this arrangement, AGC recovers in revenue, all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Long-Lived Assets
Long-lived assets owned by Allegheny are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations, in accordance with SFAS No. 144. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows. See Note 7, “Asset Impairments,” for information related to asset impairment charges recorded during 2004 and 2002.
Allowance for Funds Used During Construction (“AFUDC”) and Capitalized Interest
AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “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 recognized by Allegheny’s regulated subsidiaries as a cost of regulated property, plant and equipment. Rates used by the regulated subsidiaries for computing AFUDC in 2004, 2003 and 2002 averaged 7.27%, 8.08% and 10.59%, respectively. Allegheny recorded AFUDC of $1.9 million, $3.7 million and $1.0 million for 2004, 2003 and 2002, respectively.
For unregulated construction, Allegheny capitalizes interest costs in accordance with SFAS No. 34, “Capitalization of Interest Costs” (“SFAS No. 34”). The interest capitalization rates in 2004, 2003 and 2002 were 7.33%, 7.90% and 6.22%, respectively. Allegheny capitalized $3.4 million, $15.4 million and $12.6 million of interest during 2004, 2003 and 2002, respectively.
Depreciation and Maintenance
Depreciation expense is determined generally on a straight-line method based on the estimated service lives of depreciable properties. Depreciation expense was approximately 2.8% of average depreciable property in 2004, 2003 and 2002. Estimated service lives for generation, T&D and other property are as follows:
The Delivery and Service segment’s depreciation expense was $120.1 million, $117.7 million and $114.8 million for 2004, 2003 and 2002, respectively. The Generation and Marketing segment’s depreciation expense was $148.0 million, $132.3 million and $119.0 million for 2004, 2003 and 2002, respectively. Depreciation expense for regulated property is provided for under currently enacted regulatory rates.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Maintenance expenses represent costs incurred to maintain the generation stations, the electric and natural gas T&D systems and general plant. These expenses reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the generation stations and periodic storm damage to the T&D system. Maintenance costs are expensed as incurred.
Goodwill and Other Intangible Assets
Allegheny records the acquisition cost in excess of fair value of tangible and intangible assets acquired, less liabilities assumed, as goodwill. Effective January 1, 2002, with the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), Allegheny ceased amortization of goodwill and now tests goodwill for impairment at least annually. Other intangible assets with indefinite lives are not amortized. Instead, these assets are 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.
Investments
Benefit plans’ investments primarily represent the estimated cash surrender values of purchased life insurance on qualifying management employees under executive life insurance and supplemental executive retirement plans.
Unregulated investments represent equity investments in, and loans to, unconsolidated entities. Equity investments are recorded using the equity method of accounting, if the investment gives Allegheny the ability to exercise significant influence, but not control, over the investee. The income or loss from unregulated investments is recorded in “Other income and expenses, net” in the Consolidated Statements of Operations.
Cash Equivalents
For purposes of the Consolidated Statements of Cash Flows and Consolidated Balance Sheets, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, repurchase agreements and money market funds, are considered to be the equivalent of cash.
Restricted Funds
Allegheny had restricted funds at December 31, 2004 and 2003 of $228.9 million and $120.9 million, respectively. The restricted funds held at December 31, 2004 were primarily comprised of $198.3 million of cash, which was received at the closing of certain asset sales during December and used to repay outstanding debt in January 2005 and $14.4 million of Competitive Transition Charges collected from customers. The restricted funds held at December 31, 2003 included $70.8 million held in escrow pending the fulfillment of certain post-closing obligations related to the sale of the California Department of Water Resources (“CDWR”) contract and related hedge agreements. These amounts are included in “Current assets” on the Consolidated Balance Sheets.
Collateral Deposits
Allegheny had collateral deposits at December 31, 2004 and 2003 of $88.7 million and $51.2 million, respectively. These deposits are posted as security with counterparties, for certain transactions including PJM, and transmission and transportation tariffs. These amounts are included in “Current assets” on the Consolidated
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Balance Sheets. Additionally, there was $0.2 million of collateral deposits at December 31, 2004 included in “Assets held for sale” on the Consolidated Balance Sheet.
Allegheny also has funds on deposit with a third party posted as collateral for the issuance of surety bonds. These amounts were $39.1 million and $39.0 million at December 31, 2004 and 2003, respectively, and are included in the caption “Other” within “Investments and other assets” on the Consolidated Balance Sheets.
Regulatory Assets and Liabilities
Under cost-based regulation, regulated enterprises generally are permitted to recover their operating expenses and earn a reasonable return on their utility investment.
Allegheny accounts for its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). The economic effects of regulation can result in a regulated company recording costs 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 would be charged to expense 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 SFAS No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. See Note 20, “Regulatory Assets and Liabilities,” for additional details regarding regulatory assets and liabilities.
Inventory
Allegheny values materials, supplies and fuel inventory using an average cost method.
Income Taxes
Book income differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using the most current tax rates. See Note 15, “Income Taxes,” for additional information regarding income taxes.
Allegheny has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.
Allegheny’s federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s federal income tax returns for 1998 through 2003. Management believes that its accrued tax liabilities are adequate and that any settlement related to such examination is not expected to have a material impact on Allegheny’s consolidated statement of operations, financial position or cash flow.
Pension and Other Postretirement Benefits
AE has noncontributory, defined benefit pension plans covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. The funding policy is to
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
contribute annually at least the minimum amount required under the Employee Retirement Income Security Act of 1974 (“ERISA”) and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments.
AE’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. The funding policy is to contribute amounts that can be deducted for federal income tax purposes. Medical benefits are self-insured.
Stock-Based Compensation
Allegheny maintains a stock-based employee compensation plan, which is described in greater detail in Note 18, “Stock-Based Compensation.” Allegheny accounts for this plan under the recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. No stock-based compensation relating to stock options was recognized in consolidated net loss in 2004, 2003 and 2002, as all options granted under the plan had an exercise price that equaled the market price of the underlying stock on the date of the grant.
Through July 2, 2004, Allegheny recorded compensation expense related to stock units issued to certain of its executive officers using the variable method of accounting. On July 2, 2004, Allegheny received authorization from the SEC to settle stock units in shares of AE’s common stock as the units vest. As a result, Allegheny began recording compensation expense relating to stock unit awards using the fixed method of accounting, effective July 3, 2004. The amount of this expense was approximately $18.7 million ($11.3 million, net of income tax) in 2004 and $10.6 million ($6.4 million, net of income tax) in 2003. No compensation expense was recorded in 2002.
Allegheny follows the disclosure provisions of SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure, an Amendment of SFAS No. 123.” The following table illustrates the effect on consolidated net loss and loss per share as if Allegheny had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to all stock-based employee compensation:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Other Comprehensive Income (Loss)
Other comprehensive income (loss) consists of unrealized gains and losses, net of income taxes, from the temporary decline in the fair value of available-for-sale securities, cash flow hedges and the adjustment for the minimum pension liability.
NOTE 3: CAPITALIZATION
Allegheny’s consolidated capital structure, including short-term debt and debt associated with assets held for sale and excluding minority interest, as of December 31, 2004 and 2003, was as follows:
Common Stock
Allegheny issued 0.4 million shares of its common stock during each of 2004 and 2003, primarily under its Dividend Reinvestment and Stock Purchase Plan, Employee Stock Ownership and Savings Plan and Long-Term Incentive Plan. Allegheny did not repurchase shares during 2004. During 2003, Allegheny repurchased 1.1 million shares, which were forfeited by employees under these plans.
On October 5, 2004, Allegheny sold 10 million shares of its common stock at a price of $15.15 per share directly to institutional investors in a private placement. The proceeds of the sale, and cash on hand, were used to reduce $200 million of debt at AE Supply.
Long-Term Debt
At December 31, 2004, contractual maturities for Allegheny’s long-term debt for the next five years, excluding $86.7 million of long-term debt included in liabilities associated with assets held for sale, are:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
At December 31, 2004, contractual maturities of long-term debt by entity, for the next five years, excluding $15.3 million of unamortized debt discounts and premiums and terminated interest rate swaps that were accounted for as fair value hedges under SFAS No. 133, are:
At December 31, 2004, substantially all of AE Supply’s properties are subject to liens of various relative priorities securing debt obligations, consisting of approximately $1.04 billion of bank debt restructured in October 2004 (of which $982 million remained outstanding as of December 31, 2004) and $344 million of notes that were restructured in February 2003. Substantially all of the properties owned by Monongahela and Potomac Edison are held subject to the liens securing their outstanding first mortgage bonds. Some properties owned by AE Supply and Monongahela are also subject to liens securing certain pollution control bonds and solid waste disposal notes.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
2004 Refinancings
On March 8, 2004, AE and AE Supply refinanced approximately $1.7 billion of long-term debt with new loans in an aggregate amount of $1.55 billion. These new loans consisted of secured Term B Loans and a secured Term C Loan (collectively, the “AE Supply Loans”) at AE Supply of $750 million and $500 million, respectively, and unsecured revolving and term loan facilities at AE of $300 million (the “New AE Facility” and collectively with the AE Supply Loans, the “New Loan Facilities”). On October 28, 2004, AE Supply refinanced the remaining $1.04 billion outstanding under the AE Supply Loan (as refinanced, the “Refinanced AE Supply Loan”). The terms of the New Loan Facilities and the Refinanced AE Supply Loan are described below:
AE Supply
•
A borrowing facility of $750 million consisting of secured Term B Loans in (a) an aggregate principal amount of $650 million (the “Term B Secured Loan”) and (b) an aggregate principal amount of $100 million (the “Term B Springdale Loan”). The Term B Secured Loan and the Term B Springdale Loan are collectively referred to as the (“Term B Loans”).
Provided that AE Supply meets certain requirements listed in the loan documents, including, but not limited to, ensuring that all covenants are maintained on a pro-forma basis and sufficient liens on collateral can be granted, AE Supply may request an increase in the principal amount under the Term B Secured Loan up to $200 million. Any increased amounts would amortize over the remaining term of the Term B Loans.
The Term B Loans bore interest at AE Supply’s option at either the London Interbank Offering Rate (“LIBOR”) plus a margin of 3.0% per annum or at a base lending rate plus a margin of 2.0% per annum, depending on AE Supply’s then current credit rating as provided by Standard and Poor’s (“S&P”) and Moody’s Investor Services (“Moody’s”).
The Term B Loans required repayments under a schedule providing for quarterly installments in an annual amount equal to one percent of the Term B Loans outstanding, with the balance payable on March 8, 2011.
•
A borrowing facility with an aggregate principal amount of $500 million (the “Term C Loan”).
The Term C Loan bore interest at AE Supply’s option at either LIBOR plus a margin of 4.25% per annum or at a base lending rate plus a margin of 3.25% per annum, depending on AE Supply’s then current credit rating as provided by S&P and Moody’s.
On October 28, 2004, AE Supply refinanced the remaining $1.04 billion outstanding under the AE Supply Loans. In connection with the refinancing of the AE Supply Loans, the Term B Loans and the Term C Loan were consolidated into the Refinanced AE Supply Loan. The Refinanced AE Supply Loan bore interest at a rate per annum equal to LIBOR plus 2.75%. Following the repayment of $200 million on January 14, 2005, the per annum interest rate on the Refinanced AE Supply Loan was reduced to LIBOR plus 2.50%. The Refinanced AE Supply Loan will mature on March 8, 2011.
The AE Supply Loans contained financial covenants, including a minimum interest coverage ratio and a maximum debt to EBITDA ratio (as defined). Other covenants included: limitations on the incurrence of debt, guarantees or other contingent obligations; creation of liens; entering into leases; mergers and consolidations; sales, transfers or other dispositions of assets; making of loans or investments; capital expenditures; making restricted payments or distributions; speculative transactions; transactions with affiliates and prepayments or redemptions of other debt. The AE Supply Loans also contained provisions requiring mandatory prepayments
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
with specified percentages of excess cash flow (as defined) and the net proceeds of certain asset sales, 50% of the net cash proceeds from the issuance of equity securities and 100% of the net cash proceeds from the issuance of debt securities, with certain exceptions. The Refinanced AE Supply Loan contains similar covenants.
The Refinanced AE Supply Loan is secured pari passu with the Amended A-Notes (as defined below) by a first priority perfected pledge of substantially all of the assets of AE Supply.
AE
•
The New AE Facility is an unsecured borrowing facility of up to an aggregate amount of $300 million. The New AE Facility is comprised of a $200 million revolving credit sub-facility, $100 million of which is available for the issuance of letters of credit, and a $100 million term loan.
The full amount of all borrowings is required to be repaid by March 8, 2007.
Interest on borrowings under the New AE Facility are at AE’s option at either LIBOR plus a margin of 2.5% to 3.0% per annum, depending on AE’s then current credit rating as provided by S&P and Moody’s, or an applicable bank lending base rate plus a margin of 1.5% to 2.0% per annum, depending on AE’s then current credit rating as provided by S&P and Moody’s.
The New AE Facility carries an unused commitment fee of 0.5% per annum and letter of credit fees comprised of a fronting fee of 0.35% and an additional annual fee of 2.5% to 3.0% on the face amount of outstanding letters of credit, depending on AE’s then current credit rating as provided by S&P and Moody’s.
The New AE Facility contains financial covenants, including a minimum interest coverage ratio and a maximum debt to EBITDA ratio (as defined). Other covenants include limitations on: incurrence of debt, guarantees or other contingent obligations; creation of liens, entering into leases; mergers and consolidations; sales, transfers or other dispositions of assets; making loans or investments; capital expenditures; making restricted payments or distributions; creating dividend restrictions on subsidiaries; speculative transactions; transactions with affiliates and prepayments or redemptions of other debt of AE or its subsidiaries.
The New AE Facility also contains provisions requiring mandatory prepayments with all of the net cash proceeds of asset sales after the first $100 million, subject to certain exceptions. Mandatory prepayments of the New AE Facility generally will be applied first to repay the term loan, then to repay borrowings for letters of credit and then to repay amounts outstanding under the revolving credit sub-facility.
In June 2004, Monongahela issued $120 million of 6.70% First Mortgage Bonds, which mature on June 15, 2014. The net proceeds of the bond issuance were used to repay Monongahela’s $53.6 million short-term bridge loan in June 2004 and to fund the July 2004 redemption of $40 million of 8.375% First Mortgage Bonds due 2022 and $25 million of 7.25% First Mortgage Bonds due 2007. Interest on the 6.70% First Mortgage Bonds is payable semi-annually in arrears on each June 15 and December 15, commencing December 15, 2004. The bonds are redeemable at Monongahela’s option and rank equally in right of payment with its existing or future first mortgage bonds.
In November 2004, Potomac Edison issued $175 million of 5.35% First Mortgage Bonds, which mature on November 15, 2014. The net proceeds of the bond issuance were used to fund the December 2004 redemption of $55.0 million of 8.0% First Mortgage Bonds due 2022, $45.0 million of 7.75% First Mortgage Bonds due 2023 and $75.0 million of 8.0% First Mortgage Bonds due 2024. Interest on the 5.35% First Mortgage Bonds is payable semi-annually in arrears on each May 15 and November 15, commencing May 15, 2005. The bonds are redeemable at Potomac Edison’s option and rank equally in right of payment with its existing or future unsubordinated debt.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
2004 Issuances and Redemptions
The aggregate amount of debt issued, by entity, during 2004 is shown below:
Redemptions of indebtedness, by entity, during 2004 are listed below:
2003 Long-Term Debt Refinancing
Allegheny refinanced existing debt and issued new debt on February 25, 2003 and March 13, 2003 under the Borrowing Facilities. The Borrowing Facilities were repaid in March 2004 with a combination of available cash and proceeds from the New Loan Facilities, as described above in “2004 Refinancing,” except for the $55 million revolving credit facility at Monongahela described below, which was repaid with the proceeds of Monongahela’s June 2004 issuance of first mortgage bonds.
Following is a summary of the terms of the Borrowing Facilities:
1.
Facilities at AE, Monongahela and West Penn:
•
A $305.0 million unsecured facility with AE, Monongahela and West Penn as the designated borrowers, under which AE utilized the full facility amount. Borrowings under this facility bore interest at LIBOR based rate plus a margin of 5% or a designated money center bank’s base rate plus a margin of 4%. As of December 31, 2003, the interest rate was approximately 6.12%. This facility required a quarterly amortization payment of $7.5 million. This facility was repaid in March 2004 with proceeds from the New Loan Facilities;
•
A $25.0 million unsecured credit facility at AE. This facility had an interest rate of a designated money center bank’s base rate plus a margin of 4% and was repaid in July 2003; and
•
A $10.0 million unsecured credit facility at Monongahela. On September 24, 2003, this facility was renegotiated as part of a $55 million revolving facility, of which $53.6 million was drawn at December 31, 2003. The interest on the facility was dependent upon the type of advance and consisted of a base rate plus
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
an applicable margin or a LIBOR-based rate plus an applicable margin. As of December 31, 2003, the LIBOR-based rate was approximately 4.63%. This facility matured in September 2004 and was classified as short-term debt on the Consolidated Balance Sheet as of December 31, 2003.
2.
Facilities at AE Supply (all outstanding amounts at December 31, 2003 were repaid in March 2004 with a combination of available cash and proceeds from the New Loan Facilities):
•
A $987.7 million credit facility (the “Refinancing Credit Facility”) at AE Supply, of which $893.4 million was secured by substantially all of the assets of AE Supply. Borrowings under the facility bore initial interest at a LIBOR-based rate plus a margin of 6% or a designated money center bank’s base rate plus a margin of 5% on the secured portion. The interest rate margin applicable to unsecured borrowings under the facility was 10.5%. As of December 31, 2003, the interest rate was approximately 7.83%. This facility required amortization payments of approximately $23.6 million in September 2004 and $117.8 million in December 2004, and matured in April 2005;
•
A $470.0 million credit facility, of which $420.0 million was drawn and $50.0 million is no longer committed. The facility was secured by substantially all of AE Supply’s assets. Borrowings under the facility bore interest at a LIBOR-based rate plus a margin of 6% or a designated money center bank’s base rate plus a margin of 5%. As of December 31, 2003, the interest rate was approximately 7.12%. In December 2003, $250.0 million of the facility was repaid. This facility required a final amortization payment of $170.0 million in September 2004; and
•
A $270.1 million credit facility (the “Springdale Credit Facility”) associated with the financing of the construction of AE Supply’s new generation facility in Springdale, Pennsylvania, which was secured by a combination of that facility and substantially all of AE Supply’s assets. Borrowings under the facility bore interest at a LIBOR-based rate plus a margin of 6% or a designated money center bank’s base rate plus a margin of 5%, on the portion secured by substantially all of AE Supply’s assets. The interest rate margin applicable to the remainder of the borrowings under the facility was 10.5%. As of December 31, 2003, the interest rate was approximately 10.62%. This facility required amortization payments of $6.4 million in September 2004, and $32.2 million in December 2004, and matured in April 2005.
In addition, $380.0 million of indebtedness related to the discontinued St. Joseph, Indiana generation project, in the form of A-Notes, was restructured and assumed by AE Supply in connection with the Borrowing Facilities (the “Amended A-Notes”). Of this debt, $343.7 million is secured by substantially all the assets of AE Supply, other than its generation facility in Springdale, Pennsylvania. The secured portion of this debt bears an interest rate of 10.25%, and the unsecured portion bears interest at 13.0%.
The $420.0 million borrowed by AE Supply under the $470.0 million facility represented new liquidity to Allegheny during 2003. The Borrowing Facilities at AE Supply also refinanced $1,637.8 million of existing debt and letters of credit, including $894.9 million outstanding under various credit agreements, and $270.1 million outstanding related to the construction of AE Supply’s generation facility in Springdale, Pennsylvania, which went into commercial operation in July 2003. The Borrowing Facilities at AE, Monongahela and West Penn refinanced $340.0 million of existing debt and letters of credit.
Until August 1, 2003, after certain conditions associated with securing the collateral under the Borrowing Facilities were met on July 19, 2003, the LIBOR component charged to AE Supply under the Borrowing Facilities with respect to secured borrowings had a two percent floor. Also, because AE Supply was unable to secure all of the Borrowing Facilities and the Amended A-Note debt before July 31, 2003, the interest rates
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
charged on the amounts not so secured increased to a spread of 10.5% over the applicable LIBOR-based rate, which contained a two percent floor for unsecured borrowings, or the designated money center bank’s base rate for the Refinancing Credit Facility and the Springdale Credit Facility, and the interest rate increased to 13.0% for the unsecured portion of the $380.0 million A-Note debt retroactively to February 25, 2003, the closing date of the Borrowing Facilities. The total amounts unsecured under the Refinancing Credit Facility, the Springdale Credit Facility and the Amended A-Note debt at December 31, 2003 were approximately $94.3 million, $175.8 million and $36.3 million, respectively.
AE Supply utilized $2,057.8 million under the Borrowing Facilities and the restructured A-Notes. Either AE Supply’s new generation facility in Springdale, Pennsylvania or substantially all of AE Supply’s assets secured $1,927.2 million of this total amount. A covenant in AE Supply’s public debt places limitations, with certain exceptions, upon the issuance of secured debt. This limitation will constrain AE Supply’s ability to borrow additional funds until outstanding debt is reduced.
Convertible Trust Preferred Securities Issuance
On July 24, 2003, Allegheny obtained $291 million ($275 million after deducting various fees and placement agents’ commissions) from the issuance to Allegheny Capital Trust I, a wholly owned special purpose finance subsidiary of AE (“Capital Trust”), of units (“Units”) comprised of $300 million principal amount of 11 7/8% Notes due 2008 (the “Notes”) and warrants (the “Warrants”) for the purchase of up to 25 million shares of AE’s common stock, exercisable at $12 per share. The Warrants are mandatorily exercisable if AE’s common stock price equals or exceeds $15 per share over a specified averaging period occurring after June 15, 2006. The Warrants are attached to the Notes and may be exercised only through the tender of the Notes. As of June 15, 2006, Allegheny has the right to redeem the Notes at a redemption price of 105.9375% of the principal amount. Capital Trust purchased the Units with proceeds from the sale of $300 million of its 11 7/8% Mandatorily-Convertible Trust Preferred Securities (the “Trust Preferred Securities”) to investors in a private placement. Holders of Trust Preferred Securities are entitled to distributions on a corresponding principal amount of Notes and may direct the exercise of Warrants. AE fully and unconditionally guarantees Capital Trust’s payment obligations under the Trust Preferred Securities. The Notes and AE’s guarantee of Capital Trust’s payment obligations are subordinated only to the AE indebtedness arising under the New Loan Facilities. The Notes are recorded as long-term debt on Allegheny’s Consolidated Balance Sheets.
2003 Issuances and Redemptions
The aggregate amount of debt issued, by entity, during 2003 is shown below:
Of the amounts listed above, the $25.0 million unsecured credit facility at AE was repaid in July 2003, $33.0 million of the $305.0 million unsecured credit facility at AE was repaid during 2003 and $250.0 million of
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
the $420.0 million credit facility at AE Supply was repaid in December 2003. The $10 million unsecured credit facility at Monongahela was renegotiated as part of a $55 million revolving facility of which $53.6 million was drawn and the remainder is no longer available.
Redemptions of debt, by entity, during 2003 are listed below:
NOTE 4: ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
During the third quarter of 2004, Allegheny and certain of its subsidiaries entered into agreements to sell, or made the decision to sell, certain non-core assets. The results of operations relating to these assets have been reclassified to discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. In accordance with SFAS No. 144, the assets and liabilities associated with these discontinued operations have been reclassified as held for sale in the accompanying Consolidated Balance Sheets subsequent to the date that held for sale criteria were met. These assets are recorded at the lower of carrying amount or fair value, less estimated costs to sell, and are no longer depreciated. Allegheny recorded impairment charges for certain of the assets held for sale as described below. These impairment charges reflect the write-down of the applicable asset to the lower of its carrying amount or fair value, less estimated costs to sell.
Natural Gas Operations. In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia to Mountaineer Gas Holdings Limited Partnership (the “Buyer”), a partnership composed of IGS Utilities LLC, IGS Holdings LLC and affiliates of ArcLight Capital Partners, LLC, for $141 million in cash and the assumption of approximately $87 million of long-term debt, subject to certain closing adjustments. In addition, the Buyer will pay Monongahela, over a three-year period, certain amounts due to Monongahela from affiliates holding or owning Monongahela’s West Virginia natural gas operations. These amounts will be finally determined at the closing of the transaction. Allegheny expects to utilize net proceeds from the sale to reduce debt. Monongahela’s natural gas operations consist of the natural gas assets of Monongahela, Mountaineer and Mountaineer Gas Services, which is a subsidiary of Mountaineer. The agreement is subject to certain closing conditions, third-party consents and state and federal regulatory approvals, including approval of a rate adjustment from the Public Service Commission of West Virginia (“West Virginia PSC”). The sale is expected to be completed in mid- to late-2005.
During 2004, Monongahela recorded a charge against earnings to write-down its investment in its natural gas operations to the expected net proceeds from the sale. The write-down resulted in a charge against earnings of $36.7 million, before income taxes ($21.7 million, net of income taxes). This write-down is included in “Loss from discontinued operations, net of tax” in Allegheny’s and Monongahela’s Consolidated Statements of Operations. The gas operations are a component of the Delivery and Services segment.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Midwest Assets. During the third quarter of 2004, AE Supply recorded a charge against earnings to write-down its investment in the Lincoln Generating Facility to the expected net proceeds from the sale. The write-down resulted in a charge against earnings of $209.4 million, before income taxes ($129.2 million, net of income taxes). This write-down is included in “Loss from discontinued operations, net of tax” in Allegheny’s Consolidated Statements of Operations. The Lincoln Generating Facility was a component of Allegheny’s Generation and Marketing segment. In December 2004, AE Supply sold its 672 MW Lincoln Generating Facility and used the $175.0 million of cash proceeds to reduce debt in December 2004 and January 2005.
AE Supply also recorded write-downs to fair value of its investments in its two remaining Midwest natural-gas fired peaking facilities, the Wheatland Generating Facility and the Gleason Generating Facility, as a result of its decision to sell these facilities. These write-downs resulted in an aggregate charge against earnings of $445.4 million, before income taxes ($274.7 million, net of income taxes). These write-downs are included in loss from discontinued operations in Allegheny’s Consolidated Statements of Operations. A portion of AE Supply’s consolidated interest expense was allocated to discontinued operations for these two facilities based on the estimated relative fair value of the assets. These assets are a component of Allegheny’s Generation and Marketing segment.
Other. In July 2004, Potomac Edison entered into an agreement to sell its Hagerstown, Maryland property for approximately $13 million in cash. The potential buyer terminated the sales agreement in December 2004. Potomac Edison is continuing to market this property and expects to complete a sale in 2005. In December 2004, Potomac Edison recorded a write-down to fair value less estimated costs to sell, which resulted in an impairment charge of $0.9 million, before income taxes ($0.5 million, net of income taxes). This impairment charge is recorded in “Other income and expenses, net” on the Consolidated Statements of Operations for Allegheny and Potomac Edison. This asset has been recorded as an asset held for sale within “Investments and Other Assets” on the Consolidated Balance Sheet as of December 31, 2004. This asset is included in Allegheny’s Delivery and Services segment.
In December 2004, AE Supply made the decision, and reached a tentative agreement, to sell approximately 149 acres of land. AE Supply recorded a write-down to fair value less estimated costs to sell, during December 2004, which resulted in an impairment charge of $1.2 million, before income taxes ($0.7 million, net of income taxes). This impairment charge is recorded in “Other income and expenses, net” on Allegheny’s Consolidated Statements of Operations. This asset has been recorded as an asset held for sale within “Investments and Other Assets” on the Consolidated Balance Sheet as of December 31, 2004. This asset is included in Allegheny’s Generation and Marketing segment.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The components of (loss) income from discontinued operations are as follows:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Assets held for sale and liabilities associated with assets held for sale at December 31, 2004 were as follows:
NOTE 5: WHOLESALE ENERGY ACTIVITIES
Allegheny records the trading contracts used in AE Supply’s wholesale marketing activities at fair value on the Consolidated Balance Sheets. All changes in fair value are recorded as gains or losses on the Consolidated Statements of Operations in “Operating revenues,” unless the contract falls within the “normal purchase and normal sale” scope exception of SFAS No. 133 or is designated as a hedge for accounting purposes. The normal purchase and normal sale 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 a normal purchase and normal sale 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 gain or loss is initially recorded as a separate component of stockholders’ equity under the caption “Accumulated other comprehensive income (loss)” and subsequently reclassified into earnings when the forecasted transaction is completed or settled. The ineffective portion of the hedge is immediately reflected in earnings.
Fair values for exchange-traded instruments, principally futures and certain options, are based on quoted market prices. In establishing the fair value of commodity contracts that do not have quoted market prices, such as physical contracts, over-the-counter options and swaps, management makes estimates using available market data and pricing models. Factors such as commodity price risk, operational risk and credit risk of counterparties are evaluated in establishing the fair value of commodity contracts. The commodity contracts include certain financial instruments, such as interest rate swaps, which are used to mitigate the effect of interest rate changes on the fair value of commodity contracts.
Allegheny has contracts that are unique due to their long-term nature and terms and are valued using proprietary pricing models. Inputs to the models include estimated forward natural gas and power prices, interest rates, estimates of market volatility for natural gas and power prices and the correlation of natural gas and power prices. These inputs depend heavily on judgments and assumptions by management. These inputs become more difficult to predict, and the models become less precise, the further into the future these estimates are made. There may be an adverse effect on Allegheny’s financial position and results of operations if the judgments and assumptions underlying those models’ inputs prove to be wrong or inaccurate. Exposure to these types of contracts has declined significantly as a result of AE Supply’s exit from the Western U.S. energy markets.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The fair values of trading commodity contracts, which represent net unrealized gain and loss positions, are recorded as assets and liabilities, respectively, after applying the appropriate counterparty netting agreements in accordance with FASB Interpretation No. 39. At December 31, 2004, the fair values of the trading commodity contract assets and liabilities were $17.2 million and $97.3 million, respectively. At December 31, 2003, the fair values of the trading commodity contract assets and liabilities were $29.9 million and $102.6 million, respectively.
In June 2002, EITF 02-3 was issued. EITF 02-3 requires that mark-to-market gains and losses on energy trading contracts (whether realized or unrealized) be shown net in the Consolidated Statements of Operations. During 2002, Allegheny modified its reporting as a result of EITF 02-3 to reflect the revenues from energy trading activities, net of the cost of purchased power and transmission, related to contracts that require physical delivery.
Net unrealized losses of $5.7 million, $468.4 million and $358.4 million, before income taxes, were recorded in “Operating revenues” to reflect the change in fair value of the trading contracts for 2004, 2003 and 2002, respectively.
2004 Events:
AE Supply has designated certain contracts as cash flow hedges effective July 1, 2004. Changes in the fair value of these contracts are reflected in “Accumulated other comprehensive income (loss)” after they are designated as cash flow hedges. The derivative liabilities associated with each contract at the time of their designation as a cash flow hedge will be realized in earnings over the remaining term of each contract, in accordance with the estimated cash flow of each contract at the time of designation. These contracts expire at various dates through December 31 2006 and represent an aggregate liability at December 31, 2004 of $31.0 million. The increase in this liability since June 30, 2004 is a result of the change in the fair value of such contracts, $3.3 million of which has been reflected in “Accumulated other comprehensive income (loss).” Based on the fair value of AE Supply’s financial instruments as of December 31, 2004, accumulated other comprehensive income (loss) of $0.2 million is expected to be reclassified as an increase to earnings over the next twelve months. The ineffective portion of the cash flow hedges was reflected in earnings for the year ended December 31, 2004 and was not material.
In addition, during 2004, AE Supply has been designating certain contracts that qualify for the normal purchase and normal sale SFAS No.133 scope exception. The impact of these designations is to qualify certain contracts for the accrual method of accounting as opposed to marking these contracts to market or fair value accounting.
Events:
Strategy Change in 2003
Allegheny worked throughout 2003 to accomplish AE Supply’s exit from the Western U.S. energy markets, as well as other speculative trading positions. AE Supply’s positions based in the Western U.S. had been a substantial source of earnings and cash flow volatility and risk, and trading in these markets did not fit with Allegheny’s intentions to focus on its core business.
Renegotiation and Sale of the CDWR Contract
In June 2003, AE Supply entered into a settlement agreement with the State of California to resolve the state’s litigation regarding its power supply contract with the CDWR. The terms of the settlement reduced the
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
volume of power to be delivered from 2005 through 2011 and reduced the sale price of off-peak power to be delivered from 2004 through 2011, which in turn substantially reduced the value of the contract. On September 15, 2003, AE Supply and its subsidiary, Allegheny Trade Finance (“ATF”), sold the CDWR contract and associated hedge transactions, to J. Aron & Company, a subsidiary of The Goldman Sachs Group, Inc., for approximately $354 million. Allegheny applied $214 million of the sale proceeds to required payments under agreements entered into to terminate tolling agreements with Williams Energy Marketing & Trading Company (“Williams”) and Las Vegas Cogeneration II, L.L.C. (“LV Cogen”), a unit of Black Hills Corporation, as described below. Allegheny applied an additional $28 million of the proceeds to make required payments in March and September of 2004 under the agreement with Williams. Approximately $26 million was held in a pledged account for the benefit of AE Supply’s creditors. Approximately $71 million of the sale proceeds were placed in escrow for the benefit of J. Aron & Company, pending Allegheny’s fulfillment of certain post-closing requirements. On March 3, 2004, the funds were released from escrow, which resulted in the recognition of a gain of approximately $68 million in the first quarter of 2004. Approximately $15 million of sale proceeds were used to partially offset certain hedges related to the CDWR contract and to pay fees and expenses associated with the transaction.
During 2003, AE Supply exited the Western U.S. energy trading markets, including all related contracts and hedge agreements. As a result, Allegheny recorded a net loss of approximately $535.2 million. This loss was recorded as a component of “Operating revenues” in the Consolidated Statements of Operations. This loss did not include the approximately $71 million of proceeds from the sale of the CDWR contract that were placed in escrow, as described above.
Refocusing Trading Activities
AE Supply has reoriented its trading operations from high-volume financial trading in national markets to asset optimization and hedging within its region. Following its exit from the Western U.S. energy markets, AE Supply is concentrating its efforts in the PJM and Mid-Atlantic markets.
2002 Events:
As a result of significant changes in market conditions in 2002, AE Supply performed a comprehensive assessment of the valuation techniques and assumptions used to value its then existing portfolio of energy commodity contracts. To reflect then current market conditions, AE Supply revised the valuation techniques and assumptions for certain contracts with option features. As a result, AE Supply reduced the value of its portfolio of energy commodity contracts by $356.3 million, before income taxes, in the third quarter of 2002.
During the fourth quarter of 2002, the fair value of AE Supply’s portfolio of energy commodity contracts was reduced by an additional $216.4 million, before income taxes. This reduction in fair value resulted from a decrease in the liquidity and volatility of the energy markets in the Western U.S. This decrease in market liquidity and volatility primarily affected the fair values related to the Williams and LV Cogen agreements. Both of these agreements were terminated in 2003, as noted above in “Renegotiation and Sale of the CDWR Contract.”
Implementation of EITF 02-3:
•
EITF 02-3 also reached a consensus that all new contracts that are not derivatives as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133-an amendment of FASB Statement No. 133,” (“SFAS No. 137”) and SFAS
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities-an amendment of FASB Statement No. 133,” (collectively, with SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” (“SFAS No. 149”) referred to as “SFAS No. 133”), entered into subsequent to October 25, 2002, should be accounted for on the accrual basis of accounting as executory contracts and would not qualify for mark-to-market accounting.
•
The effective date for the full rescission of EITF Issue No. 98-10 is for fiscal periods beginning after December 15, 2002. The effect of rescinding Issue No. 98-10 is reported as a cumulative effect of a change in accounting principle in accordance with APB Opinion No. 20, “Accounting Changes.”
In connection with its implementation of EITF 02-3, AE Supply recorded a loss as a cumulative effect of an accounting change of approximately $19.7 million, before income taxes ($12.2 million, net of income taxes), in the first quarter of 2003. This charge represented the fair value of those contracts previously accounted for under EITF Issue No. 98-10 that no longer qualify for mark-to-market accounting.
NOTE 6: ASSET SALES
On December 31, 2004, AE completed the sale of a 9% equity interest in the Ohio Valley Electric Corporation (“OVEC”) to Buckeye Power Generating, LLC (“Buckeye”). In addition, AE Supply assigned to Buckeye all of its rights and obligations under the Amended and Restated OVEC Inter-Company Power Agreement (the “New ICPA”) effective March 13, 2006. The aggregate purchase price for the equity sale by AE and the assignment of AE Supply’s rights in the New ICPA was $102 million. AE Supply will retain its rights to 9% of the power from the OVEC electric generation facility through March 12, 2006. The sale resulted in a gain of $94.8 million, before income taxes ($60.0 million, net of income taxes), which is recorded in “Gain on sale of OVEC power agreement and shares” on the Consolidated Statements of Operations. AE recorded a gain of $6.2 million, before income taxes ($4.0 million, net of income taxes), and AE Supply recorded a gain of $88.6 million, before income taxes ($56.0 million, net of income taxes). Cash proceeds from the sale were $102.0 million, of which $6.0 million is expected to be received in March 2006 upon the fulfillment of certain post-closing obligations. Of the remaining $96.0 million in proceeds, $88.9 million was used to reduce debt in January 2005.
In December 2004, AE Supply sold its 672 MW Lincoln Generating Facility, in Manhattan, Illinois, together with an associated tolling agreement, to an affiliate of ArcLight Capital Partners, LLC. The sale resulted in a gain of $1.8 million, before income taxes ($1.1 million, net of income taxes), based on the previously written down value of these assets. This gain is recorded in “Loss from discontinued operations, net of tax” on the Consolidated Statements of Operations. Cash proceeds from the sale were $175.0 million, which were used to reduce debt.
In June 2003, AE Supply sold its 83 MW share of the coal-fired Conemaugh Generating Station to UGI Development Company, an indirect, wholly owned subsidiary of UGI Corp., for approximately $46.3 million in cash and a contingent amount of $5.0 million, which was received on March 3, 2004 after the satisfaction of certain post-closing obligations. The sale resulted in a loss to AE Supply of $28.5 million, before income taxes in 2003, without considering the contingent amount.
On November 1, 2001, Allegheny Ventures acquired Fellon-McCord, an energy consulting and management services company, and Alliance Energy Services, a provider of natural gas and other energy-related services to large commercial and industrial customers. Allegheny, which accounted for this transaction as a purchase, completed this acquisition for $30.8 million in cash, including direct costs of the acquisition, plus a maximum of $18.7 million in contingent consideration to be paid over a three-year period starting from the acquisition date. This $18.7 million in contingent consideration was recorded in December 2002 and paid on January 2, 2003,
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
subject to change of control provisions in the original acquisition agreement. Taking into account purchase price adjustments made in 2002 and the contingent consideration recorded in December 2002, Allegheny recorded $1.2 million as the fair value of net assets acquired and $48.3 million as the excess of cost over net assets acquired (goodwill). Pursuant to a participation agreement entered into as part of the acquisition of Mountaineer, on March 1, 2002, Allegheny Ventures sold a 20% indirect interest in Alliance Energy Services to Energy Corporation of America. Effective December 31, 2002, Allegheny Ventures sold Fellon-McCord and Alliance Energy Services to a third party for $21.8 million. Allegheny recorded a loss on this sale of $31.5 million, before minority interest and income taxes ($18.8 million, net of income taxes).
NOTE 7: ASSET IMPAIRMENTS
In July 2004, Potomac Edison entered into an agreement to sell its Hagerstown, Maryland property. The potential buyer terminated the sales agreement in December 2004. Potomac Edison is continuing to market this property and expects to complete a sale in 2005. Potomac Edison recorded a write-down to fair value less estimated costs to sell, during December 2004, which resulted in an impairment charge of $0.9 million, before income taxes ($0.5 million, net of income taxes). See Note 4, “Assets Held for Sale and Discontinued Operations,” for additional information regarding this asset impairment.
During the fourth quarter of 2004, AE Supply made the decision, and reached a tentative agreement, to sell approximately 149 acres of land. AE Supply recorded a write-down to fair value less estimated costs to sell, during December 2004, which resulted in an impairment charge of $1.2 million, before income taxes ($0.7 million, net of income taxes). See Note 4, “Assets Held for Sale and Discontinued Operations,” for additional information regarding this asset impairment.
During 2004, Monongahela recorded a charge against earnings to write-down its investment in its West Virginia natural gas operations to the expected net proceeds from the sale of these assets. The write-down resulted in a charge against earnings of $36.7 million, before income taxes ($21.7 million, net of income taxes). See Note 4, “Assets Held for Sale and Discontinued Operations,” for additional information regarding this asset impairment.
AE Supply recorded a charge against earnings to write-down its investment in the Lincoln Generating Facility to the expected net proceeds from the sale. The write-down resulted in a charge against earnings of $209.4 million, before income taxes ($129.2 million, net of income taxes). Also during the third quarter of 2004, AE Supply recorded write-downs to fair value of its investments in its two remaining Midwest natural-gas fired peaking facilities, the Wheatland Generating Facility and the Gleason Generating Facility, as a result of its decision to sell these facilities. These write-downs resulted in an aggregate charge against earnings of $445.4 million, before income taxes ($274.7 million, net of income taxes). See Note 4, “Assets Held for Sale and Discontinued Operations,” for additional information regarding these asset impairments.
In the fourth quarter of 2002, circumstances surrounding the St. Joseph generation facility, a 630 MW merchant power plant under construction, indicated that the carrying amount of the facility would not be recoverable through operations. Allegheny and AE Supply determined that the completion of the construction of the St. Joseph generation facility was not possible given their liquidity constraints and, therefore, they could not proceed with the construction. AE Supply terminated construction of the St. Joseph generation facility and recorded an impairment charge of $192.0 million, before income taxes ($118.4 million, net of income taxes). This impairment charge included amounts to record closure and cancellation costs associated with the facility.
In 2002, AE Supply cancelled the planned construction and investment in a 79 MW barge-mounted generation project, a planned 1,080 MW natural gas-fired generation facility and certain other early-stage
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
development generation projects. AE Supply recorded impairment charges with respect to these projects, as the carrying amounts of each project were determined not to be recoverable through operations. The impairment charges were the result of the write-down of the projects to their estimated fair values and the recording of the estimated costs to cancel the projects. The impairment charges associated with these generation projects were approximately $52.0 million, before income taxes ($30.8 million, net of income taxes).
The estimated fair values of these generation projects were determined using discounted future projected cash flows of the projects, as well as indications from unrelated third parties regarding the value of the projects. The total impairment charges for 2002 related to cancelled generation projects of $244.0 million, before income taxes ($149.2 million, net of income taxes) are recorded in “Operations and maintenance” expense on the Consolidated Statements of Operations.
In 2002, circumstances surrounding several unregulated investments indicated that their carrying amounts may not have been recoverable. An impairment charge of $44.7 million, before income taxes ($26.5 million, net of income taxes) was recorded to write off the unregulated investments. The impairment charges on these investments were recorded in “Other income and expenses, net” on the Consolidated Statements of Operations.
As a result of Allegheny’s sale of Fellon-McCord and Alliance Energy Services in December 2002, the $48.3 million of goodwill carried on the books of these entities and reflected in Allegheny’s Delivery and Services segment was written off in December 2002.
NOTE 8: GOODWILL AND OTHER INTANGIBLE ASSETS
On January 1, 2002, Allegheny adopted SFAS No. 142 which eliminated amortization of goodwill and other intangible assets with indefinite lives, effective January 1, 2002. Subsequent to the transition provisions of SFAS No. 142 (see below), goodwill and other intangible assets with indefinite lives are tested annually for impairment, with impairment losses recognized in operating income. Absent any impairment indicators, Allegheny performs its annual impairment tests during its third quarter in connection with its annual budgeting process.
The transition provisions of SFAS No. 142 required Allegheny to test its goodwill for impairment as of January 1, 2002. Allegheny completed its transitional goodwill impairment test, using a discounted cash flow methodology to determine the estimated fair value of its reporting units, and recorded an impairment loss of $210.1 million, before income taxes ($130.5 million, net of income taxes), all of which related to the Delivery and Services segment. This impairment loss was recorded as the cumulative effect of a change in accounting principle.
The transitional goodwill impairment loss consists of $170.0 million related to Monongahela’s acquisition of Mountaineer in 2000, $25.0 million related to Monongahela’s acquisition of West Virginia Power in 1999 and $15.1 million of other regulated utility goodwill at AE, related to activity recorded prior to 1966. The impairment amounts resulted from factors that are unique to these rate regulated entities and the rate-making process, including the fact that none of the $210.1 million of goodwill was being recovered in rates or included in rate base. As a result, Monongahela and AE recorded after-tax charges of $115.4 million and $15.1 million, respectively, as a cumulative effect of a change in accounting principle.
Transitional provisions also were completed with respect to Allegheny’s other intangible assets, resulting in no impairments or changes to amortizable lives.
The goodwill of $367.3 million at December 31, 2004 and 2003 was attributable to the Generation and Marketing segment. There were no additions to, or disposals of, goodwill during 2004 and 2003. The annual
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
impairment test used a discounted cash flow methodology to determine the fair value of the Generation and Marketing segment and indicated no impairment of goodwill. This test result reflects that AE Supply’s fleet of generation stations, comprised primarily of low-cost coal-fired steam generation stations, has a fair value in excess of the carrying value of those assets sufficient to cover goodwill associated with the 2001 acquisition of the energy trading business, and no impairment of goodwill is required.
Intangible assets of $33.2 million and $41.7 million as of December 31, 2004 and 2003, respectively, related to an additional minimum pension liability, as discussed in Note 17, “Pension Benefits and Postretirement Benefits Other Than Pensions.”
Additional intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:
In addition, “Assets held for Sale” included intangible assets related to natural gas rights, amortized with a gross carrying amount of $8.3 and 8.1 million at December 31, 2004 and 2003, respectively, and accumulated depreciation of $4.7 million and $4.4 million at December 31, 2004 and 2003, respectively.
Amortization expense for other intangible assets for 2004, 2003 and 2002 was $19.0 million, $23.0 million and $49.6 million, respectively. Amortization expense for 2002 includes amounts related to Fellon-McCord and Alliance Energy Services. Amortization expense is estimated to be $19.0 million annually for 2005 through 2009.
NOTE 9: RESTRUCTURING CHARGES AND WORKFORCE REDUCTION EXPENSES
In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction and a reorganization of Allegheny’s energy trading division. For the year ended December 31, 2002, Allegheny recorded a charge for the restructuring and workforce reduction of $128.3 million, before income taxes ($77.5 million, net of income taxes). In addition, as a result of the restructuring, Allegheny recorded a charge of $7.9 million, before income taxes ($4.9 million, net of income taxes) for impairment of leasehold improvements.
Allegheny achieved workforce reductions in 2002 of approximately 10% primarily through a voluntary early retirement option (“ERO”) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For the year ended December 31, 2002, approximately 600 eligible employees accepted the ERO program, resulting in a charge of $82.3 million, before income taxes ($49.3 million, net of income taxes). Allegheny also offered a Staffing Reduction Separation Program (“SRSP”) for employees whose positions were being eliminated as part of the workforce reductions and severance for certain energy trading
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
employees. The severance and other employee-related costs were accounted for in accordance with EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” For the year ended December 31, 2002, Allegheny recorded a charge of $25.0 million, before income taxes ($15.3 million, net of income taxes) related to approximately 80 employees whose positions had been eliminated. Allegheny has completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expenses” on the Consolidated Statements of Operations. The reorganization of Allegheny’s energy trading division includes the relocation of the trading operations and resulted in a charge of approximately $21.0 million, before income taxes ($12.9 million, net of income taxes), related to costs associated with the relocation which are recorded as “Operations and maintenance expense” on the Consolidated Statements of Operations.
During May 2003, an additional charge of approximately $4.5 million related to additional operating lease changes arising from relocating the trading operations was recorded as “Operations and maintenance” expense.
The following table provides a roll forward of Allegheny’s pre-tax expenses and liabilities related to the 2002 restructuring charge to the liability balance at December 31, 2004 (excluding the $7.9 million impairment charge related to the abandoned leasehold improvements):
The table above does not include Allegheny’s transition and severance expense of $5.7 million and $6.1 million in 2004 and 2003, respectively, which is included in “Operations and maintenance” expense on the Consolidated Statements of Operations.
NOTE 10: DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Effective January 1, 2001, Allegheny adopted SFAS No. 133, which established accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives), and for hedging activities. SFAS No. 133, as amended, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The standard requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The accounting for qualifying cash flow hedges allows a derivative’s gains and losses to offset related results on the hedged item in earnings or other
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
comprehensive income (loss) and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. Derivatives treated as a normal purchase or normal sale are recorded and recognized as income using accrual accounting under a scope exception within SFAS No. 133.
The fair value of AE Supply’s trading portfolio is primarily comprised of interest rate swap agreements and commodity cash flow hedges, which represented a net liability of $80.1 million and $72.7 million as of December 31, 2004 and 2003, respectively. These are accounted for at fair value on the Consolidated Balance Sheets.
AE Supply has designated certain contracts as cash flow hedges effective July 1, 2004. Changes in the fair value of these contracts are reflected in “Accumulated other comprehensive income (loss)” after their designation as cash flow hedges. The derivative liabilities associated with each contract at the time of their designation as a cash flow hedge will be realized in earnings over the remaining term of each contract, in accordance with the estimated cash flow of each contract at the time of designation. These contracts expire at various dates through December 31, 2006 and represented an aggregate liability at December 31, 2004 of $31.0 million. The increase in this liability since June 30, 2004 is a result of the change in the fair value of these contracts, $3.3 million of which has been reflected in “Accumulated other comprehensive income (loss).” Based on the fair value of AE Supply’s financial instruments as of December 31, 2004, accumulated other comprehensive income (loss) of $0.2 million is expected to be reclassified as an increase to earnings over the next twelve months. The ineffective portion of the cash flow hedges was reflected in earnings for the year ended December 31, 2004 and was not material.
On March 19, 2002, AE Supply entered into two treasury lock agreements to hedge its exposure to changing United States Treasury interest rates on the forecasted issuance of long-term, fixed-rate debt in April 2002. These treasury lock agreements were accounted for as cash flow hedges. In April 2002, these contracts were settled at a loss of $1.6 million, before income taxes ($1.0 million, net of income taxes). The unrealized loss was recorded in other comprehensive income (loss). In April 2002, AE Supply began reclassifying to earnings the amounts in accumulated other comprehensive income (loss) for these treasury lock agreements over the life of the 10 year debt. For each of 2004, 2003 and 2002, $0.2 million, before income taxes ($0.1 million, net of income taxes) was reclassified from accumulated other comprehensive income (loss) to earnings.
On August 1, 2000, Allegheny issued a $165.0 million, 7.75% fixed-rate note and a $135.0 million, 7.75% fixed-rate note. Each note matures on August 1, 2005 and requires semi-annual interest payments on August 1 and February 1. On April 24, 2002, Allegheny entered into an interest rate swap to convert the notes’ fixed rates to variable rates for the notes’ remaining terms. Under the term of the swap, Allegheny received interest at a fixed rate of 7.75% and paid interest at a variable rate equal to the three-month LIBOR plus a fixed spread. Allegheny designated the swap as a fair-value hedge of changes in the general level of market interest rates. During September 2002, Allegheny terminated the interest rate swap at its fair value of $11.3 million. As a result, Allegheny has discontinued its fair value hedge accounting. The increase in the carrying amount of the fixed-rate notes of $11.3 million as a result of the fair value hedge accounting is being amortized over the remaining life of the notes. For 2004, 2003 and 2002, $3.8 million, $3.8 million and $1.5 million, respectively, before income taxes ($2.4 million, $2.3 million and $0.9 million, respectively, net of income taxes), was amortized to the Consolidated Statements of Operations.
During 2002, AE Supply recognized a net unrealized loss of $2.6 million related to derivative instruments associated with the delivery of electricity that did not qualify for the normal purchase and normal sale exception under SFAS No. 133.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Fellon-McCord and Alliance Energy Services-Sold in 2002
On November 1, 2001, Allegheny Ventures acquired Fellon-McCord and Alliance Energy Services, which were both subsequently sold in December 2002. Alliance Energy Services was engaged in the purchase, sale and marketing of natural gas and other energy-related services to various commercial and industrial customers across the United States. Alliance Energy Services, on behalf of its customers, used both physical and financial derivative contracts, including forwards, NYMEX futures, options and swaps, in order to minimize market risk associated with its purchase and sales activities. These derivative contracts were accounted for as cash flow hedges. For 2002, an unrealized gain of $31.2 million, net of reclassifications to earnings, income taxes and minority interest, was recorded to other comprehensive income (loss) for these contracts. For 2001, an unrealized loss of $18.9 million, net of reclassifications to earnings and income taxes, was recorded to other comprehensive income (loss) for these contracts. These hedges were highly effective during 2002 and 2001.
NOTE 11: ASSET RETIREMENT OBLIGATIONS (“ARO”)
Effective January 1, 2003, Allegheny adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”) which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS No. 143 requires that the fair value of asset retirement costs for which Allegheny has a legal obligation be recorded as liabilities, with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if it is settled at a different amount.
Allegheny recorded retirement obligations primarily related to ash landfills, underground and aboveground storage tanks and natural gas wells. Allegheny also has identified a number of retirement obligations associated with certain of its electric generation and transmission assets that have not been recorded, because the fair value of such obligations cannot be reasonably estimated, due primarily to the indeterminate lives of the assets.
The effect of adopting SFAS No. 143 on Allegheny’s Consolidated Financial Statements in 2003 was as follows:
AROs were identified with respect to property, plant and equipment at Monongahela, and the cost of removal for these assets currently is being recovered through rates. Allegheny believes it is probable that any difference between expenses under SFAS No. 143 and expenses recovered currently in rates with respect to these assets will be recoverable in future rates. Therefore, Allegheny is deferring these expenses as a regulatory asset.
For the year ended December 31, 2004, Allegheny’s ARO balance increased $6.3 million, from $22.5 million at January 1, 2004, to $28.8 million at December 31, 2004, due primarily to a $5.4 million liability recorded for the Harrison generation station ash disposal site extension Phase IV and accretion expense. For the year ended December 31, 2003, Allegheny’s ARO balance increased $2.8 million due to accretion expense.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Costs of removal that do not have associated retirement obligations were recorded in accumulated depreciation in previous years. However, in February 2004, the Securities and Exchange Commission’s (“SEC”) Accounting Staff indicated in a public comment release that these removal costs should be included in regulatory liabilities for all periods presented. As of December 31, 2003, Allegheny’s regulated utility subsidiaries began recording the removal costs collected from customers related to assets that do not have associated retirement obligations under SFAS No. 143 in “Regulatory assets,” “Regulatory liabilities” and/or “Other current liabilities” on its Consolidated Balance Sheets. These estimated removal costs, which represent a regulatory liability (asset), are as follows:
Had the provisions of SFAS No. 143 been adopted on January 1, 2001, Allegheny’s reported loss before cumulative effect of accounting change, net loss and loss per share for 2002, would not have been materially different.
Had the provisions of SFAS No. 143 been adopted on January 1, 2001, Allegheny’s AROs would have been $17.2 million at December 31, 2001 and $19.7 million at December 31, 2002.
NOTE 12: BUSINESS SEGMENTS
Allegheny manages and evaluates its operations in two business segments: 1) Delivery and Services and 2) Generation and Marketing.
The Delivery and Services segment includes Allegheny’s electric and natural gas T&D operations. This segment also includes the results of Allegheny Ventures.
The Generation and Marketing segment includes Allegheny’s power generation operations. This segment owns, operates and manages regulated and unregulated electric generation capacity. For 2002 and 2003, until it was able to exit from most of its speculative energy trading positions, this segment also marketed and traded electricity, natural gas, oil, coal and other energy-related commodities using primarily over-the-counter and exchange-traded contracts.
Allegheny accounts for intersegment sales based on cost or regulatory commission-approved tariffs or contracts. AE and certain of its subsidiaries entered into agreements to sell, or made the decision to sell, certain non-core assets during the third quarter of 2004. See Note 4, “Assets Held for Sale and Discontinued Operations,” for additional information concerning the segments in which the results of operations for these assets have previously been reported. The results of operations for these assets for 2004, 2003 and 2002 have been reclassified to discontinued operations.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Business segment information is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts. The majority of the eliminations relate to power sold by the Generation and Marketing segment to the Distribution Companies.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 13: DIVIDEND RESTRICTION
The Board of Directors of AE did not declare a dividend on AE’s common stock during 2004 or 2003. Covenants contained in AE’s borrowing agreements, as well as regulatory limitations under PUHCA, preclude AE from declaring or paying cash dividends for the foreseeable future. See Note 3, “Capitalization,” for additional information.
NOTE 14: ACCOUNTING FOR THE EFFECTS OF PRICE REGULATION
Deregulation
On May 29, 1998, the Pennsylvania Public Utility Commission (“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 on November 19, 1998. West Penn recorded an extraordinary charge under the provisions of SFAS No. 101, “Regulated Enterprises-Accounting for the Discontinuation of Application of FASB Statement No. 71,” in 1998 to reflect the disallowances of certain costs in the order. This charge included an estimated amount for an adverse power purchase commitment, which reflects a commitment to purchase power at above-market prices. The adverse power purchase commitment is amortized over the life of the commitment based on a schedule of estimated electricity purchases established in connection with the settlement agreement. As of December 31, 2004, Allegheny’s reserve for adverse power purchase commitments was $218.1 million.
Based on the forecast mentioned above, Allegheny’s reserve for adverse power purchase commitments decreased as follows for 2004, 2003 and 2002:
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 Operations.
Reregulation
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. This plan was approved, but never implemented, by the legislature. In 2002, the West Virginia PSC issued orders dismissing deregulation proceedings. Based on these actions, Monongahela concluded that retail competition and the deregulation of generation assets is no longer probable and that the generation operations in West Virginia meet the requirements of SFAS No. 71.
Monongahela reapplied the provisions of SFAS No. 71 to its West Virginia generation assets in the first quarter of 2003 and recorded a gain of $61.7 million as part of “Other income and expenses, net” in the Consolidated Statements of Operations. This gain was primarily the result of the elimination of its transition obligation and the reestablishment of regulatory assets related to deferred income taxes.
Potomac Edison had recorded a transition obligation on its books associated with West Virginia deregulation. Potomac Edison also reapplied the provisions of SFAS No. 71 in the first quarter of 2003 and recognized a gain of approximately $14.1 million as a result of the elimination of its transition obligation. This gain is also a component of “Other income and expenses, net” in the Consolidated Statements of Operations.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
As of December 31, 2002, Allegheny had no generation assets subject to SFAS No. 71. As a result of the reapplication of SFAS No. 71 to the West Virginia generation assets in January 2003, the Consolidated Balance Sheets include the amounts listed below for generation assets not subject to SFAS No. 71 as of December 31, 2004 and 2003:
NOTE 15: INCOME TAXES
Details of federal and state income tax expense (benefit) from continuing operations are:
The total income tax expense (benefit) from continuing operations differs from the amount produced by applying the federal statutory income tax rate of 35% to financial accounting income, as set forth below:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The income tax benefit for loss from discontinued operations differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount as set forth below:
The income tax benefit for the cumulative effect of accounting changes differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount, as set forth below:
At December 31, the deferred income tax assets and liabilities consisted of the following:
Allegheny recorded as deferred income tax assets the effect of net operating losses, which will more likely than not be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2024.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 16: SHORT-TERM DEBT
No short-term debt was outstanding at December 31, 2004. The $53.6 million of short-term debt outstanding at December 31, 2003 was related to a bridge loan at Monongahela that was issued in September of 2003, had a term of 364 days and was repaid in June 2004 with a portion of the proceeds from the issuance of Monongahela’s first mortgage bonds.
To provide interim financing and support for outstanding commercial paper, lines of credit had been established with several banks. AE and certain of its subsidiaries had fee arrangements on all of their lines of credit and no compensating balance requirements. These facilities, which were refinanced in February 2003, required the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio, as defined under the applicable credit agreements. On October 8, 2002, Allegheny announced that AE, AE Supply and AGC were in technical default under these facilities after AE Supply declined to post additional collateral in favor of several trading counterparties. As of December 31, 2003, Allegheny had obtained waivers and amendments for these facilities. See Note 3, “Capitalization,” for additional details regarding the Borrowing Facilities that were entered into in February 2003.
Short-term debt outstanding for 2004 and 2003 consisted of:
NOTE 17: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Substantially all of Allegheny’s employees, including officers, are employed by AESC and are covered by noncontributory, defined benefit pension plans. Benefits are based on each employee’s years of service and compensation. Allegheny makes annual contributions of the minimum amount required under ERISA and not more than can be deducted for federal income tax purposes. For reporting purposes, the measurement date is September 30.
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, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993, with the exception of certain union employees. The postretirement health care plans include a limit on the company’s share of costs for recent and future retirees.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The components of the net periodic benefit cost for pension benefits and for postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents and the allocation by Allegheny, through AESC, of costs for pension benefits and postretirement benefits other than pensions were as follows:
Approximately 20% and 13% of the above net periodic cost amounts were allocated to “Construction work in progress,” a component of “Property, plant and equipment, net” in 2004 and 2003, respectively.
As discussed in Note 4, “Assets Held for Sale and Discontinued Operations,” Monongahela entered into an agreement in August 2004 to sell its West Virginia natural gas operations. Included in the net periodic cost for 2004 are $2.7 million and $3.4 million of curtailment charges for pension and postretirement benefits other than pensions, respectively.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The amounts accrued at December 31, using a measurement date of September 30, included the following components:
The postretirement benefits other than pensions unrecognized transition obligation is being amortized over 20 years, beginning January 1, 1993.
As the Supplemental Executive Retirement Plan (“SERP”) is a non-qualified pension plan, Allegheny is not obligated to fund the SERP obligation. The SERP obligation, which is included as a component of the pension benefit obligation, was $7.0 million and $11.0 million at December 31, 2004 and 2003, respectively. The amount of SERP included in the accrued pension benefits at December 31, 2004 and 2003 was an (accrued) prepaid benefit of $(2.5) million and $0.9 million, respectively.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Amounts included in the Consolidated Balance Sheets were as follows:
The accumulated benefit obligation for all defined benefit pension plans was $997.2 million and $949.6 million at December 31, 2004 and 2003, respectively. The portion of the total accumulated benefit obligation related to the SERP was $6.6 million and $9.5 million at December 31, 2004 and 2003, respectively.
Information for pension plans with a projected benefit obligation and an accumulated benefit obligation in excess of plan assets is as follows:
The assumptions used to determine net periodic benefit costs for years ended December 31, 2004, 2003 and 2002 are shown in the table below. The discount rates, expected long-term rates of return on plan assets and rates of compensation increases used in determining net periodic benefit costs were as follows:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The assumptions used to determine benefit obligations at September 30, 2004, 2003 and 2002 and the expected long-term rates of return on plan assets in each of the years 2004, 2003 and 2002 are shown in the table below:
Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs for 2005 is 8.5%.
Assumed health care cost trend rates at December 31 are as follows:
For measuring obligations related to postretirement benefits other than pensions, Allegheny assumed a health care cost trend rate of 9.5% beginning with 2005 and grading down by 0.5% each year to an ultimate rate of 5.0%, 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:
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Medicare Act”) became law. Beginning in 2006, the federal government will provide subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. Allegheny elected to follow the deferral provisions of FASB Staff Position (“FSP”) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-1”). FSP 106-1 permits employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until guidance on the accounting for the federal subsidy is issued. On May 19, 2004, FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”), which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Plan Assets
Allegheny’s pension plans’ asset allocations as of the measurement dates of September 30, 2004 and 2003, by asset category are as follows:
Allegheny’s postretirement benefits other than pensions asset allocations as of the measurement dates of September 30, 2004 and 2003, by asset category are as follows:
The investment policy of the defined benefit pension plan is to invest in assets with a long-term asset allocation objective of 40% equity securities and 60% fixed income securities. The investment policy of the postretirement benefits other than pensions is to invest in assets with a long-term asset allocation objective of 50% equity securities and 50% fixed income securities. The strategic asset allocation represents a long-term perspective. Under the plans investment policy, this allocation may vary, in the short-term, from the stated objective. 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.
Contributions
Allegheny contributed approximately $27.7 million to its pension plans in 2004, including a voluntary contribution of $0.3 million to the SERP. Allegheny also contributed $28.1 million to its postretirement benefits other than pensions in 2004. Allegheny currently anticipates contributing approximately $58.0 million to its pension plans in 2005, including $0.3 million to the SERP. Allegheny also currently anticipates contributing an additional amount in 2005 ranging from $27.0 million to $32.0 million, to fund postretirement benefits other than pensions. Allegheny makes contributions to its pension plan in order to meet the minimum required funding amount under ERISA. These anticipated contributions will change in the future if Allegheny’s assumptions regarding prevailing interest rates change, if actual investments under-perform or out-perform expectations or if actuarial assumptions or asset valuation methods change.
401(k) Savings Plan
Allegheny maintains a 401(k) Employee Stock Ownership and Savings Plan (the “ESOSP”). The ESOSP was established as a non-contributory stock ownership plan for all eligible employees, effective January 1, 1976,
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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 can elect to have from 2% to 12% of his or her compensation contributed to the ESOSP on a pre-tax basis, and an additional 1% to 6% on a post-tax basis. Participants direct the investment of contributions to specified mutual funds or AE common stock. Allegheny matches 50% of pre-tax contributions, up to 6% of an employee’s compensation. Allegheny made these matching contributions by issuing shares of common stock of AE for the periods January 1, 2002 through June 30, 2003 and since April 1, 2004. AE purchased shares in the open market to make these matching contributions for the period July 1, 2003 through the first quarter of 2004. AE issued 363,361 shares, 399,914 shares and 573,664 shares of AE common stock as matching contributions for 2004, 2003 and 2002, respectively. Allegheny recorded expense for these contributions of $6.0 million, $2.5 million and $8.8 million for 2004, 2003 and 2002, respectively. Allegheny purchased 129,308 and 544,490 shares in open market transactions in 2004 and 2003, respectively, to fund the matching contribution. Allegheny also recorded expense for the matching contributions made in open market transactions in 2004 and 2003 of $1.7 million and $5.3 million, respectively.
Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are estimated to be paid as follows:
NOTE 18: STOCK-BASED COMPENSATION
Under Allegheny’s 1998 Long-Term Incentive Plan (the “LTIP”), stock options, restricted shares and performance awards may be granted to officers and key employees. Ten million shares of Allegheny’s common stock have been authorized for issuance under the LTIP, subject to adjustments for changes in Allegheny’s common shares. The LTIP provides vesting periods of one to five years, with options terminating 10 years after the date of grant. Options are granted at the quoted market price of Allegheny’s common shares on the date of grant. There were 1,609,193 exercisable options at December 31, 2004.
Under the LTIP, Allegheny may grant awards of restricted shares of common stock on terms, conditions and restrictions as it may determine, based on performance standards, periods of service, share ownership or other criteria.
Allegheny may also grant performance awards under the LTIP which consist of a right to receive a payment that is either measured by the fair market value of a certain number of shares of its common stock, increases in the fair market value of its common stock during an award period and/or a fixed cash amount. Performance awards may be made in connection with, or in addition to, restricted stock awards. Award periods will be two or more years or annual periods as may be determined.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In February 2004, Allegheny granted approximately 3.4 million stock units pursuant to agreements with certain executives. Stock units vest annually over a period of three to five years. Each unit entitles the holder to one share of AE common stock on the vesting date, subject to an election to defer receipt. The weighted average grant date fair value of the 2004 stock units was $13.37 per share. Approximately 390,000 stock units were cancelled during 2004 as a result of the resignation of an executive. For the years ended December 31, 2004 and 2003, compensation expense of $18.7 million and $10.6 million, respectively, was recorded for these stock units.
The weighted average fair values of the 2004 and 2002 options were $7.18 and $7.81 per share, respectively. There were no stock options granted during 2003. The fair values were estimated at the date of grant using the Black-Scholes option-pricing model, with the following weighted average assumptions:
The following table summarizes the status of the stock options granted under the LTIP as of December 31, 2004:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The following table summarizes the stock options outstanding at December 31, 2004:
During 2004, Allegheny adopted a Non-Employee Director Stock Plan, under which each non-employee director receives, subject to the director’s election to defer his or her receipt, up to 1,000 shares of AE’s common stock for services performed during a calendar quarter. AE’s Board of Directors set the 2004 quarterly compensation of each non-employee director at 800 shares of AE’s common stock. 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. During 2004, AE issued 14,400 shares under this plan, and the directors deferred an additional 11,200 shares pursuant to the terms of the plan. During 2004, Allegheny recognized $0.4 million of expense for this plan.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 19: RECONCILIATION OF BASIC AND DILUTED SHARES
The following table provides a reconciliation of the numerators and the denominators for the basic and diluted per share computations:
*
The table below shows the following anti-dilutive shares not included above:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 20: REGULATORY ASSETS AND LIABILITIES
Certain of Allegheny’s regulated operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:
Income Taxes, Net
In certain jurisdictions, deferred income tax expense is not permitted as a cost in the determination of rates charged to customers. In these jurisdictions a deferred income tax liability is recorded with an offsetting regulatory asset. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. These deferred income taxes relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. No return is allowed on the regulatory asset for income taxes.
Pennsylvania Stranded Cost Recovery
In 1998, Allegheny recorded a regulatory asset for Pennsylvania stranded cost recovery, representing the portion of transition costs determined by the Pennsylvania PUC to be recoverable by West Penn under its deregulation plan. The CTC regulatory asset is being recovered over the transition period that will end in 2008. CTC rates include return on, as well as recovery of, transition costs.
Pennsylvania CTC Reconciliation
The Pennsylvania PUC authorized West Penn to defer the difference between authorized and billed CTC revenues, with an 11% return on the deferred amounts, for future full and complete recovery. The amount of under-recovery of CTC during the transition period, if any, will be determined at the end of the transition period, which extends through 2008. On an annual basis, the Pennsylvania PUC has approved the amount of CTC reconciliation recorded as a regulatory asset by Allegheny.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
See Note 14, “Accounting for the Effects of Price Regulation,” for a discussion regarding Monongahela and Potomac Edison’s reapplication of the provisions of SFAS No. 71 to their West Virginia generation assets in the first quarter of 2003.
See Note 11, “Asset Retirement Obligations,” for a discussion of a regulatory liability identified in conjunction with the application of a new accounting pronouncement.
NOTE 21: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year and preferred stock of a subsidiary, at December 31, were as follows:
The above table excludes long-term debt with a carrying amount of $86.7 million and a fair value of $95.1 million related to liabilities associated with assets held for sale at December 31, 2004.
The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The fair value of preferred stock is based on quoted market prices. The carrying amounts of cash equivalents and short-term debt approximate the fair values of these financial instruments because of the short maturities of those instruments.
NOTE 22: JOINTLY OWNED ELECTRIC UTILITY PLANTS
Certain of AE’s subsidiaries jointly own electric generation facilities. AE’s subsidiaries record their proportionate share of operating costs, assets and liabilities related to these generation facilities in the corresponding lines in the Consolidated Financial Statements.
In addition, AGC jointly owns the Bath County generation station with a non-affiliated third party. AGC’s investment and accumulated depreciation in the Bath County generation station jointly owned with a third party, at December 31 were as follows:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 23: OTHER INCOME AND EXPENSES, NET
Other income and expenses, net represent non-operating income and expenses before income taxes. The following table summarizes Allegheny’s other income and expenses, net, for 2004, 2003 and 2002:
NOTE 24: QUARTERLY FINANCIAL INFORMATION (Unaudited)
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(1)
Results for the first quarter of 2003 include a cumulative effect of accounting changes for the adoption of SFAS No. 143 and EITF 02-3
(2)
Amounts may not total to year to date results.
NOTE 25: GUARANTEES AND LETTERS OF CREDIT
Guarantees
At December 31, 2004, Allegheny and its subsidiaries provided guarantees, either directly or indirectly, of $27.3 million for contractual obligations of affiliated companies. Allegheny does not carry any amounts as liabilities on its Consolidated Balance Sheets for its obligations with respect to $18.2 million of the $27.3 million in guarantees. This does not include approximately $11.7 million of aggregate letters of credit discussed below. Under the terms of the guarantees, Allegheny would be required to perform should an affiliate be in default of its obligation, generally for an amount not to exceed the amount of the guarantee. The terms of these guarantees coincide with the terms of the underlying agreements.
Of the $18.2 million in guarantees for which liabilities are not recorded, approximately $3.6 million relates to guarantees associated with the purchase, sale, exchange or transportation of wholesale natural gas, electric power and related services, $9.9 million relates to loans and other financing related guarantees and $4.7 million relates to a lease agreement that was signed in 2001.
Effective January 1, 2003, Allegheny began recording, as liabilities at their fair value, all guarantees issued or modified after that date. As of December 31, 2004, Allegheny’s Consolidated Balance Sheet reflected liabilities for $9.1 million of the total $27.3 million in outstanding guarantees. The $9.1 million in guarantees recorded as liabilities were issued by AE Supply in connection with the sale of the CDWR contract and related hedge transactions and the performance of a put option issued in connection with an asset sale.
Letters of Credit
The New AE Facility includes a $200 million revolving credit sub-facility, of which $100 million is available for the issuance of letters of credit. Allegheny incurs fees associated with letters of credit comprised of a fronting fee of 0.35% and an additional annual fee of 2.5% to 3.0% on the face amount of outstanding letters of credit, depending on AE’s then current credit rating as provided by S&P and Moody’s. There were $11.5 million of outstanding letters of credit drawn against the revolving credit facility at December 31, 2004.
AE has one letter of credit outstanding under the New AE Facility for $2.0 million, which expires in September 2005. Potomac Edison has two letters of credit outstanding for an aggregate amount of approximately $9.7 million. Of this amount, $9.5 million was issued under the New AE Facility to support an energy conservation contract. This letter of credit expires in July 2005. The remaining $0.2 million represents a letter of credit issued by a bank that is not a lender under the New AE Facility to support a property purchase. This letter of credit, which was not collateralized, expired in the first quarter of 2005. AE Supply, Monongahela and AGC did not have any letters of credit outstanding as of December 31, 2004.
AE Supply’s $13.9 million of letters of credit outstanding at September 30, 2004 were released during the fourth quarter as a result of reduced exposure related to an interest rate swap and the sale of the Lincoln Generation Facility.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 26: VARIABLE INTEREST ENTITIES
Allegheny adopted FASB’s Interpretation No. 46 (Revised December 2003) “Consolidation of Variable Interest Entities” (“FIN 46R”), as of March 31, 2004. FIN 46R requires Allegheny to consolidate entities or contracts that represent a variable interest in a variable interest entity (“VIE”) if Allegheny is determined to be the primary beneficiary of the VIE.
Under FIN 46R, Allegheny consolidated Hunlock Creek Energy Ventures, LLC (“Hunlock Creek”) as of March 31, 2004. This entity operates two plants that produce and sell electricity to Allegheny and a third party. The consolidation resulted in an increase in total assets as of March 31, 2004 of $16.5 million. Consolidation of this entity had no impact on Allegheny’s net income or stockholders’ equity.
West Penn and Potomac Edison each has a long-term electricity purchase contract with an unrelated independent power producer (“IPP”) that represents a variable interest under FIN 46R. Allegheny continues to pursue, but has been unable to obtain, certain information from the IPPs necessary to determine if the related VIEs should be consolidated under FIN 46R.
West Penn and Potomac Edison purchased power for 2004 from these two IPPs in the amount of $47.3 million and $93.6 million, respectively. West Penn recovers a portion, and Potomac Edison recovers the full amount, of the cost of the applicable power contract in their rates charged to consumers. Neither West Penn nor Potomac Edison is subject to any risk of loss associated with the applicable VIE, because neither of them has any obligation to the applicable IPP other than to purchase the power that the VIE produces according to the terms of the applicable electricity purchase contract.
NOTE 27: COMMITMENTS AND CONTINGENCIES
Construction and Capital Program
The subsidiaries have entered into commitments for their capital programs for which expenditures are estimated to be $291.2 million for 2005 and $378.5 million for 2006. Capital expenditure levels in 2006 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. See “Environmental Matters and Litigation-Clean Air Act Matters” below.
Environmental Matters and Litigation
Allegheny is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Allegheny to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.
Clean Air Act Matters: Allegheny currently meets applicable standards for particulate matter emissions at its generation stations through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and emission allowances and, at times, through reduction of output. From time to time, minor excursions of stack emission opacity that are normal to fossil fuel operations are experienced and accommodated by the regulatory process.
Allegheny meets current emission standards for sulfur dioxide (“SO2”) by using scrubbers, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and using emission allowances.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Allegheny’s compliance with the Clean Air Act of 1970 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install of expensive post-combustion control technologies on many of its generation stations.
The Clean Air Act mandates annual reductions of SO2 and created a SO2 emission allowance trading program. AE Supply and Monongahela comply with current SO2 emission standards through a system-wide plan combining the use of emission controls, low sulfur fuel and emission allowances. Allegheny continues to study the use of allowances, additional emission controls and low sulfur fuel to meet future SO2 compliance obligations. Allegheny estimates that it may purchase allowances for up to 50,000 tons for 2005 and an average of approximately 100,000 tons per year for 2006 through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the type of fuel used by its generation facilities. Allegheny currently expects that its plan to increase its use of lower sulfur coal and implement other environmental control improvements should reduce allowance purchase requirements over this time period.
In 1998, the EPA finalized its Nitrogen Oxide (“NOx”) State Implementation Plan (“SIP”) call rule (known as the “NOx SIP call”), which addressed the regional transport of ground-level ozone and required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Pennsylvania, Maryland and West Virginia. Compliance with the NOx SIP call was required beginning in May 2004. Pennsylvania and Maryland implemented their respective SIP call rules in May 2003. West Virginia’s SIP call rules were effective as of May 2004.
AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. These NOx controls include selective catalytic reduction at the Harrison and Pleasants generation stations and selective noncatalytic reduction at the Hatfield’s Ferry and Fort Martin generation stations, as well as burner modifications at Mitchell generation station. The NOx compliance plan functions on a system-wide basis, similar to the SO2 compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. AE Supply estimates that its emission control activities, in concert with its inventory of banked allowances, will facilitate its compliance with NOx limits established by the SIP through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the type of fuel used by its generation facilities. Allegheny’s capital expenditure forecast includes the expenditure of $4.7 million of capital costs during the 2005 through 2007 period for NOx emission controls.
In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation stations, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these generation stations. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the New Source Review (“NSR”) standards of the Clean Air Act, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. AE provided responsive information to this and a subsequent request. A meeting between the EPA and AE was held on July 16, 2003. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues.
Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings in most cases. AE believes that its subsidiaries’ generation facilities have been operated in accordance with the Clean Air Act and the rules implementing it. The experience of other energy companies, however, suggests that,
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
in recent years, the EPA has narrowed its view regarding the scope of the definition of “routine maintenance” under its rules, thereby broadening the range of actions subject to compliance with NSR standards. Section 114 information requests concerning facility modifications are often followed by enforcement actions.
If NSR standards are applied to Allegheny’s generation stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. There are two federal district court decisions interpreting the application of NSR standards to utilities, the Ohio Edison decision and the Duke Energy decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy decision supports the industry’s understanding of NSR requirements. The final Routine Maintenance, Repair and Replacement Rule (“RMRR”) released by the EPA is more consistent with the energy industry’s historical compliance approach. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the RMRR, which was scheduled to go into effect on December 26, 2003. The stay delays implementation of the RMRR. At this time, AE and its subsidiaries are not able to determine the effect that these actions may have on them.
On February 2, 2004, the EPA informed AE that it intended to provide the New York Attorney General, pursuant to his request, certain records that AE provided to the EPA pursuant to its request under Section 114 of the Clean Air Act. On April 23, 2004, the Pennsylvania Department of Environmental Protection (“PADEP”) notified AE Supply that the PADEP had requested that the EPA provide it with these records.
On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from PADEP. The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2 and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation stations in Pennsylvania and identifies PADEP as the lead agency regarding those facilities. On September 8, 2004, AE, AE Supply, Monongahela and West Penn received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal district court in West Virginia on January 6, 2005. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation facilities in Pennsylvania and West Virginia are in compliance with the Clean Air Act. The Attorneys General filed a motion to dismiss the declaratory judgment action. If the action is dismissed based upon the their motion, the Attorneys General may file an enforcement action against Allegheny in federal court in Pennsylvania. It is also possible that the EPA and other state authorities may join in the current declaratory judgment action or, if it is dismissed, a new action filed by the Attorneys General.
On February 16, 2005, Citizens for Pennsylvania’s Future, an environmental group, sued Allegheny in the U.S. District Court for the Western District of Pennsylvania. The action alleges violations of operating limits and particulate matter emission limits at the Hatfield’s Ferry generation facility.
Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.
Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”) Claim: On March 4, 1994, Monongahela and certain affiliated companies received notice that the EPA had identified them as potentially responsible parties (“PRPs”) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site. Initially, approximately 175 PRPs were involved, however, the current number of active PRPs has been reduced as a result of settlements with de minimis contributors and other contributors to the site. The
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
costs of remediation will be shared by all past and active responsible parties. In 1999, a PRP group that included Monongahela and certain affiliated companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30.0 million. Monongahela has an accrued liability representing its estimated share of the remediation costs as of December 31, 2004.
Claims Related to Alleged Asbestos Exposure: The Distribution Companies have been named as defendants, along with multiple other defendants, in pending asbestos cases alleging bodily injury involving multiple plaintiffs and multiple sites. These suits have been brought mostly by seasonal contractors’ employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from these historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W.Va.). The parties in these actions are seeking an allocation of responsibility for historic and potential future asbestos liability.
During the pendency of these actions, Allegheny will continue to receive payments from one of its insurance companies in the amount of $625,000, payable on each of July 1, 2005 and 2006. During 2004 and 2003, Allegheny received insurance recoveries of approximately $960,000 and $1.8 million, respectively, in connection with these cases. Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2004, Allegheny had 1,504 open cases remaining. Allegheny intends to vigorously defend against these actions but cannot predict their outcomes.
Other Litigation
Putative Class Actions Under California Statutes: Eight related putative class action lawsuits were filed against and served on AE Supply and more than two dozen other named defendant power suppliers in various California superior courts during 2002. These class action suits were removed from state court and transferred to the U.S. District Court for the Southern District of California. Seven of the suits were commenced by consumers of wholesale electricity in California. The eighth, Millar v. Allegheny Energy Supply Co., et al., was filed on behalf of California consumers and taxpayers. The complaints allege, among other things, that AE Supply and the other defendant power suppliers violated California’s antitrust statute and the California unfair business practices statutes by manipulating the California electricity market. The suits also challenge the validity of various long-term power contracts with the State of California, including the CDWR contract.
On August 25, 2003, the U.S. District Court granted AE Supply’s motion to dismiss the seven consumer class actions with prejudice. On February 25, 2005, the United States Court of Appeals for the Ninth Circuit affirmed the District Court’s judgment dismissing the seven class actions with prejudice.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The District Court separately granted plaintiffs’ motion to remand in the eighth action, Millar, on July 9, 2003. On December 18, 2003, the plaintiffs filed an amended complaint in California state court, solely on behalf of consumers, naming certain additional defendants, including The Goldman Sachs Group, Inc. (“Goldman Sachs”). The case was removed to federal court based on the amended complaint. On January 11, 2005, the federal district court remanded the case back to the state court.
Under the terms of the agreement relating to the sale of the CDWR contract, AE Supply and one of its affiliates have agreed to indemnify Goldman Sachs and its affiliate J. Aron & Company, under certain conditions, for any losses arising out of the class action litigation up to the amount of the purchase price. AE Supply issued a guarantee to J. Aron & Company in connection with this indemnification obligation.
AE Supply intends to vigorously defend against these actions but cannot predict their outcomes.
Nevada Power Contracts: On December 7, 2001, Nevada Power Company (“NPC”) filed a complaint with FERC against AE Supply seeking FERC action to modify prices payable to AE Supply under three trade confirmations between Merrill Lynch and NPC. NPC’s claim was based, in part, on the assertion that dysfunctional California spot markets had an adverse effect on the prices NPC was able to negotiate with Merrill Lynch under the contracts. NPC filed substantially identical complaints against a number of other energy suppliers. On December 19, 2002, the Administrative Law Judge (“ALJ”) issued findings that no contract modification was warranted. The ALJ determined in favor of NPC that AE Supply, rather than Merrill Lynch, was a proper subject of NPC’s complaint.
On June 26, 2003, FERC affirmed the ALJ’s decision upholding the long-term contracts negotiated between NPC and Merrill Lynch, among others, and did not render a decision on whether AE Supply, rather than Merrill Lynch, was the real party in interest. On November 10, 2003, FERC issued an order, on rehearing, affirming its conclusion that the long-term contracts should not be modified. Snohomish County and other parties filed petitions for review of FERC’s June 26, 2003 order with the U.S. Court of Appeals for the Ninth Circuit (the “NPC Petitions”). On December 17, 2003, AE Supply filed a motion to intervene in this proceeding in the Ninth Circuit. The Ninth Circuit heard oral argument in these cases on December 8, 2004. The NPC Petitions were consolidated in the Ninth Circuit. AE Supply intends to vigorously defend against these actions but cannot predict their outcomes.
Sierra/Nevada: On April 2, 2003, NPC and Sierra Pacific Resources, Inc. (together, “Sierra/Nevada”) initiated a lawsuit in U.S. District Court in Nevada against AE and AE Supply, together with Merrill Lynch & Co. and Merrill Lynch Capital Services, Inc. (together, “Merrill”). The complaint alleged that AE, AE Supply and Merrill engaged in fraudulent conduct in connection with NPC’s application to the Public Utilities Commission of Nevada (“The Nevada PUC”) for a deferred energy accounting adjustment, which allegedly caused the Nevada PUC to disallow $180 million of NPC’s deferred energy expenses. Sierra/Nevada asserted claims against AE and AE Supply for: (1) tortious interference with Sierra/Nevada’s contractual and prospective economic advantages; (2) conspiracy and (3) violations of the Nevada state Racketeer Influenced and Corrupt Organization (“RICO”) Act. Sierra/Nevada filed an amended complaint on May 30, 2003, which asserted a fourth cause of action against AE and AE Supply for wrongful hiring and supervision. Sierra/Nevada seeks $180 million in compensatory damages plus attorneys’ fees and seeks in excess of $850 million under the RICO count. AE and AE Supply filed motions to dismiss the complaints on May 6, 2003 and June 23, 2003. AE Supply intends to vigorously defend against this action but cannot predict its outcome.
Litigation Involving Merrill Lynch: AE and AE Supply entered into an asset purchase agreement with Merrill Lynch and affiliated parties in 2001, under which AE and AE Supply purchased Merrill Lynch’s energy marketing and trading business for approximately $489 million and an equity interest in AE Supply of nearly 2%.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The asset purchase agreement provided that Merrill Lynch would have the right to require AE to purchase Merrill Lynch’s equity interest in AE Supply for $115 million plus interest calculated from March 16, 2001 in the event that certain conditions were not met.
On September 24, 2002, certain Merrill Lynch entities filed a complaint against AE in the U.S. District Court for the Southern District of New York, alleging that AE breached the asset purchase agreement by failing to repurchase the equity interest in AE Supply from Merrill Lynch and seeking damages in excess of $125 million. On September 25, 2002, AE and AE Supply filed an action against Merrill Lynch in New York state court. The complaint in that action alleged that Merrill Lynch fraudulently induced AE to enter into the purchase agreement and that Merrill Lynch breached certain representations and warranties contained in the agreement.
On May 29, 2003, the U.S. District Court for the Southern District of New York denied AE’s motion to stay Merrill Lynch’s action and ordered that AE and AE Supply assert their claims against Merrill Lynch, which were initially brought in New York state court, as counterclaims in Merrill Lynch’s federal court action. As a result, AE and AE Supply dismissed the New York state action and filed an answer and asserted affirmative defenses and counterclaims against Merrill Lynch in the U.S. District Court for the Southern District of New York. The counterclaims, as amended, allege that Merrill Lynch fraudulently induced AE and AE Supply to enter into the purchase agreement, that Merrill Lynch breached certain representations and warranties contained in the purchase agreement, that Merrill Lynch negligently misrepresented certain facts relating to the purchase agreement and that Merrill Lynch breached fiduciary duties owed to AE and AE Supply. The counterclaims seek damages in excess of $605 million, among other relief.
On November 24, 2003, the court dismissed AE and AE Supply’s counterclaim for rescission and struck their demand for a jury trial. AE and AE Supply’s counterclaims for fraudulent inducement, breach of contract, negligent misrepresentation, breach of fiduciary duty and their request for punitive damages with respect to certain counterclaims remains in place.
On February 2, 2005, the parties filed separate motions for summary judgment, which were opposed and have been fully briefed. The trial has been scheduled for May 2005.
The federal government is holding certain assets of Daniel L. Gordon, the former head of energy trading for AE Supply. Both AE and Merrill Lynch have filed petitions with the U.S. District Court for the Southern District of New York claiming rights to the funds. On August 13, 2004, the U.S. Attorney filed a motion to dismiss the petitions filed by AE and Merrill Lynch on the grounds that neither AE nor Merrill Lynch had an interest in the specific property seized by the government at the time Gordon committed his offense. On September 30, 2004, AE filed an opposition to the government’s motion to dismiss.
AE and AE Supply intend to vigorously pursue these matters but cannot predict their outcomes.
Putative Shareholder, Benefit Plan Class Actions and Derivative Action: From October 2002 through December 2002, plaintiffs claiming to represent purchasers of AE’s securities filed 14 putative class action lawsuits against AE and several of its former senior managers in U.S. District Courts for the Southern District of New York and the District of Maryland. The complaints alleged that AE and senior management violated federal securities laws when AE purchased Merrill Lynch’s energy marketing and trading business with the knowledge that the business was built on illegal wash or round-trip trades with Enron, which the complaints alleged artificially inflated trading revenue, volume and growth. The complaints asserted that AE’s fortunes fell when Enron’s collapse exposed what plaintiffs claim were illegal trades in the energy markets. All of the securities cases were transferred to the District of Maryland and consolidated. The plaintiffs filed an amended complaint on May 3, 2004 that alleged that the defendants violated federal securities laws by failing to disclose weaknesses in
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Merrill Lynch’s energy marketing and trading business, as well as other internal control and accounting deficiencies. The amended complaint seeks unspecified compensatory damages and equitable relief. On July 2, 2004, the defendants moved to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding.
In February and March 2003, two putative class action lawsuits were filed against AE in U.S. District Courts for the Southern District of New York and the District of Maryland. The suits alleged that AE and a senior manager violated the Employee Retirement Income Security Act of 1974 (“ERISA”) by: (1) failing to provide complete and accurate information to plan beneficiaries regarding the energy trading business, among other things; (2) failing to diversify plan assets; (3) failing to monitor investment alternatives; (4) failing to avoid conflicts of interest and (5) violating fiduciary duties. The ERISA cases were consolidated in the District of Maryland. On April 26, 2004, the plaintiffs in the ERISA cases filed an amended complaint, adding a number of current and former directors of AE as defendants and clarifying the nature of their claims. On June 25, 2004, the defendants filed a motion to dismiss the amended complaint. Plaintiffs have opposed the motion and it remains outstanding.
In June 2003, a shareholder derivative action was filed against AE’s Board of Directors and several former senior managers in the Supreme Court of the State of New York for the County of New York. The suit alleges that the Board and senior management breached fiduciary duties to AE that have exposed AE to the securities class action lawsuits. The derivative action has been stayed pending the commencement of discovery in the securities cases.
AE intends to vigorously defend against these actions but cannot predict their outcome.
Suits Related to the Gleason Generating Facility: Allegheny Energy Supply Gleason Generating Facility, LLC, a subsidiary of AE Supply, is the defendant in a suit brought in the Circuit Court for Weakley County, Tennessee, by residents living in the vicinity of the generation facility in Gleason, Tennessee. The original suit was filed on September 16, 2002. AE Supply purchased the generation facility in 2001. The plaintiffs are asserting claims based on trespass and/or nuisance, claiming personal injury and property damage as a result of noise from the generation facility. They seek a restraining order with respect to the operation of the plant and damages of $200 million. A mediation session was held on June 17, 2004, but the parties did not reach settlement. AE has undertaken property purchases and other mitigation measures. AE intends to vigorously defend against this action but cannot predict its outcome.
AE Supply has demanded indemnification from Siemens Westinghouse, the manufacturer of the turbines used in the Gleason Generating Facility, pursuant to the terms of the related equipment purchase agreement. On October 17, 2002, Siemens Westinghouse filed a declaratory judgment action in the Court of Common Pleas of Allegheny County, Pennsylvania, against AE Supply and its subsidiary seeking a declaration that the prior owner released Siemens Westinghouse from this liability through a release executed after AE Supply purchased the Gleason facility. On May 6, 2004, AE Supply filed a motion for summary judgment to dismiss the declaratory judgment action. The motion for summary judgment was granted on September 7, 2004. On October 6, 2004, Siemens Westinghouse appealed the dismissal of the declaratory judgment action. Allegheny intends to vigorously defend against this action but cannot predict its outcome.
SEC Matters: On October 9, October 25 and November 5, 2002, AE received subpoenas from the SEC. The subpoenas principally concerned: (1) the departure of Daniel L. Gordon; (2) AE’s litigation with Merrill Lynch; (3) AE Supply’s valuation and management of its trading business; (4) AE’s November 4, 2002 press release concerning its financial statements; (5) the departure of AE’s and its subsidiaries’ Controller, Thomas Kloc, in June 2002 and (6) AE’s acquisition of power plants from Enron. AE and AE Supply responded to the subpoenas.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
On January 16, 2004, the SEC requested that AE voluntarily produce certain documents in connection with an informal investigation of AE, and the SEC has since requested the voluntary production of additional documents. AE has responded to the SEC’s request for documents. The SEC also has taken testimony from several current and former employees and has expressed an intention to take testimony from several additional current and former employees. AE is cooperating fully with the SEC.
EPMI Adversary Proceeding: AE Supply and Enron Power Marketing, Inc. (“EPMI”) were involved in an adversary proceeding, which EPMI filed on May 9, 2003. Following mediation, a settlement was reached resolving all outstanding issues and a settlement agreement was executed and filed with the Bankruptcy Court for its approval. The Bankruptcy Court approved the settlement on December 2, 2004 and dismissed EPMI’s complaint with prejudice on December 16, 2004.
LTI Arbitration: On April 22, 2004, Leasing Technologies International, Inc. and its shareholders (collectively, “LTI”) filed a demand for arbitration against Allegheny Ventures and AE before the American Arbitration Association. In December 2000, Allegheny Ventures entered into an agreement to acquire LTI, an equipment leasing company. Allegheny Ventures terminated the agreement on May 4, 2003. LTI alleges that the termination of the agreement was unjustified and seeks damages in an unspecified amount for breach of the agreement, as well as other consequential damages. On June 11, 2004, AE and Allegheny Ventures filed an answer to LTI’s demand, denying all claims. The arbitration hearing is scheduled to begin on May 16, 2005. Allegheny intends to vigorously defend against these actions, but cannot predict their outcome.
Ordinary Course of Business: The registrants are from time to time involved in litigation and other legal disputes in the ordinary course of business. Each registrant is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.
Leases
Allegheny has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles, computer equipment and communication lines.
Total capital and operating lease rent payments of $28.4 million, $33.6 million and $36.7 million were recorded as rent expense in 2004, 2003 and 2002, respectively, in accordance with SFAS No. 71. Allegheny’s estimated future minimum lease payments for capital and operating leases, including those related to discontinued operations, 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:
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In November 2001, AE Supply entered into an operating lease to finance construction of a 630 MW generation facility in St. Joseph County, Indiana. As of December 31, 2002, AE Supply recorded the facility on its Consolidated Balance Sheet as a result of lessor reimbursement for construction expenditures. As a result, AE Supply recorded approximately $415.5 million of debt related to this obligation, including costs associated with terminating the project, on its Consolidated Balance Sheet at December 31, 2002. In February 2003, AE Supply purchased the project by assuming $380.0 million of the lessor’s long-term debt (the “A-Notes”) and paying an additional $35.5 million. See Note 3, “Capitalization,” for additional information. Following the purchase of the facility, Allegheny terminated the project resulting in a write-off of $192.0 million, before income taxes ($118.4 million, net of income taxes).
In April 2001, AE Supply entered into an operating lease structured to finance the purchase of turbines and transformers. In November 2001, some of the equipment was used for the St. Joseph generation project. In May 2002, AE Supply terminated the lease and the remainder of the equipment was purchased by an unconsolidated joint venture that placed an 88 MW generation facility in southwest Virginia into commercial operation in June 2002.
In November 2000, AE Supply entered into an operating lease to finance construction of a 540 MW generation facility in Springdale, Pennsylvania. In February 2003, AE Supply purchased the facility for $318.4 million financed with debt. See Note 3, “Capitalization,” for additional information. The facility went into commercial operation in July 2003.
PURPA
Under PURPA, electric utility companies, such as Allegheny’s regulated utility subsidiaries, are required to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. The appropriate state public service commission or legislature establishes the rates paid for electric energy purchased from qualifying facilities.
Allegheny’s regulated utilities are committed to purchasing the electrical output from 479 MW of qualifying PURPA capacity. Payments for PURPA capacity and energy in 2004, 2003 and 2002 totaled $198.7 million, $216.8 million and $205.0 million, respectively, before amortization of West Penn’s adverse power purchase commitment. The amount for 2003 excludes a contractually required payment from a hydroelectric facility that supplies power to Monongahela. The average cost of these power purchases was approximately 5.2, 5.6 and 5.6 cents per kilowatt-hour for 2004, 2003 and 2002, respectively.
The table below reflects Allegheny’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2004, by entity. Actual values can vary substantially depending upon future conditions.
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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 consumed in electric generation was $614.4 million, $592.0 million and $576.6 million in 2004, 2003 and 2002, respectively. In 2004, Allegheny purchased approximately 50% of its fuel from one vendor. Total estimated long-term fuel purchase and transportation commitments (primarily coal and lime), excluding commitments related to assets held for sale of $217.0 million, at December 31, 2004, were as follows, by entity and in total:
Southern Mississippi Electric Power Association (“SMEPA”) Agreement
In December 2001, an indirect subsidiary of AE entered into an agreement to provide design, construction and installation services for seven natural gas-fired turbine generators for SMEPA. The seven units, with a combined output of approximately 450 MW, will be located at three sites in southern Mississippi. The units will be owned by SMEPA. Construction started in May 2002, and installation of all of the units is expected to be completed by May 2006. The agreement allows for liquidated damages, for a maximum of $10 million, in the event the indirect subsidiary fails to meet specified delivery dates or the generators fail to meet specified performance requirements.
UGI Put Option
Through its wholly owned subsidiary, AE Supply Hunlock Creek LLC, Allegheny owns a 50% partnership interest in Hunlock Creek. UGI Hunlock Development Company (“UGI”) also owns a 50% interest in Hunlock Creek. Hunlock Creek owns a 48 MW coal-fired generation facility and a 44 MW gas-fired combustion turbine. On March 31, 2004, Allegheny consolidated Hunlock Creek under the provisions of FIN 46R. See Note 26, “Variable Interest Entities,” for additional information.
UGI holds a put option under which it can require AE Supply Hunlock Creek, LLC to purchase its 50% interest in either the coal-fired facility, gas-fired combustion turbine or both. The option can be exercised for a period of 90 days beginning on January 1, 2006.
NOTE 28: 2002 COMPREHENSIVE FINANCIAL REVIEW
During 2002, Allegheny identified certain errors in its financial reporting. In light of this fact and Allegheny’s prior restatements of reports filed with the SEC, Allegheny initiated a comprehensive review of its financial processes, records, and internal controls to ensure that its then current and prior financial statements were fairly presented in accordance with GAAP.
As a result of this accounting review, Allegheny identified, prior to closing its books for 2002, various errors relating to the financial statements for prior years. Except for certain classification adjustments to the
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Consolidated Balance Sheet as of December 31, 2001, Allegheny’s management concluded that these errors were not material, either individually or in the aggregate, to the current year or any prior years’ financial statements. Accordingly, prior years’ financial statements were not restated, except for the Consolidated Balance Sheet as of December 31, 2001. These errors were corrected in 2002 and resulted in an increase in Allegheny’s 2002 net loss by approximately $20.1 million, net of income taxes.
The summary of these various errors are reflected in the following table, which demonstrates the effect on (loss) income from continuing operations, loss from discontinued operations and net (loss) income:
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Allegheny Energy, Inc.
We have completed an integrated audit of Allegheny Energy, Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedules
In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive loss present fairly, in all material respects, the financial position of Allegheny Energy, Inc. and its subsidiaries (the “Company”) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in Item 15 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 audits. We conducted our audits 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 of the financial statements 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 audits provide a reasonable basis for our opinion.
As discussed in Note 8, the Company changed the manner in which it accounts for goodwill and other intangible assets as of January 1, 2002. As discussed in Note 11, the Company changed the manner in which it accounts for asset retirement obligations as of January 1, 2003. As discussed in Note 5, the Company changed the manner in which it accounts for gains and losses on energy trading contracts as of January 1, 2003.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), is fairly stated, in all material respects, based on these criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the COSO. 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. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards required 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. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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 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.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
March 10, 2005
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
See accompanying Notes to Consolidated Financial Statements.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
See accompanying Notes to Consolidated Financial Statements.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
See accompanying Notes to Consolidated Financial Statements.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets-(Continued)
See accompanying Notes to Consolidated Financial Statements.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
See accompanying Notes to Consolidated Financial Statements.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholder’s Equity
See accompanying Notes to Consolidated Financial Statements.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION
Monongahela Power Company (“Monongahela”) is a wholly owned subsidiary of Allegheny Energy, Inc. (“AE,” and collectively with AE’s consolidated subsidiaries, “Allegheny”), along with its wholly owned subsidiary Mountaineer Gas Company (“Mountaineer”) and its regulated utility affiliates, The Potomac Edison Company (“Potomac Edison”) and West Penn Power Company (“West Penn”), collectively doing business as Allegheny Power, operates electric and natural gas transmission and distribution (“T&D”) systems. Monongahela operates electric T&D systems in Ohio and West Virginia and natural gas T&D systems in West Virginia. Monongahela also generates power for its West Virginia customers. Monongahela has two principal business segments. The Generation and Marketing segment includes Monongahela’s power generation operations. The Delivery and Services segment includes Monongahela’s electric T&D operations.
Monongahela is subject to regulation by the Securities and Exchange Commission (“SEC”), the Public Service Commission of West Virginia (“West Virginia PSC”), the Public Utilities Commission of Ohio (“PUCO”) and the Federal Energy Regulatory Commission (“FERC”).
Allegheny Energy Services Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who work at Monongahela and its subsidiaries. As of December 31, 2004, AESC employed approximately 5,100 employees of which approximately 1,530 are subject to collective bargaining arrangements.
NOTE 2: BASIS OF PRESENTATION
During the third quarter of 2004, Monongahela entered into an agreement to sell its West Virginia natural gas operations. The results of operations relating to these assets have been reclassified to discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. In accordance with the provisions of the Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”), the assets and liabilities associated with these discontinued operations have been reclassified as held for sale in the Consolidated Balance Sheets as of, and subsequent to, the date that held for sale criteria were met.
Certain amounts in the December 31, 2003 and 2002 Consolidated Statements of Operations, the December 31, 2002 Consolidated Statement of Cash Flows and the December 31, 2003 Consolidated Balance Sheet have been reclassified for comparative purposes.
Significant accounting policies of Monongahela and its subsidiaries are summarized below.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires Monongahela to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a continuous basis, Monongahela evaluates its estimates, including those related to the calculation of unbilled revenues, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Monongahela bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Consolidation
The Consolidated Financial Statements reflect investments in controlled subsidiaries on a consolidated basis. The Consolidated Financial Statements include the accounts of Monongahela and all subsidiary companies after elimination of intercompany transactions and balances. The Consolidated Financial Statements are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of FERC and applicable state regulatory commissions.
Revenues
Revenues from the sale of electricity and natural gas to customers of the regulated utility subsidiaries are recognized in the period that the electricity and natural gas are delivered and consumed by customers, including an estimate for unbilled revenues.
Natural gas production revenue is recognized as income when the natural gas is extracted, delivered and sold.
Deferred Energy Costs, Net
The difference between the costs of fuel, purchased energy and certain other costs and revenues from regulated electric utility purchases from, or sales to, other utilities and power marketers, including transmission services, and fuel-related revenues billed to customers has historically been deferred until it is either recovered from, or credited to, customers under state fuel and energy cost-recovery procedures. However, fuel and purchased energy costs for the regulated electric utilities have been expensed as incurred because the applicable state regulatory bodies eliminated their deferred energy cost mechanisms.
The difference between natural gas supply costs incurred and natural gas cost revenues collected from customers is deferred until recovered from, or credited to, customers under a Purchased Gas Adjustment clause in effect in West Virginia.
Deferred energy costs, net, related to Mountaineer have been reclassified to discontinued operations.
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 using the effective interest method.
Property, Plant and Equipment
Regulated Subsidiaries. Regulated property, plant and equipment are stated at original cost. Cost includes direct labor and materials, allowance for funds used during construction on regulated property for which construction work in progress is not included in rate base, and indirect costs such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes and other benefits related to employees engaged in construction.
Upon normal retirement, the cost of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation with no gain or loss recorded.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Unregulated Subsidiaries. Unregulated property, plant and equipment are stated at original cost. Monongahela’s Ohio and FERC generation assets were transferred to AE Supply at book value on June 1, 2001. For the unregulated subsidiaries, gains or losses on asset dispositions and retirements are included in the determination of net income.
Monongahela 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 beginning upon a project’s completion.
Monongahela accounts for its natural gas exploration and production activities under the successful efforts method of accounting. The cost of natural gas wells is being depleted using the units of production method. The results of operations for Monongahela’s West Virginia natural gas operations have been reclassified to discontinued operations as the result of the agreement to sell this asset.
Monongahela consolidates its proportionate interest in the electric generation stations it owns jointly with AE Supply.
Long-Lived Assets
Long-lived assets owned by Monongahela are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations, in accordance with SFAS No. 144. If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or the use of other valuation techniques, such as expected discounted future cash flows.
Allowance for Funds Used During Construction (“AFUDC”) and Interest Capitalized
AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “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 recognized as a cost of the Delivery and Services segment’s regulated property, plant and equipment, and beginning in 2003, the Generation and Marketing segment’s regulated property, plant and equipment as a result of the reapplication of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). Rates used for computing AFUDC in 2004, 2003 and 2002 averaged 6.93%, 7.38% and 8.97%, respectively. Monongahela recorded AFUDC of $0.7 million, $2.1 million and $0.5 million for 2004, 2003 and 2002, respectively.
For the Generation and Marketing segment’s construction, from June 1, 2001 until December 31, 2002, Monongahela had capitalized interest costs and amortized them on a straight-line basis over the lives of the applicable assets in accordance with SFAS No. 34, “Capitalization of Interest Costs.” Monongahela did not capitalize any interest during 2004 or 2003 and capitalized $2.6 million of interest during 2002. The interest capitalization rate in 2002 was 6.14%.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Depreciation and Maintenance
Depreciation expense is determined generally on a straight-line method based on the estimated service lives of depreciable properties. Depreciation expense was approximately 3.0% of average depreciable property in 2004 and 2003 and 3.1% in 2002. Estimated service lives for generation, T&D and other property are as follows:
The Delivery and Service segment’s depreciation expense was $30.3 million, $29.1 million and $28.4 million for 2004, 2003 and 2002, respectively. The Generation and Marketing segment’s depreciation expense was $34.4 million, $33.9 million and $32.0 million for 2004, 2003 and 2002, respectively. Depreciation expense for regulated property is provided for under currently enacted regulatory rates.
Maintenance expenses represent costs incurred to maintain the generation stations, the electric and natural gas T&D systems and general plant. These expenses reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from forced outages at the generation station and periodic storm damage to the T&D system. Maintenance costs are expensed as incurred.
Goodwill and Other Intangible Assets
Monongahela records the acquisition cost in excess of fair value of tangible and intangible assets acquired, less liabilities assumed, as goodwill. Effective January 1, 2002, with the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), Monongahela ceased amortization of goodwill and now tests goodwill for impairment at least annually. Other intangible assets with indefinite lives are not amortized. Instead, these assets are 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.
Investments
Investments are recorded using the equity method of accounting, if the investment gives Monongahela the ability to exercise significant influence, but not control, over the investee. The income or loss from unregulated investments is recorded in “Other income and expenses, net” in the Consolidated Statements of Operations.
Monongahela’s interest in the common stock of AGC is 22.97% at December 31, 2004 and 2003. AE Supply owns the remaining shares of AGC. Monongahela reports AGC in its Consolidated Financial Statements using the equity method of accounting. AGC owns an undivided 40% interest (985 megawatts (“MW”)) in the 2,463 MW pumped-storage hydroelectric station in Bath County, Virginia. This station is operated by the 60% owner, Virginia Electric and Power Company, a nonaffiliated utility.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Following is a summary of financial information for AGC in its entirety:
Cash Equivalents
For purposes of the Consolidated Statements of Cash Flows and Balance Sheets, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, repurchase agreements, and money market funds, are considered to be the equivalent of cash.
Transfer of Assets
On June 1, 2001, Monongahela transferred, at book value, approximately 352 MW of Ohio and FERC generation assets to AE Supply. PUCO, as part of Ohio’s deregulation efforts, approved the transfer. In conjunction with the transfer of the generation assets of Monongahela to AE Supply, AE Supply assumed certain pollution control debt. As of December 31, 2004 and 2003, Monongahela was a co-obligor of $12.8 million of this pollution control debt.
These pollution control bonds are included as debt in Monongahela’s Consolidated Balance Sheets, because Monongahela remains co-obligor for the debt. Even though AE Supply is responsible for the payment of the pollution control bonds, Monongahela accrues interest expense associated with the bonds. As AE Supply remits payment, Monongahela reduces accrued interest and increases paid-in capital.
AE Supply and Monongahela own certain generation assets jointly as tenants in common. AE Supply operates these jointly owned assets. Each owner is entitled to the available energy output and capacity in
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
proportion to its ownership of the asset. Monongahela does the billing for the jointly owned stations located in West Virginia, while AE Supply is responsible for billing Hatfield’s Ferry generation station, a Pennsylvania station. See Note 15, “Jointly Owned Electric Utility Plants,” for additional information.
Intercompany Transactions
Monongahela has various operating transactions with affiliates. It is Monongahela’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented on a net basis on the Consolidated Balance Sheets and the Consolidated Statements of Cash Flows.
Substantially all of the employees of Monongahela are employed by AESC, which performs services at cost for Monongahela and its affiliates in accordance with the Public Utility Holding Company Act of 1935. Monongahela is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to Monongahela for 2004, 2003 and 2002 were $209.7 million, $212.3 million and $203.7 million, respectively.
Monongahela purchases the majority of the power necessary to serve its Ohio customers who do not choose an alternate electricity generation provider from its unregulated generation company affiliate, AE Supply, in accordance with agreements approved by FERC. Monongahela’s expense from these purchases is reflected in “Purchased power and transmission” expense on the Consolidated Statements of Operations. For 2004, 2003 and 2002, Monongahela purchased power from AE Supply of $90.5 million, $69.6 million and $62.3 million, respectively. For 2004, 2003 and 2002, Monongahela also paid AE Supply $0.7 million, $1.1 million and $1.2 million, respectively, for ancillary transmission expenses. Monongahela sells electricity to AE Supply under a market rate tariff and other agreements. For 2004, 2003 and 2002, Monongahela sold electricity back to AE Supply of $19.6 million, $51.0 million and $38.5 million, respectively.
AE and its subsidiaries, including Monongahela, file a consolidated federal income tax return. The consolidated income tax liability is 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. In accordance with this consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various registrants at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the intercompany balance. Income taxes payable to affiliates, including both short and long-term obligations, at December 31, 2004 and 2003, were $53.1 million and $51.1 million, respectively.
An internal money pool accommodates intercompany short-term borrowing needs to the extent that certain of AE’s subsidiaries have funds available. The money pool provides funds to approved AE subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. Monongahela can either lend money into, or borrow money from, the money pool. At December 31, 2004, Monongahela had $42.1 million invested in the money pool, and Mountaineer had borrowings of $67.0 million outstanding from the money pool. At December 31, 2003, neither Monongahela nor Mountaineer had any investment in, or borrowings from, the money pool. See Note 11, “Short-term Debt,” for additional information regarding Monongahela’s participation in an Allegheny internal money pool.
At December 31, 2004 and 2003, Monongahela had net accounts payable to affiliates of $11.5 million and $28.6 million, respectively.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Regulatory Assets and Liabilities
Under cost-based regulation, regulated enterprises are generally permitted to recover their operating expenses and earn a reasonable return on their utility investment.
Monongahela accounts for its regulated operations under the provisions of SFAS No. 71. The economic effects of regulation can result in a regulated company recording costs 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 would be charged to expense by an unregulated enterprise. Accordingly, Monongahela 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.” Monongahela periodically evaluates the applicability of SFAS No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. See Note 13, “Regulatory Assets and Liabilities,” for additional details.
Inventory
Monongahela values materials, supplies and fuel inventory using an average cost method.
Income Taxes
Book income differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using the most current tax rates. See Note 10, “Income Taxes,” for additional information.
Monongahela joins with AE and its subsidiaries in filing a consolidated federal income tax return. The consolidated income tax liability is 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.
Monongahela has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.
Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. Management believes that its accrued tax liabilities are adequate and that any settlement related to such examination is not expected to have a material impact on Allegheny’s consolidated statement of operations, financial position or cash flow.
Pension and Other Postretirement Benefits
AE and its subsidiaries have noncontributory, defined benefit pension plans covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act of 1974 (“ERISA”) and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
AE’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. The funding policy is to contribute amounts that can be deducted for federal income tax purposes. Medical benefits are self-insured.
Through AESC, Monongahela is responsible for its proportionate share of postretirement benefit costs.
Other Comprehensive Income (Loss)
Other comprehensive income (loss) consists of unrealized gains and losses, net of income taxes, from the temporary decline in the fair value of available-for-sale securities.
NOTE 3: CAPITALIZATION
Monongahela’s consolidated capital structure, including short-term debt and debt associated with assets held for sale, as of December 31, 2004 and 2003, was as follows:
Preferred Stock
Each share of Monongahela’s preferred stock is entitled, upon voluntary liquidation, to its then current call price and, on involuntary liquidation, to $100 a share.
Long-Term Debt
At December 31, 2004, contractual maturities for long-term debt for the next five years, excluding unamortized discounts of $1.7 million, are:
At December 31, 2004, substantially all of Monongahela’s properties were held subject to the lien securing its first mortgage bonds. Some properties of Monongahela are also subject to liens securing certain pollution control bonds and solid waste disposal notes.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In June 2004, Monongahela issued $120 million of 6.70% First Mortgage Bonds, which mature on June 15, 2014. The net proceeds of the bond issuance were used to repay Monongahela’s $53.6 million short-term bridge loan in June 2004 and to fund the July 2004 redemption of $40 million of 8.375% First Mortgage Bonds due 2022 and $25 million of 7.25% First Mortgage Bonds due 2007. Interest on the 6.70% First Mortgage Bonds is payable semi-annually in arrears on each June 15 and December 15, commencing December 15, 2004. The bonds are redeemable at Monongahela’s option and rank equally in right of payment with its existing or future first mortgage bonds.
Issuances and Redemptions
Monongahela issued $120 million of first mortgage bonds during 2004. Redemptions of Monongahela’s debt during 2004 are listed below:
2003 Long-Term Debt Refinancing
Allegheny refinanced existing debt and issued new debt on February 25, 2003 and March 13, 2003, as the result of its entry into the Borrowing Facilities, as described below.
AE, AE Supply, Monongahela and West Penn entered into agreements (the “Borrowing Facilities”) with various credit providers to refinance and restructure the bulk of AE and AE Supply’s short-term debt. The Borrowing Facilities were repaid in March 2004 with a combination of available cash and proceeds from the New Loan Facilities, except for the $55 million revolving credit facility at Monongahela described below, which was repaid with the proceeds of Monongahela’s June 2004 issuance of first mortgage bonds.
Following is a summary of the terms of the Borrowing Facilities at AE, Monongahela and West Penn:
•
A $305.0 million unsecured facility with AE, Monongahela and West Penn as the designated borrowers, under which AE utilized the full facility amount. Borrowings under this facility bore interest at a London Interbank Offering Rate (“LIBOR”) based rate plus a margin of 5% or a designated money center bank’s base rate plus a margin of 4%. As of December 31, 2003, the interest rate was approximately 6.12%. This facility required a quarterly amortization payment of $7.5 million. This facility was repaid in March 2004 with proceeds from the New Loan Facilities;
•
A $25.0 million unsecured credit facility at AE. This facility had an interest rate of a designated money center bank’s base rate plus a margin of 4% and was retired in July 2003; and
•
A $10.0 million unsecured credit facility at Monongahela. On September 24, 2003, this facility was renegotiated as part of a $55 million revolving facility, of which $53.6 million was drawn at December 31, 2003. The interest on the facility was dependent upon the type of advance and consisted of a base rate plus an applicable margin or a LIBOR-based rate plus an applicable margin. As of December 31, 2003, the LIBOR-based rate was approximately 4.63%. This facility matured in September 2004 and was classified as short-term debt on the Consolidated Balance Sheet as of December 31, 2003.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
2003 Issuances and Redemptions
Monongahela issued $10.0 million of debt under the unsecured credit facility of the Borrowing Facilities during 2003. This was renegotiated as part of a $55 million revolving facility of which $53.6 million was drawn and the remainder is no longer available.
Redemptions of Monongahela’s indebtedness during 2003 are listed below:
NOTE 4: ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
Natural Gas Operations. In August 2004, Monongahela signed a definitive agreement to sell its natural gas operations in West Virginia to Mountaineer Gas Holdings Limited Partnership, (the “Buyer”) a partnership composed of IGS Utilities LLC, IGS Holdings LLC and affiliates of ArcLight Capital Partners, LLC, for $141 million in cash and the assumption of approximately $87 million of long-term debt, subject to certain closing adjustments. In addition, the Buyer will pay Monongahela, over a three-year period, certain amounts due to Monongahela from affiliates holding or owning Monongahela’s West Virginia natural gas operations. These amounts will be finally determined at the closing of the transaction. Monongahela’s natural gas operations consist of the natural gas assets of Monongahela, Mountaineer and Mountaineer Gas Services, which is a subsidiary of Mountaineer. The agreement is subject to certain closing conditions, third-party consents and state of federal regulatory approvals, including approval of a rate adjustment from the West Virginia PSC. The sale is expected to be completed in mid- to late-2005.
The results of operations relating to these assets have been reclassified to discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. These assets are recorded at the lower of carrying amount or fair value, less estimated costs to sell, and are no longer depreciated. Monongahela recorded impairment charges for the assets held for sale as described below. These impairment charges reflect the write-down of the applicable asset to the lower of its carrying amount or fair value, less estimated costs to sell. In accordance with SFAS No. 144, the assets and liabilities associated with these discontinued operations are classified as held for sale on the Consolidated Balance Sheet as of December 31, 2004.
During 2004, Monongahela recorded a charge against earnings of $36.7 million, before income taxes ($21.7 million, net of income taxes), to write-down its investment in its West Virginia natural gas operations to the expected net proceeds from the sale. This write-down is included in “Loss from discontinued operations, net of tax” in Monongahela’s Consolidated Statement of Operations. The natural gas operations are a component of the Delivery and Services segment.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The components of (loss) income from discontinued operations are as follows:
Assets held for sale and liabilities associated with assets held for sale at December 31, 2004 were as follows:
NOTE 5: GOODWILL AND OTHER INTANGIBLE ASSETS
On January 1, 2002, Monongahela adopted SFAS No. 142 which eliminated amortization of goodwill and other intangible assets with indefinite lives, effective January 1, 2002. Subsequent to the transition provisions of SFAS No. 142 (see below), other intangible assets with indefinite lives are tested annually for impairment, with impairment losses recognized in operating income. Absent any impairment indicators, Monongahela performs its annual impairment tests during its third quarter in connection with its annual budgeting process.
The transition provisions of SFAS No. 142 required Monongahela to test its goodwill for impairment as of January 1, 2002. Monongahela completed its transitional goodwill impairment test, using a discounted cash flow methodology to determine the estimated fair value of its reporting units, and recorded an impairment loss of $195.0 million, before income taxes ($115.4 million, net of income taxes), all of which related to the Delivery and Services segment. This impairment loss was recorded as the cumulative effect of a change in accounting principle. As of January 1, 2002, Monongahela no longer has any goodwill recorded on its Consolidated Balance Sheet.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The transitional goodwill impairment loss consisted of $170.0 million related to Monongahela’s acquisition of Mountaineer in 2000 and $25.0 million related to Monongahela’s acquisition of West Virginia Power in 1999. The impairment amounts resulted from factors that were unique to these rate regulated entities and the rate-making process, including the fact that none of the $195.0 million of goodwill was being recovered in rates or included in rate base. As a result, Monongahela recorded after-tax charges of $115.4 million as a cumulative effect of a change in accounting principle.
Additional intangible assets included in “Property, plant and equipment, net” on the Consolidated Balance Sheets were as follows:
Amortization expense for other intangible assets for 2004, 2003 and 2002 was $2.3 million, $2.9 million and $2.3 million, respectively. Amortization expense is estimated to be $2.3 million annually for 2005 through 2009.
In addition, “Assets held for Sale” included intangible assets related to natural gas rights, amortized with a gross carrying amount of $6.7 million at December 31, 2004 and 2003 and accumulated depreciation of $4.0 million and $3.8 million at December 31, 2004 and 2003, respectively.
NOTE 6: RESTRUCTURING CHARGES AND WORKFORCE REDUCTION EXPENSES
In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction and a reorganization of Allegheny’s energy trading division. For the year ended December 31, 2002, Allegheny recorded a charge for the workforce reduction of $107.3 million, before income taxes ($64.6 million, net of income taxes).
Allegheny has achieved workforce reductions of approximately 10% primarily through a voluntary early retirement option (“ERO”) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For the year ended December 31, 2002, approximately 600 eligible employees accepted the ERO program, resulting in a charge of $82.3 million, before income taxes ($49.3 million, net of income taxes). Allegheny also offered a Staffing Reduction Separation Program for employees whose positions were being eliminated as part of the workforce reductions and severance for certain energy trading employees. The severance and other employee-related costs were accounted for in accordance with EITF Issue No. 94-3. “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” For the year ended December 31, 2002, Allegheny recorded a charge of $25.0 million, before income taxes ($15.3 million, net of income taxes) related to approximately 80 employees whose positions had been eliminated. Allegheny has completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expenses” on the Consolidated Statements of Operations.
For the year ended December 31, 2002, Monongahela recorded a charge for its allocable share of the workforce reduction expenses of $27.8 million, before income taxes ($16.5 million, net of income taxes).
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Allegheny also recorded transition and severance expense of $5.7 million and $6.1 million in 2004 and 2003, respectively. Monongahela recorded charges of $1.5 million and $1.7 million for its allocable share of the transition and severance expense for 2004 and 2003 respectively, which is included in “Operations and maintenance” expense on the Consolidated Statements of Operations.
NOTE 7: ASSET RETIREMENT OBLIGATIONS (“ARO”)
Effective January 1, 2003, Monongahela adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS No. 143 requires that the fair value of asset retirement costs for which Monongahela has a legal obligation be recorded as liabilities, with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if it is settled at a different amount.
Monongahela recorded retirement obligations primarily related to ash landfills, underground and aboveground storage tanks and natural gas wells. Monongahela also has identified a number of retirement obligations associated with certain of its electric generation and transmission assets that have not been recorded, because the fair value of such obligations cannot be reasonably estimated, due primarily to the indeterminate lives of the assets.
The effect of adopting SFAS No. 143 on Monongahela’s Consolidated Financial Statements in 2003 was as follows:
AROs were identified with respect to property, plant and equipment for which the cost of removal of these assets currently is being recovered through rates. Monongahela believes it is probable that any difference between expenses under SFAS No. 143 and expenses recovered currently in rates with respect to these assets will be recoverable in future rates. Therefore, Monongahela is deferring these expenses as a regulatory asset.
In 2004, Monongahela recorded additional ARO liabilities of $1.2 million for the Harrison generation station ash disposal site extension Phase IV and $0.6 million for accretion expense. In accordance with SFAS No. 144, Mountaineer’s $1.8 million ARO liability was reclassified to liabilities associated with assets held for sale in the accompanying Consolidated Balance Sheets. Accordingly, Monongahela’s ARO balances at December 31, 2004 and 2003 were $6.7 million. See Note 4, “Assets Held for Sale and Discontinued Operations” to Monongahela’s Consolidated Financial Statements for additional information.
Prior to December 31, 2003, Monongahela had recorded costs of removal that did not have associated retirement obligations in “Accumulated depreciation” on its Consolidated Balance Sheets. However, in February 2004, the SEC’s Accounting Staff indicated in a public comment release that these removal costs should be included in regulatory liabilities for all periods presented. As of December 31, 2003, Monongahela began recording the removal costs collected from customers related to assets that do not have associated retirement obligations under SFAS No. 143 in “Regulatory liabilities” or “Other current liabilities” on its Consolidated Balance Sheets. These estimated removal costs were as follows:
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 8: BUSINESS SEGMENTS
Monongahela manages and evaluates its operations in two business segments: 1) Delivery and Services and 2) Generation and Marketing. The Delivery and Services segment includes Monongahela’s electric T&D operations. The Generation and Marketing segment owns, operates and manages electric generation capacity. This segment includes intersegment sales to provide energy to Monongahela’s Delivery and Services segment.
Monongahela accounts for intersegment sales based on cost or regulatory commission approved tariffs or contracts.
Monongahela entered into an agreement to sell its West Virginia natural gas operations during the third quarter of 2004. The results of operations for these assets have previously been reported as a component of the Delivery and Services segment. The results of operations for these assets for 2004, 2003 and 2002 have been reclassified to discontinued operations.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Business segment information is summarized below. Significant transactions between reportable segments are shown as eliminations to reconcile the segment information to consolidated amounts. The majority of the eliminations relate to power sold by the Generation and Marketing segment to the Delivery and Services segment.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 9: ACCOUNTING FOR THE EFFECTS OF PRICE REGULATION
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. This plan was approved, but never implemented, by the legislature. In 2002, the West Virginia PSC issued orders dismissing deregulation proceedings. Based on these actions, Monongahela concluded that retail competition and the deregulation of generation assets is no longer probable and that the generation operations in West Virginia meet the requirements of SFAS No. 71.
Monongahela reapplied the provisions of SFAS No. 71 to its West Virginia generation assets in the first quarter of 2003 and recorded a gain of $61.7 million as part of “Other income and expenses, net” in the Consolidated Statements of Operations. This gain was primarily the result of the elimination of its transition obligation and the reestablishment of regulatory assets related to deferred income taxes.
As a result of the reapplication of SFAS No. 71 to the West Virginia generation assets in January 2003, the Consolidated Balance Sheets do not include any amounts for generation assets not subject to SFAS No. 71 as of December 31, 2004 and 2003.
NOTE 10: INCOME TAXES
Details of federal and state income tax (benefit) expense from continuing operations are:
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The total provision for income tax (benefit) expense from continuing operations differs from the amount produced by applying the federal statutory income tax rate of 35% to financial accounting income, as set forth below:
The total provision for income tax (benefit) expense from discontinued operations differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount, as set forth below:
The total provision for income tax benefit for the cumulative effect of accounting change differs from the amount produced by applying the federal statutory income tax rate of 35% to the gross amount, as set forth below:
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
At December 31, the deferred tax assets and liabilities consisted of the following:
Monongahela recorded as deferred tax assets the effect of net operating losses, which will more likely than not be realized through future operations and through the reversal of existing temporary differences. These net operating loss carryforwards expire in varying amounts through 2024. In addition, Monongahela is a party to a consolidated tax sharing agreement, which was amended effective July 1, 2003. Monongahela can realize the benefits of its net operating loss carryforwards generated prior to this date only to the extent of its future taxable income. Monongahela expects to realize benefits represented by deferred tax assets through its participation in the consolidated tax return in future years.
NOTE 11: SHORT-TERM DEBT
Monongahela had no short-term debt outstanding at December 31, 2004. Monongahela had $53.6 million of short-term debt outstanding as of December 31, 2003, which represented a bridge loan that had a term of 364 days, and which was issued in September of 2003. This loan was repaid in June 2004 with a portion of the proceeds from the issuance of the Monongahela first mortgage bonds.
Monongahela has SEC authorization for total short-term borrowings, from all sources, of $106.0 million and its subsidiary, Mountaineer has SEC authorization for total short-term borrowings, from all sources, of $100.0 million.
To provide interim financing and support for outstanding commercial paper, Allegheny and its regulated subsidiaries, including Monongahela, had established lines of credit with several banks. These lines of credit had fee arrangements and no compensating balance requirements. These facilities were refinanced in 2003, as discussed in Note 3, “Capitalization.”
Short-term debt outstanding for 2004 and 2003 consisted of:
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 12: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
As described in Note 2, “Basis of Presentation,” Monongahela is responsible for its proportionate share of the net periodic cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. Monongahela’s share of the costs, of which approximately 19% and 16% in 2004 and 2003, respectively, were allocated to “Construction work in progress,” a component of “Property, plant and equipment, net,” was as follows:
The assumptions used to determine net periodic benefit costs for years ended December 31, 2004, 2003 and 2002 are shown in the table below. The discount rates, expected long-term rates of return on plan assets and rates of compensation increases used in determining net periodic benefit costs were as follows:
The assumptions used to determine benefit obligations at September 30, 2004, 2003 and 2002 and the expected long-term rates of return on plan assets in each of the years 2004, 2003 and 2002 are shown in the table below:
Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs for 2005 is 8.5%.
Assumed health care cost trend rates at December 31 are as follows:
For measuring obligations related to postretirement benefits other than pensions, a health care cost trend rate of 9.5% beginning with 2005 and grading down by 0.5% each year to an ultimate rate of 5.0%, and plan
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
provisions that limit future medical and life insurance benefits, were assumed. 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.
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 became law. Beginning in 2006, the federal government will provide subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. Allegheny elected to follow the deferral provisions of FASB Staff Position (“FSP”) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-1”). FSP 106-1 permits employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until guidance on the accounting for the federal subsidy is issued. On May 19, 2004, FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”), which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.
NOTE 13: REGULATORY ASSETS AND LIABILITIES
Monongahela’s electric generation and T&D operations and natural gas T&D operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:
Income Taxes, Net
In certain jurisdictions, deferred income tax expense is not permitted as a cost in the determination of rates charged to customers. In these jurisdictions a deferred income tax liability is recorded with an offsetting regulatory asset. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. These deferred income taxes relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. No return is allowed on the regulatory asset for income taxes.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
See Note 9, “Accounting for the Effects of Price Regulation,” for a discussion regarding Monongahela’s reapplication of the provisions of SFAS No. 71 to their West Virginia generation assets in 2003.
See Note 7, “Asset Retirement Obligations,” for a discussion of a regulatory liability identified in conjunction with the application of a new accounting pronouncement.
NOTE 14: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of long-term debt, including long-term debt due within one year, and preferred stock of subsidiary, at December 31, were as follows:
The above table excludes long-term debt with a carrying amount of $86.7 million and a fair value of $95.1 million related to liabilities associated with assets held for sale at December 31, 2004.
The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The fair value of preferred stock is based on quoted market prices. The carrying amounts of cash equivalents and short-term debt approximate the fair values of these financial instruments because of the short maturities of those instruments.
NOTE 15: JOINTLY OWNED ELECTRIC UTILITY PLANTS
Monongahela owns an interest in seven generation stations with AE Supply. Monongahela records its proportionate share of operating costs, assets and liabilities in the corresponding lines in the Consolidated Financial Statements. As of December 31, 2004 and 2003, Monongahela’s utility plant investment and accumulated depreciation in these generation stations were as follows:
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Through its 22.97% interest in AGC, Monongahela also owns an interest in AGC’s jointly owned electric utility plant. AGC’s 40% investment and accumulated depreciation in the Bath County generation station jointly owned with a third party at December 31, 2004 and 2003, were as follows:
NOTE 16: OTHER INCOME AND EXPENSES, NET
Other income and expenses, net represents non-operating income and expenses before income taxes. The following table summarizes Monongahela’s other income and expenses, net for 2004, 2003 and 2002:
NOTE 17: QUARTERLY FINANCIAL INFORMATION (Unaudited)
NOTE 18: GUARANTEES AND LETTERS OF CREDIT
Monongahela had no guarantees or letters of credit outstanding as of December 31, 2004.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 19: COMMITMENTS AND CONTINGENCIES
Construction and Capital Program
Monongahela has entered into commitments for its capital programs for which expenditures are estimated to be $66.6 million for 2005 and $80.6 million for 2006. Capital expenditure levels in 2007 and beyond will depend upon, among other things, the strategy eventually selected for complying with Phase II of the Clean Air Act Amendments of 1990 and the extent to which environmental initiatives currently being considered become mandated. See “Environmental Matters and Litigation-Clean Air Act Matters” below.
Environmental Matters and Litigation
Monongahela is subject to various laws, regulations, and uncertainties as to environmental matters. Compliance may require Monongahela to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.
Clean Air Act Matters: Allegheny currently meets applicable standards for particulate matter emissions at its generation stations through the use of high-efficiency electrostatic precipitators, cleaned coal, flue-gas conditioning, optimization software, fuel combustion modifications and emission allowances and, at times, through reduction of output. From time to time, minor excursions of stack emission opacity that are normal to fossil fuel operations are experienced and accommodated by the regulatory process.
Allegheny meets current emission standards for sulfur dioxide (“SO2”) by using scrubbers, burning low-sulfur coal, purchasing cleaned coal (which has lower sulfur content), blending low-sulfur coal with higher sulfur coal and using emission allowances.
Allegheny’s compliance with the Clean Air Act of 1970 (the “Clean Air Act”) has required, and may require in the future, that Allegheny install of expensive post-combustion control technologies on many of its generation stations.
The Clean Air Act mandates annual reductions of SO2 and created a SO2 emission allowance trading program. AE Supply and Monongahela comply with current SO2 emission standards through a system-wide plan combining the use of emission controls, burning low sulfur fuel and emission allowances. Allegheny continues to study of the use of allowances, additional emission controls and low sulfur fuel to meet future SO2 compliance obligations. Allegheny estimates that it will purchase allowances for up to 50,000 tons for 2005 and an average of approximately 100,000 tons per year for 2006 through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the type of fuel used by its generation facilities. Allegheny currently expects that its plan to increase its use of lower sulfur coal and implement other environmental control improvements should reduce allowance purchase requirements over this time period.
In 1998, the EPA finalized its Nitrogen Oxide (“NOx”) State Implementation Plan (“SIP”) call rule (known as the “NOx SIP call”), which addressed the regional transport of ground-level ozone and required the equivalent of a uniform 0.15 lb/mmBtu emission rate throughout a 22-state region, including Pennsylvania, Maryland and West Virginia. The Compliance with the NOx SIP call was required beginning in May 2004. Pennsylvania and Maryland implemented their respective SIP call rules in May 2003. West Virginia’s SIP call rules were effective as of May 2004.
AE Supply and Monongahela are completing installation of NOx controls to meet the Pennsylvania, Maryland and West Virginia SIP calls. These NOx controls include selective catalytic reduction at the Harrison and Pleasants generation stations and selective noncatalytic reduction at the Hatfield’s Ferry and Fort Martin
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
generation stations, as well as burner modifications at Mitchell generation station. The NOx compliance plan functions on a system-wide basis, similar to the SO2 compliance plan. AE Supply and Monongahela also have the option, in some cases, to purchase alternate fuels or NOx allowances, if needed, to supplement their compliance strategies. AE Supply estimates that its emission control activities, in concert with its inventory of banked allowances, will facilitate its compliance with NOx limits established by the SIP through 2008. Allegheny’s allowance needs, to a large extent, are affected at any given time by the amount of output produced and the type of fuel used by its generation facilities. Monongahela’s capital expenditure forecast includes the expenditure of $1.5 million of capital costs during the 2005 through 2007 period for NOx emission controls.
In August 2000, AE received a letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten electric generation stations, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. AE Supply and Monongahela own these generation stations. The letter requested information under Section 114 of the Clean Air Act to determine compliance with the Clean Air Act and related requirements, including potential application of the New Source Review (“NSR”) standards of the Clean Air Act, which can require the installation of additional air pollution control equipment upon the major modification of an existing facility. AE provided responsive information to this and a subsequent request. A meeting between the EPA and AE was held on July 16, 2003. At this time, AE is engaged in discussions with the EPA with respect to environmental matters, including NSR issues.
Similar inquiries have been made of other electric utilities and have resulted in enforcement proceedings in most cases. AE believes that its subsidiaries’ generation facilities have been operated in accordance with the Clean Air Act and the rules implementing it. The experience of other energy companies, however, suggests that, in recent years, the EPA has narrowed its view regarding the scope of the definition of “routine maintenance” under its rules, thereby broadening the range of actions subject to compliance with NSR standards. Section 114 information requests concerning facility modifications are often followed by enforcement actions.
If NSR standards are applied to Allegheny’s generation stations, in addition to the possible imposition of fines, compliance would entail significant expenditures. There are two federal district court decisions interpreting the application of NSR standards to utilities, the Ohio Edison decision and the Duke Energy decision. The Ohio Edison decision is favorable to the EPA. The Duke Energy decision supports the industry’s understanding of NSR requirements. The final Routine Maintenance, Repair and Replacement Rule (“RMRR”) released by the EPA is more consistent with the energy industry’s historical compliance approach. On December 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit issued an order to stay the RMRR, which was scheduled to go into effect on December 26, 2003. The stay delays implementation of the RMRR. At this time, AE and its subsidiaries are not able to determine the effect that these actions may have on them.
On February 2, 2004, the EPA informed AE that it intended to provide the New York Attorney General, pursuant to his request, certain records that AE provided to the EPA pursuant to its request under Section 114 of the Clean Air Act. On April 23, 2004, the Pennsylvania Department of Environmental Protection (“PADEP”) notified AE Supply that the PADEP had requested that the EPA provide it with these records.
On May 20, 2004, AE, AE Supply, Monongahela and West Penn received a Notice of Intent to Sue Pursuant to Clean Air Act §7604 (the “Notice”) from the Attorneys General of New York, New Jersey and Connecticut and from PADEP. The Notice alleged that Allegheny made major modifications to some of its West Virginia facilities in violation of the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act at the following coal-fired facilities: Albright Unit No. 3; Fort Martin Units No. 1 and 2; Harrison Units No. 1, 2
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
and 3; Pleasants Units No. 1 and 2 and Willow Island Unit No. 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation stations in Pennsylvania and identifies PADEP as the lead agency regarding those facilities. On September 8, 2004, AE Supply and Monongahela received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
AE Supply and Monongahela filed a declaratory judgment action against the Attorneys General of New York, Connecticut and New Jersey in federal district court in West Virginia on January 6, 2005. This action requests that the court declare that AE Supply’s and Monongahela’s coal-fired generation in Pennsylvania and West Virginia are in compliance with the Clean Air Act. The Attorneys General filed a motion to dismiss the declaratory judgment action. If the action is dismissed based upon the Attorneys General’s motion, the Attorneys General may file an enforcement action against Allegheny in federal court in Pennsylvania. It is also possible that the EPA and other state authorities may join in the current declaratory judgment action or, if it is dismissed, a new action filed by the Attorneys General.
On February 16, 2005, Citizens for Pennsylvania’s Future, an environmental group, sued Allegheny in the U.S. District Court for the Western District of Pennsylvania. The action alleges violations of operating limits and particulate matter emission limits at the Hatfield’s Ferry generation facility.
Allegheny intends to vigorously pursue these matters but cannot predict their outcomes.
Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”) Claim: On March 4, 1994, Monongahela and certain affiliated companies received notice that the EPA had identified them as potentially responsible parties (“PRPs”) with respect to the Jack’s Creek/Sitkin Smelting Superfund Site. Initially, approximately 175 PRPs were involved, however, the current number of active PRPs has been reduced as a result of settlements with de minimis contributors and other contributors to the site. The costs of remediation will be shared by all past and active responsible parties. In 1999, a PRP group that included Monongahela and certain affiliated companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30.0 million. Monongahela has an accrued liability representing its estimated share of the remediation costs as of December 31, 2004.
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 contractor employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from its historical insurers and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s, London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W. Va.). The parties in these actions are seeking an allocation of responsibility for Allegheny’s historic asbestos liability.
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
During the pendency of these actions, Allegheny will continue to receive payments from one of its insurance companies in the amount of $625,000, payable on each of July 1, 2005 and 2006. During 2004 and 2003, Allegheny received insurance recoveries of approximately $960,000 and $1.8 million, respectively, in connection with these cases. Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2004, Allegheny had 1,504 open cases remaining. Allegheny intends to vigorously defend against these actions but cannot predict their outcomes.
Ordinary Course of Business: Monongahela is from time to time involved in litigation and other legal disputes in the ordinary course of business. Monongahela is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.
Leases
Monongahela has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles and computer equipment.
Total capital and operating lease rent payments of $7.8 million in 2004 and $8.8 million in 2003 and 2002 were recorded as rent expense in accordance with SFAS No. 71. Monongahela’s estimated future minimum lease payments for capital and operating leases, including those leases entered into by AESC which are allocated to Monongahela and certain other leases related to discontinued operations, 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 consists of the following:
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
PURPA
Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), electric utility companies, such as Monongahela, are required to interconnect with, provide back-up electric service to, and purchase electric capacity and energy from, qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. The appropriate state public service commission or legislature establishes the rates paid for electric energy purchased from qualifying facilities.
Monongahela is committed to purchase the electrical output from 161 MW of qualifying PURPA capacity. Payments for PURPA capacity and energy in 2004, 2003 and 2002 totaled $56.6 million, $68.8 million and $59.3 million, respectively. The amount for 2003 excludes a contractually required payment received in accordance with certain contract provisions at a hydroelectric facility that supplies power to Monongahela. The average cost to Monongahela of these power purchases was approximately 4.3 cents per kilowatt-hour (“kWh”) 5.2 cents per kWh and 5.4 cents per kWh for 2004, 2003 and 2002, respectively. Monongahela is currently authorized to recover PURPA costs in its retail rates.
The table below reflects Monongahela’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2004. Actual values can vary substantially depending upon future conditions.
Fuel Purchase and Transportation Commitments
Monongahela 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. Monongahela’s fuel consumed in electric generation was $119.1 million, $135.1 million and $128.9 million in 2004, 2003 and 2002, respectively. In 2004, Monongahela purchased approximately 52% of its fuel from one vendor. Total estimated long-term fuel purchase and transportation commitments (primarily coal and lime), excluding commitments related to assets held for sale of $217.0 million, at December 31, 2004, were as follows, by year, and in total:
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 20: COMPREHENSIVE FINANCIAL REVIEW
During 2002, Monongahela identified certain errors in its financial reporting. In light of this fact and Monongahela’s prior restatements of reports filed with the SEC, Monongahela initiated a comprehensive review of its financial processes, records, and internal controls to ensure that its then current and prior financial statements were fairly presented in accordance with GAAP.
As a result of this accounting review, Monongahela identified, prior to closing its books for 2002, various errors relating to the financial statements for prior years. Monongahela identified certain additional errors prior to closing its books in 2003. Monongahela’s management concluded that these errors were not material, either individually or in the aggregate, to the current year or any prior years’ financial statements. Accordingly, prior years’ financial statements have not been restated. These errors were corrected in 2002 and 2003.
The summary of these various errors are reflected in the following table, which demonstrates the effect on income from continuing operations, income from discontinued operations and net income (loss):
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Monongahela Power Company:
In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of operations, stockholder’s equity and cash flows present fairly, in all material respects, the financial position of Monongahela Power Company and its subsidiaries (the “Company”) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in Item 15 presents 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 schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
As discussed in Note 5 to the consolidated financial statements, the Company changed the manner in which it accounts for goodwill and other intangible assets as of January 1, 2002.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
March 10, 2005
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
See accompanying Notes to Consolidated Financial Statements.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
See accompanying Notes to Consolidated Financial Statements.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
See accompanying Notes to Consolidated Financial Statements.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets-(Continued)
See accompanying Notes to Consolidated Financial Statements.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
Long-term Debt:
See accompanying Notes to Consolidated Financial Statements.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Consolidated Statements of Stockholder’s Equity
See accompanying Notes to Consolidated Financial Statements.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION
Potomac Edison is a regulated wholly owned subsidiary of Allegheny Energy, Inc. (“AE”, and collectively with AE’s consolidated subsidiaries, “Allegheny”) and along with its regulated utility affiliates, Monongahela Power Company (“Monongahela”) and West Penn Power Company (“West Penn”), collectively doing business as Allegheny Power, operate electric and natural gas transmission and distribution (“T&D”) systems. Potomac Edison operates an electric T&D system in Maryland, Virginia and West Virginia. Potomac Edison currently operates under a single business segment, Delivery and Services.
Potomac Edison is subject to regulation by the Securities and Exchange Commission (“SEC”), the Maryland Public Service Commission (“Maryland PSC”), the Public Service Commission of West Virginia, the Virginia State Corporation Commission and the Federal Energy Regulatory Commission (“FERC”).
Allegheny Energy Services Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who work at Potomac Edison and its subsidiaries. As of December 31, 2004, AESC employed approximately 5,100 employees, of which approximately 1,530 are subject to collective bargaining arrangements.
NOTE 2: BASIS OF PRESENTATION
Certain amounts in the December 31, 2003 and 2002 Consolidated Statements of Cash Flows have been reclassified for comparative purposes.
Significant accounting policies of Potomac Edison and its subsidiaries are summarized below.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires Potomac Edison to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a continuous basis, Potomac Edison evaluates its estimates, including those related to the calculation of unbilled revenues, provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. Potomac Edison bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.
Consolidation
The Consolidated Financial Statements reflect investments in controlled subsidiaries on a consolidated basis. The Consolidated Financial Statements include the accounts of Potomac Edison and all subsidiary companies after elimination of intercompany transactions and balances and are prepared in conformity with GAAP, giving recognition to the rate-making and accounting practices of FERC and applicable state regulatory commissions.
Revenues
Revenues from the sale of electricity and natural gas to customers of the regulated utility subsidiaries are recognized in the period that the electricity and natural gas are delivered and consumed by customers, including an estimate for unbilled revenues.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Revenues from one industrial customer were 12.9%, 10.5% and 8.9% of total operating revenues in 2004, 2003 and 2002, respectively.
Deferred Energy Costs, Net
To satisfy its obligations under the provisions of the Public Utility Regulatory Policies Act of 1978 (“PURPA”), Potomac Edison entered into a long-term contract to purchase capacity and energy from the AES Warrior Run facility through the beginning of 2030. Effective July 1, 2000, Potomac Edison was authorized by the Maryland PSC to recover all contract costs from the AES Warrior Run cogeneration 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 or over-recovery of net costs related to AES Warrior Run is being deferred on Potomac Edison’s Consolidated Balance Sheets, as deferred energy costs, pending subsequent recovery from, or return to, customers through adjustments to this retail revenue surcharge. See “PURPA” in Note 18, “Commitments and Contingencies,” 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 using the effective interest method.
Property, Plant and Equipment
Regulated property, plant and equipment are stated at original cost. Cost includes direct labor and materials, allowance for funds used during construction on regulated property for which construction work in progress is not included in rate base, and indirect costs such as administration, maintenance and depreciation of transportation and construction equipment, postretirement benefits, taxes and other benefits related to employees engaged in construction.
Upon normal retirement, the cost of depreciable regulated property, plus removal costs less salvage, are charged to accumulated depreciation with no gain or loss recorded.
Potomac Edison 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 beginning upon a project’s completion.
Long-Lived Assets
Long-lived assets owned by Potomac Edison are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations, in accordance with the provisions of the Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”). If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals or other valuation techniques, such as expected discounted future cash flows.
Allowance for Funds Used During Construction (“AFUDC”)
AFUDC, an item that does not represent current cash income, is defined in applicable regulatory systems of accounts as including “the net cost for the period of construction of borrowed funds used for construction
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
purposes and a reasonable rate on other funds when so used.” AFUDC is recognized by Allegheny’s regulated subsidiaries as a cost of regulated property, plant and equipment. Rates used for computing AFUDC in 2004, 2003 and 2002 averaged 9.28%, 9.04% and 2.76%, respectively. Potomac Edison recorded AFUDC of $1.0 million and $0.8 million in 2004 and 2003, respectively. Potomac Edison did not record a material amount of AFUDC in 2002.
Depreciation and Maintenance
Depreciation expense is determined generally on a straight-line method based on the estimated service lives of depreciable properties. Depreciation expense was approximately 2.8% of average depreciable property in 2004, 2003 and 2002. Estimated service lives for T&D and other property are as follows:
Maintenance expenses represent costs incurred to maintain the electric T&D systems and general plant. These expenses reflect routine maintenance of equipment and rights-of-way, as well as planned repairs and unplanned expenditures, primarily from periodic storm damage to the T&D system. Maintenance costs are expensed as incurred.
Intangible Assets
Intangible assets with indefinite lives are not amortized, but rather are tested for impairment at least annually. Intangible assets with finite lives are amortized over their useful lives and tested for impairment when events or circumstances warrant. Potomac Edison has intangible assets consisting of amortized land easements, which are included in property, plant and equipment on the Consolidated Balance Sheets, with a gross carrying amount and accumulated amortization as follows: at December 31, 2004, $55.2 million and $15.1 million, respectively, and at December 31, 2003, $55.0 million and $14.3 million, respectively. Amortization expense was $0.8 million in 2004 and 2003. Amortization expense is estimated to be $0.8 million annually for 2005 through 2010.
Intercompany Transactions
Potomac Edison has various operating transactions with affiliates. It is Potomac Edison’s policy that the affiliated receivable and payable balances outstanding from these transactions are presented on a net basis on the Consolidated Balance Sheets and the Consolidated Statements of Cash Flows.
Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for Potomac Edison and its affiliates in accordance with the Public Utility Holding Company Act of 1935, as amended (“PUHCA”). Potomac Edison is responsible for its proportionate share of services provided by AESC. The total billings by AESC (including capital) to Potomac Edison for 2004, 2003 and 2002 were $100.8 million, $102.2 million and $103.1 million, respectively.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Potomac Edison purchases a majority of the power necessary to serve its customers who do not choose an alternate electricity generation provider from AE Supply in accordance with agreements approved by FERC. The expense for these purchases is reflected in “Purchased power and transmission cost” on the Consolidated Statements of Operations. For 2004, 2003 and 2002, Potomac Edison purchased power from Allegheny Energy Supply Company, LLC (“AE Supply”) of $528.3 million, $527.6 million and $497.6 million, respectively. For 2004, 2003 and 2002, Potomac Edison also paid AE Supply $10.2 million, $9.9 million and $9.8 million, respectively, for ancillary transmission expenses. Before Potomac Edison joined PJM Interconnection, LLC (“PJM”) in April 2002, if Potomac Edison purchased more electricity than was needed to serve its customers, the excess electricity purchased was sold back to AE Supply and reflected as “Operating revenues” on the Consolidated Statements of Operations. When Potomac Edison joined PJM, operational changes were made so that Potomac Edison no longer has excess electricity to sell back to AE Supply. For 2002, Potomac Edison sold excess electricity back to AE Supply of $5.1 million.
AE and its subsidiaries, including Potomac Edison, file a consolidated federal income tax return. The consolidated income tax liability is 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. In accordance with this consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various registrants at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the intercompany balance. Income taxes payable to affiliates, including both short and long-term obligations, at December 31, 2004 and 2003, were $47.3 million and $42.7 million, respectively.
An internal money pool accommodates intercompany short-term borrowing needs to the extent that certain of AE’s subsidiaries have funds available. The money pool provides funds to approved AE subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. Potomac Edison can either lend money into, or borrow money from, the money pool. At December 31, 2004, Potomac Edison had $14.4 million invested in the money pool. At December 31, 2003, Potomac Edison had no investments in, or borrowings from, the money pool. See Note 10, “Short-term Debt,” for additional information regarding Potomac Edison’s participation in an Allegheny internal money pool.
At December 31, 2004 and 2003, Potomac Edison had net accounts payable to affiliates of $49.0 million and $49.7 million, respectively.
Cash Equivalents
For purposes of the Consolidated Statements of Cash Flows and Consolidated Balance Sheets, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit repurchase agreements and money market funds, are considered to be the equivalent of cash.
Regulatory Assets and Liabilities
Under cost-based regulation, regulated enterprises generally are permitted to recover their operating expenses and earn a reasonable return on their utility investment.
Potomac Edison accounts for its regulated operations under the provisions of SFAS No. 71. “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”). The economic effects of regulation can result in a regulated company recording costs that have been, or are expected to be, allowed in the rate-setting process in a
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
period different from the period in which the costs would be charged to expense by an unregulated enterprise. Accordingly, Potomac Edison 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.” Potomac Edison periodically evaluates the applicability of SFAS No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. See Note 12, “Regulatory Assets and Liabilities,” for additional details.
Inventory
Potomac Edison values materials and supplies inventory using an average cost method.
Income Taxes
Book income differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using the most current tax rates. See Note 9, “Income Taxes,” for additional information.
AE and its subsidiaries, including Potomac Edison, file a consolidated federal income tax return. The consolidated income tax liability is 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.
Potomac Edison has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.
Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. Management believes that its accrued tax liabilities are adequate and that any settlement related to such examination is not expected to have a material impact on Allegheny’s consolidated statement of operations, financial position or cash flow.
Pension and Other Postretirement Benefits
AE and its subsidiaries have noncontributory, defined benefit pension plans covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act of 1974 and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments.
AE’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. The funding policy is to contribute amounts that can be deducted for federal income tax purposes. Medical benefits are self-insured.
Through AESC, Potomac Edison is responsible for its proportionate share of postretirement benefit costs.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Other Comprehensive Income (Loss)
Other comprehensive income (loss) consists of unrealized gains and losses, net of income taxes, from the temporary change in the fair value of available-for-sale securities.
NOTE 3: CAPITALIZATION
Potomac Edison’s consolidated capital structure, including short-term debt, as of December 31, 2004 and 2003, was as follows:
Long-term Debt
At December 31, 2004, contractual maturities for Potomac Edison’s long-term debt for the next five years, excluding unamortized discounts of $2.1 million, are:
Substantially all of the properties of Potomac Edison are held subject to the lien securing its first mortgage bonds. Certain first mortgage bond series are not redeemable until dates established in the respective supplemental indentures.
2004 Issuances and Redemptions
In November 2004, Potomac Edison issued $175 million of 5.35% First Mortgage Bonds, which mature on November 15, 2014. The net proceeds of the bond issuance were used to fund the December 2004 redemption of $55.0 million of 8.0% First Mortgage Bonds due 2022, $45.0 million of 7.75% First Mortgage Bonds due 2023 and $75.0 million of 8.0% First Mortgage Bonds due 2024. Interest on the 5.35% First Mortgage Bonds is payable semi-annually in arrears on each May 15 and November 15, commencing May 15, 2005. These bonds are redeemable at Potomac Edison’s option and rank equally in right of payment with its existing or future unsubordinated indebtedness.
2003 Issuances and Redemptions
Potomac Edison did not issue or redeem any debt during 2003.
NOTE 4: ASSETS HELD FOR SALE
In July 2004, Potomac Edison entered into an agreement to sell its Hagerstown, Maryland property for approximately $13 million in cash. The potential buyer terminated the sales agreement in December 2004. Potomac Edison is continuing to market this property and expects to complete a sale in 2005. This asset has been recorded as an asset held for sale within “Other Assets” on the Consolidated Balance Sheet as of December 31, 2004.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 5: ASSET IMPAIRMENTS
During the fourth quarter of 2004, the potential buyer of Potomac Edison’s Hagerstown, Maryland property terminated the sales agreement with Potomac Edison. Potomac Edison recorded a write-down to fair value less estimated costs to sell, which resulted in an impairment charge of $0.9 million, before income taxes ($0.5 million, net of income taxes). The write-down is included in “Other income and expenses, net” on the Consolidated Statements of Operations.
NOTE 6: RESTRUCTURING CHARGES AND WORKFORCE REDUCTION EXPENSES
In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction and a reorganization of Allegheny’s energy trading division. For the year ended December 31, 2002, Allegheny recorded a charge for the workforce reduction of $107.3 million, before income taxes ($64.6 million, net of income taxes).
Allegheny has achieved workforce reductions of approximately 10% primarily through a voluntary early retirement option (“ERO”) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For the year ended December 31, 2002, approximately 600 eligible employees accepted the ERO program, resulting in a charge of $82.3 million, before income taxes ($49.3 million, net of income taxes). Allegheny also offered a Staffing Reduction Separation Program for employees whose positions were being eliminated as part of the workforce reductions and severance for certain energy trading employees. The severance and other employee-related costs were accounted for in accordance with EITF No. 94-3. “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” For the year ended December 31, 2002, Allegheny recorded a charge of $25.0 million, before income taxes ($15.3 million, net of income taxes) related to approximately 80 employees whose positions have been eliminated. Allegheny has completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expenses” on the Consolidated Statements of Operations.
Potomac Edison recorded a charge for its allocable share of the workforce reduction expenses of $12.4 million, before income taxes ($7.5 million, net of income taxes), for the year ended December 31, 2002.
Allegheny also recorded transition and severance expense of $5.7 million and $6.1 million in 2004 and 2003, respectively. Potomac Edison recorded charges of $0.9 million for its allocable share of the transition and severance expense in both 2004 and 2003, which are included in “Operations and maintenance” expense on the Consolidated Statements of Operations.
NOTE 7: ASSET RETIREMENT OBLIGATIONS (“ARO”)
Effective January 1, 2003, Potomac Edison adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS No. 143 requires that the fair value of asset retirement costs for which Potomac Edison has a legal obligation be recorded as liabilities, with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if it is settled at a different amount.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Potomac Edison recorded retirement obligations primarily related to underground and aboveground storage tanks. Potomac Edison also has identified a number of retirement obligations associated with certain of its electric generation and transmission assets that have not been recorded, because the fair value of such obligations cannot be reasonably estimated, due primarily to the indeterminate lives of the assets.
The effect of adopting SFAS No. 143 on Potomac Edison’s Consolidated Financial Statements in 2003 was not material.
Potomac Edison’s ARO balances at December 31, 2004 and 2003 were $0.2 million.
Prior to December 31, 2003, Potomac Edison had recorded costs of removal that did not have associated retirement obligations in “Accumulated depreciation” on its Consolidated Balance Sheets. However, in February 2004, the SEC’s Accounting Staff indicated in a public comment release that these removal costs should be included in regulatory liabilities for all periods presented. As of December 31, 2003, Potomac Edison began recording the removal costs collected from customers related to assets that do not have associated retirement obligations under SFAS No. 143 in “Regulatory liabilities” or “Other current liabilities” on its Consolidated Balance Sheets. These estimated removal costs were as follows:
NOTE 8: ACCOUNTING FOR THE EFFECTS OF PRICE REGULATION
Potomac Edison recorded a transition obligation on its books associated with West Virginia deregulation. Potomac Edison also reapplied the provisions of SFAS No. 71 in the first quarter of 2003 and recognized a gain of approximately $14.1 million as a result of the elimination of its transition obligation. This gain is a component of “Other income and expenses, net” in the Consolidated Statements of Operations.
NOTE 9: INCOME TAXES
Details of federal and state income tax expense (benefit) are:
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The total provision for income tax expense differs from the amount produced by applying the federal statutory income tax rate of 35% to financial accounting income, as set forth below:
At December 31, the deferred tax assets and liabilities consisted of the following:
Potomac Edison is a party to a consolidated tax sharing agreement, which was amended effective July 1, 2003. Potomac Edison expects to realize benefits represented by deferred tax assets through its participation in the consolidated Allegheny tax return in future years.
NOTE 10: SHORT-TERM DEBT
Potomac Edison has SEC authorization for total short-term borrowings, from all sources, of $130 million.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
There was no short-term debt outstanding as of December 31, 2004 and 2003. Average amounts of short-term debt outstanding during 2004 and 2003 consisted of:
NOTE 11: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
As described in Note 2, “Basis of Presentation,” Potomac Edison is responsible for its proportionate share of the net periodic cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. Potomac Edison’s share of the costs, of which approximately 35% and 21% in 2004 and 2003, respectively, were allocated to “Construction work in progress,” a component of “Property, plant and equipment, net,” was as follows:
The assumptions used to determine net periodic benefit costs for years ended December 31, 2004, 2003 and 2002 are shown in the table below. The discount rates, expected long-term rates of return on plan assets and rates of compensation increases used in determining net periodic benefit costs were as follows:
The assumptions used to determine benefit obligations at September 30, 2004, 2003 and 2002 and the expected long-term rates of return on plan assets in each of the years 2004, 2003 and 2002 are shown in the table below:
Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs for 2005 is 8.5%.
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Assumed health care cost trend rates at December 31 are as follows:
For measuring obligations related to postretirement benefits other than pensions, a health care cost trend rate of 9.5% beginning with 2005 and grading down by 0.5% each year to an ultimate rate of 5.0%, and plan provisions that limit future medical and life insurance benefits, were assumed. 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.
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) became law. Beginning in 2006, the federal government will provide subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. Allegheny elected to follow the deferral provisions of FASB Staff Position (“FSP”) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-1”). FSP 106-1 permits employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until guidance on the accounting for the federal subsidy is issued. On May 19, 2004, FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”) which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.
NOTE 12: REGULATORY ASSETS AND LIABILITIES
Potomac Edison’s operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and regulatory liabilities reflected in the Consolidated Balance Sheets at December 31 relate to:
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Income Taxes, Net
In certain jurisdictions, deferred income tax expense is not permitted as a cost in the determination of rates charged to customers. In these jurisdictions a deferred income tax liability is recorded with an offsetting regulatory asset. The income tax regulatory asset represents amounts that will be recovered from customers when the temporary differences are reversed and the taxes paid. These deferred income taxes relate to temporary differences involving regulated utility property, plant and equipment and the related provision for depreciation. No return is allowed on the regulatory asset for income taxes.
See Note 8, “Accounting for the Effects of Price Regulation,” for a discussion regarding Potomac Edison’s reapplication of the provisions of SFAS No. 71 to their West Virginia generation assets in the first quarter of 2003.
See Note 7, “Asset Retirement Obligations,” for a discussion of a regulatory liability for a cost of removal.
NOTE 13: FAIR VALUE OF FINANCIAL INSTRUMENTS
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 the long-term debt was estimated based on actual market prices or market prices of similar issues. The carrying amounts of cash equivalents and short-term debt approximate the fair values of such financial instruments because of the short maturities of those instruments.
NOTE 14: OTHER INCOME AND EXPENSES, NET
Other income and expenses, net represent non-operating income and expenses before income taxes. The following table summarizes Potomac Edison’s other income and expenses, net for 2004, 2003 and 2002:
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
NOTE 15: QUARTERLY FINANCIAL INFORMATION (Unaudited)
*
Amounts may not total to year to date results due to rounding.
NOTE 16: LETTERS OF CREDIT
Potomac Edison had two letters of credit outstanding at December 31, 2004 for an aggregate amount of approximately $9.7 million. Of this amount, $9.5 million was issued under the New Loan Facilities to support an energy conservation contract. This letter of credit expires in July 2005. The remaining $0.2 million represented a letter of credit issued by a bank that is not a lender under the New AE Facility to support a property purchase. This letter of credit was uncollateralized and expired in the first quarter of 2005.
NOTE 17: VARIABLE INTEREST ENTITIES
Potomac Edison adopted FASB’s Interpretation No. 46 (Revised December 2003), “Consolidation of Variable Interest Entities” (“FIN 46R”), as of March 31, 2004. FIN 46R requires Potomac Edison to consolidate entities or contracts that represent a variable interest in a variable interest entity (“VIE”) if Potomac Edison is determined to be the primary beneficiary of the VIE.
Potomac Edison determined that it has a long-term electricity purchase contract with an unrelated independent power producer (“IPP”) that represents a variable interest under FIN 46R. Potomac Edison continues to pursue, but has been unable to obtain, certain information from the IPP necessary to determine if the VIE should be consolidated under FIN 46R.
Potomac Edison purchased power for 2004 from the IPP in the amount of $93.6 million. Potomac Edison recovers the full amount, of the cost of the applicable power contract in their rates charged to consumers. Potomac Edison is not subject to any risk of loss associated with the applicable VIE, because they do not have any obligation to the IPP other than to purchase the power that the VIE produces according to the terms of the applicable electricity purchase contract.
NOTE 18: COMMITMENTS AND CONTINGENCIES
Construction and Capital Program
Potomac Edison has entered into commitments for its capital programs for which expenditures are estimated to be $72.4 million for 2005 and $75.8 million for 2006.
Environmental Matters and Litigation
Potomac Edison is subject to various laws, regulations and uncertainties as to environmental matters. Compliance may require Potomac Edison to incur substantial additional costs to modify or replace existing and proposed equipment and facilities that may adversely affect the cost of future operations.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA) Claim: On March 4, 1994, Potomac Edison and certain affiliated companies received notice that the EPA had identified them as potentially responsible parties (“PRPs”) with respect to the Jack’s Creek/Sitkin Smelting
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Superfund Site. Initially, approximately 175 PRPs were involved, however, the current number of active PRPs has been reduced as a result of settlements with de minimis contributors and other contributors to the site. The costs of remediation will be shared by all past and active responsible parties. In 1999, a PRP group that included Potomac Edison and certain affiliated companies entered into a consent order with the EPA to remediate the site. It is currently estimated that the total remediation costs to be borne by all of the responsible parties will not exceed $30.0 million. Potomac Edison has an accrued liability of $0.2 million representing its estimated share of the remediation costs at December 31, 2004.
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 contractor employees and do not involve allegations of either the manufacture, sale or distribution of asbestos-containing products by Allegheny. These asbestos suits arise out of historical operations and are related to the installation and removal of asbestos-containing materials at Allegheny’s generation facilities. Allegheny’s historical operations were insured by various foreign and domestic insurers, including Lloyd’s of London. Asbestos-related litigation expenses have to date been reimbursed in full by recoveries from its historical insurers, and Allegheny believes that it has sufficient insurance to respond fully to the asbestos suits. Certain insurers, however, have contested their obligations to pay for the future defense and settlement costs relating to the asbestos suits. Allegheny is currently involved in two asbestos insurance-related actions, Certain Underwriters at Lloyd’s, London et al. v. Allegheny Energy, Inc. et al., Case No. 21-C-03-16733 (Washington County, Md.), and Monongahela Power Company et al. v. Certain Underwriters at Lloyd’s, London and London Market Companies, et al., Civil Action No. 03-C-281 (Monongalia County, W. Va.). The parties in these actions are seeking an allocation of responsibility for Allegheny’s historic asbestos liability.
During the pendency of these actions, Allegheny will continue to receive payments from one of its insurance companies in the amount of $625,000, payable on each of July 1, 2005 and 2006. During 2004 and 2003, Allegheny received insurance recoveries of approximately $960,000 and $1.8 million, respectively, in connection with these cases. Allegheny does not believe that the existence or pendency of either the asbestos suits or the actions involving its insurance will have a material impact on its consolidated financial position, results of operations or cash flows. Allegheny believes that it has established adequate reserves, net of insurance receivables and recoveries, to cover existing and future asbestos claims. As of December 31, 2004, Allegheny had 1,504 open cases remaining. Allegheny intends to vigorously defend against these actions but cannot predict their outcomes.
Ordinary Course of Business: Potomac Edison is, from time to time, involved in litigation and other legal disputes in the ordinary course of business. Potomac Edison is of the belief that there are no other legal proceedings that could have a material adverse effect on its business or financial condition.
Leases
Potomac Edison has capital and operating lease agreements with various terms and expiration dates, primarily for vehicles and computer equipment.
Total capital and operating lease rent payments of $4.7 million in 2004, $5.5 million in 2003 and $6.6 million in 2002 were recorded as rent expense in accordance with SFAS No. 71. Potomac Edison’s estimated future minimum lease payments for operating leases, including leases entered into by AESC which are allocated
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
to Potomac Edison, with annual payments exceeding $100,000 and initial or remaining lease terms in excess of one year are as follows:
The carrying amount of equipment recorded under capitalized lease agreements included in “Property, plant and equipment, net” was $8.6 million and $11.1 million at December 31, 2004 and 2003, respectively.
PURPA
Under PURPA, electric utility companies, such as Potomac Edison, are required to interconnect with, provide back-up electric service to and purchase electric capacity and energy from qualifying power production and cogeneration facilities that satisfy the eligibility requirements for PURPA benefits established by FERC. The appropriate state public service commission or legislature establishes the rates paid for electric energy purchased from qualifying facilities.
Potomac Edison is committed to purchase the electrical output from 180 megawatts of qualifying PURPA capacity from the AES Warrior Run cogeneration facility. Payments for PURPA capacity and energy in 2004, 2003 and 2002 totaled $93.6 million, $95.2 million and $91.8 million, respectively. The average cost to Potomac Edison of these power purchases was approximately 6.7 cents per kilowatt-hour (“kWh”), 6.6 cents per kWh and 6.4 cents per kWh for 2004, 2003 and 2002, respectively. Potomac Edison is currently authorized to recover these costs in its retail rates as described below.
As a result of the 1999 Maryland restructuring settlement, AES Warrior Run capacity and energy must be offered into the wholesale market over the life of the applicable PURPA contract. In November 2001, the Maryland PSC approved a power sales agreement between Potomac Edison and AE Supply, the winning bidder, covering the sale of the AES Warrior Run output to the wholesale market for the period January 1, 2002 through December 31, 2004. The Warrior Run agreement between Potomac Edison and AE Supply expired on December 31, 2004 and Potomac Edison awarded a new contract to a non-affiliated company. The cost of purchases from AES Warrior Run under the PURPA contract not recovered through the market sale of the output are recovered, dollar-for-dollar, from Maryland customers through a retail revenue surcharge.
The table below reflects Potomac Edison’s estimated commitments for energy and capacity purchases under PURPA contracts as of December 31, 2004. Actual values can vary substantially depending upon future conditions.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of The Potomac Edison Company:
In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of operations, stockholder’s equity and cash flows present fairly, in all material respects, the financial position of The Potomac Edison Company and its subsidiaries (the “Company”) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in Item 15 presents 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 schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
March 10, 2005
I TEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ALLEGHENY GENERATING COMPANY
Statements of Operations
See accompanying Notes to Financial Statements.
ALLEGHENY GENERATING COMPANY
Statements of Cash Flows
See accompanying Notes to Financial Statements.
ALLEGHENY GENERATING COMPANY
Balance Sheets
See accompanying Notes to Financial Statements.
ALLEGHENY GENERATING COMPANY
Balance Sheets-(Continued)
See accompanying Notes to Financial Statements.
ALLEGHENY GENERATING COMPANY
Statements of Stockholders’ Equity
See accompanying Notes to Financial Statements.
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION
Allegheny Energy Supply Company, LLC (“AE Supply”) and Monongahela Power Company (“Monongahela”), (together, the “Parents”), own 100% of Allegheny Generating Company (“AGC”). AE Supply owns 77.03% and Monongahela owns 22.97% of AGC. The Parents are subsidiaries of Allegheny Energy, Inc. (“AE”, and collectively with AE’s consolidated subsidiaries, “Allegheny”), a diversified utility holding company whose principal business segments are the Generation and Marketing segment and the Delivery and Services segment. The Generation and Marketing segment includes AE Supply, AGC and Monongahela’s generation of electricity for its West Virginia customers, which has not deregulated electric generation. AGC owns an undivided 40% interest (985 megawatts (“MW”)) in the 2,463 MW pumped storage, hydroelectric station in Bath County, Virginia, operated by the 60% owner, Virginia Electric and Power Company, a nonaffiliated utility. AGC sells its generation capacity to its Parents. AGC operates under a single business segment, Generation and Marketing.
AGC is subject to regulation by the Securities and Exchange Commission (“SEC”), the Virginia State Corporation Commission and the Federal Energy Regulatory Commission (“FERC”).
Allegheny Energy Services Corporation (“AESC”) is a wholly owned subsidiary of AE that employs substantially all of the people who work at AGC. As of December 31, 2004, AESC employed approximately 5,100 employees, of which approximately 1,530 are subject to collective bargaining arrangements.
NOTE 2: BASIS OF PRESENTATION
Significant accounting policies of AGC are summarized below.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles used in the United States of America (“GAAP”) requires AGC to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingencies during the reporting period. On a continuous basis, AGC evaluates its estimates, including those related to the calculation of the provisions for depreciation and amortization, regulatory assets, income taxes, pensions and other postretirement benefits and contingencies related to environmental matters and litigation. AGC bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.
Revenues
Revenues are determined under a “cost-of-service” formula wholesale rate schedule approved by FERC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment. All sales of AGC are made to AE Supply and Monongahela.
Debt Issuance Costs
Costs incurred to issue debt are recorded as deferred charges on the Balance Sheets. These costs are amortized over the term of the related debt instrument using the effective interest method.
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
Property, Plant, and Equipment
Property, plant and equipment are stated at original cost and consist of a 40% undivided interest in the Bath County pumped-storage hydroelectric station and its connecting transmission facilities. Upon retirement, the cost of depreciable property, plus removal costs less salvage, are charged to accumulated depreciation in accordance with the provisions of Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS No. 71”).
Long-Lived Assets
Long-lived assets owned by AGC are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable through operations, in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets” (“SFAS No. 144”). If the carrying amount of the asset exceeds the expected undiscounted future cash flows generated by the asset, an impairment loss is recognized, and the asset is written down to its fair value. Fair value is determined by the use of quoted market prices, appraisals, or the use of other valuation techniques, such as expected discounted future cash flows.
Depreciation and Maintenance
Depreciation expense is determined generally on a straight-line method based on the estimated service lives of depreciable properties and amounted to approximately 2.1% of average depreciable property in 2004, 2003 and 2002. Estimated service lives for generation, Transmission and Distribution and other property are as follows:
Maintenance expenses represent costs incurred to maintain the power station and general plant. These expenses reflect routine maintenance of equipment, as well as planned repairs and unplanned expenditures, primarily from forced outages at the power station. Maintenance costs are expensed as incurred.
Intangible Assets
AGC has intangible assets consisting of amortized land easements, which are included in property, plant and equipment on the Balance Sheets, with a gross carrying amount of $1.6 million and accumulated amortization of $0.8 million at both December 31, 2004 and 2003, respectively.
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
Intercompany Transactions
AGC has various operating transactions with its affiliates. AGC’s policy is that the affiliated receivable and payable balances outstanding from these transactions are presented on a net basis on the Balance Sheets and the Statements of Cash Flows.
Substantially all of the employees of Allegheny are employed by AESC, which performs services at cost for AGC and its affiliates in accordance with the Public Utility Holding Company Act of 1935. AGC is responsible for its proportionate share of services provided by AESC. Total billings by AESC (including capital) to AGC for 2004 were not material. Total billings by AESC (including capital) to AGC for 2003 and 2002 were $0.2 million for each year.
Pursuant to an agreement, AE Supply and Monongahela purchase all of AGC’s capacity in the station priced under a “cost-of-service formula” wholesale rate schedule approved by FERC. Under this arrangement, AGC recovers in revenues all of its operations and maintenance expense, depreciation, taxes other than income taxes, income tax expense at the statutory rate and a component for debt and equity return on its investment. AE Supply and Monongahela purchase power from AGC on a proportional basis, based on their respective equity ownership of AGC.
AE and its subsidiaries, including AGC, file a consolidated federal income tax return. The consolidated income tax liability is 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. In accordance with this consolidated tax sharing agreement, there may be intercompany receivable and payable balances among or between the various registrants at any period. These balances may also be current or non-current, depending on the nature of the asset or liability, income or expense that gave rise to the intercompany balance. Income taxes payable to affiliate, including both short and long-term obligations, at December 31, 2004 and 2003, were $20.3 million and $21.1 million, respectively.
An internal money pool accommodates intercompany short-term borrowing needs to the extent that certain of AE’s subsidiaries have funds available. The money pool provides funds to approved AE subsidiaries at the lower of the previous day’s Federal Funds Effective Interest Rate, as quoted by the Federal Reserve, or the previous day’s seven day commercial paper rate, as quoted by the same source, less four basis points. AGC can only borrow money from the money pool. At December 31, 2004 and 2003, AGC did not have any outstanding borrowings from the money pool.
At December 31, 2004 and 2003, AGC had notes payable to its parent of $15.0 million and $30.0 million, respectively. See Note 3, “Capitalization,” for information regarding AGC’s affiliated debt.
At December 31, 2004 AGC had net accounts payable to affiliates of $0.5 million. At December 31, 2003, AGC had net accounts receivable from affiliates of $1.0 million.
Cash Equivalents
For purposes of the Statements of Cash Flows and Balance Sheets, temporary cash investments with original maturities of three months or less, generally in the form of commercial paper, certificates of deposit, repurchase agreements and money market funds, are considered to be the equivalent of cash.
Regulatory Assets and Liabilities
Under cost-based regulation, regulated enterprises generally are permitted to recover their operating expenses and earn a reasonable return on their utility investment.
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
AGC accounts for its regulated operations under the provisions of SFAS No. 71. The economic effects of regulation can result in a regulated company recording costs 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 would be charged to expense by an unregulated enterprise. Accordingly, AGC 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 Balance Sheets as current and non-current “Regulatory assets” and “Regulatory liabilities.” AGC periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. See Note 9, “Regulatory Assets and Liabilities,” for additional details.
Inventory
AGC values materials and supplies inventory using an average cost method.
Income Taxes
Book income differs from taxable income principally because certain income and deductions for tax purposes are recorded in the financial income statement in different periods. Deferred income tax assets and liabilities represent the tax effect of certain temporary differences between the book and tax basis of assets and liabilities computed using the most current tax rates. See Note 6, “Income Taxes,” for additional information.
AGC joins with AE and its affiliates in filing a consolidated federal income tax return. The consolidated income tax liability is 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.
AGC has deferred the tax benefit of investment tax credits, which are amortized over the estimated service lives of the related property, plant and equipment.
Allegheny’s consolidated federal income tax returns through 1997 have been examined by the Internal Revenue Service (“IRS”) and settled. The IRS is currently examining Allegheny’s consolidated federal income tax returns for 1998 through 2003. Management believes that its accrued tax liabilities are adequate and that any settlement related to such examination is not expected to have a material impact on Allegheny’s consolidated statement of operations, financial position or cash flow.
Pension and Other Postretirement Benefits
AE and its subsidiaries have noncontributory, defined benefit pension plans covering substantially all employees, including officers. Benefits are based on each employee’s years-of-service and compensation. The funding policy is to contribute annually at least the minimum amount required under the Employee Retirement Income Security Act of 1974 and not more than can be deducted for federal income tax purposes. Plan assets consist of equity securities, fixed-income securities and short-term investments.
AE’s subsidiaries also provide partially contributory medical and life insurance plans for eligible retirees and dependents. Medical benefits, which make up the largest component of the plans, are based upon an age and years-of-service vesting schedule and other plan provisions. Subsidized medical coverage is not provided in retirement to employees hired on or after January 1, 1993. Funding of these benefits is made primarily into Voluntary Employee Beneficiary Association trust funds. The funding policy is to contribute amounts that can be deducted for federal income tax purposes. Medical benefits are self-insured.
Through AESC, AGC is responsible for its proportionate share of postretirement benefit costs.
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
NOTE 3: CAPITALIZATION
AGC’s capital structure, including short-term debt, as of December 31, 2004 and 2003, was as follows:
On October 8, 2002, Allegheny announced that AE, AE Supply and AGC were in default under their principal credit agreements after AE Supply declined to post additional collateral in favor of several trading counterparties. The collateral calls followed the downgrading of Allegheny’s credit rating below investment grade by Moody’s. AGC was a participant in these principal credit agreements through Allegheny. During the period November 2002 through February 2003, AE, AE Supply and AGC obtained waivers of, and amended, certain covenants to these principal credit agreements.
On February 25, 2003, AE Supply provided AGC with a note of $55.0 million in order for AGC to repay amounts outstanding under its principal credit agreements. As of December 31, 2004 and 2003, the outstanding amounts due to AE Supply under this note were $15.0 million and $30.0 million, respectively. On September 1, 2003, AGC received an equity contribution of $40.0 million from AE Supply and Monongahela. This equity contribution was used to repay $50.0 million of 5 5/8% debentures, which matured on September 1, 2003. AE Supply and Monongahela may continue to provide assistance with AGC’s obligations as they come due.
The SEC has granted approval to AGC to allow it to pay common dividends out of other paid-in capital.
AGC had debt outstanding as follows:
2004 Issuances and Redemptions
AGC repaid $15.0 million of its long-term note payable to AE Supply during 2004.
2003 Issuances and Redemptions
AGC did not issue any debt during 2003 and redeemed $50.0 million of 5 5/8% debentures, which matured September 1, 2003.
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
NOTE 4: RESTRUCTURING CHARGES AND WORKFORCE REDUCTION EXPENSES
In July 2002, Allegheny announced a restructuring plan to reduce long-term expenses. The restructuring activities included a company-wide workforce reduction and a reorganization of Allegheny’s energy trading division. For the year ended December 31, 2002, Allegheny recorded a charge for the restructuring and workforce reduction of $107.3 million, before income taxes ($64.6 million, net of income taxes).
Allegheny has achieved workforce reductions of approximately 10% primarily through a voluntary early retirement option (“ERO”) program and selected staff reductions. The ERO program offered enhanced pension and medical benefits. The costs for the workforce reduction under the ERO program were determined in accordance with SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” For the year ended December 31, 2002, approximately 600 eligible employees accepted the ERO program, resulting in a charge of $82.3 million, before income taxes ($49.3 million, net of income taxes). Allegheny also offered a Staffing Reduction Separation Program for employees whose positions were being eliminated as part of the workforce reductions and severance for certain energy trading employees. The severance and other employee-related costs were accounted for in accordance with EITF No. 94-3. “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” For the year ended December 31, 2002, Allegheny recorded a charge of $25.0 million, before income taxes ($15.3 million, net of income taxes) related to approximately 80 employees whose positions have been eliminated. Allegheny has completed these planned workforce reductions. Workforce reduction costs are recorded in “Workforce reduction expenses” on the Consolidated Statements of Operations. For the year ended December 31, 2002, AGC recorded an immaterial charge for its allocable share of the workforce reduction expenses.
NOTE 5: ASSET RETIREMENT OBLIGATIONS (“ARO”)
Effective January 1, 2003, AGC adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS No. 143 requires that the fair value of asset retirement costs for which AGC has a legal obligation be recorded as liabilities, with an equivalent amount added to the asset cost. The liability is accreted (increased) to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or records a gain or loss if it is settled at a different amount.
The effect of adopting SFAS No. 143 on AGC’s Financial Statements in 2003 was not material.
NOTE 6: INCOME TAXES
Details of federal and state income tax expense (benefit) are:
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
The total provision for income tax expense differs from the amount produced by applying the federal statutory income tax rate of 35% to financial accounting, as set forth below:
At December 31, the deferred income tax assets and liabilities consisted of the following:
AGC is a party to a consolidated tax sharing agreement, which was amended July 1, 2003. AGC expects to realize benefits represented by deferred tax assets through its participation in the consolidated tax return in future years.
NOTE 7: SHORT-TERM DEBT
There was no short-term debt outstanding as of December 31, 2004 or 2003. Average amounts for short-term debt outstanding during 2004 and 2003 consisted of:
To provide interim financing and support for outstanding commercial paper, Allegheny and its subsidiaries, including AGC, had established lines of credit with several banks. The lines of credit had fee arrangements and
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
no compensating balance requirements. These facilities, which were refinanced in February 2003, required the maintenance of a certain fixed-charge coverage ratio and a maximum debt-to-capitalization ratio, as defined under the agreements.
AGC has SEC authorization for total short-term borrowings, from all sources, of $100 million.
NOTE 8: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
As described in Note 2, “Basis of Presentation,” AGC is responsible for its proportionate share of the net periodic cost for pension and postretirement benefits other than pensions (principally health care and life insurance) for employees and covered dependents provided by AESC. AGC’s share of these costs was not material for the years ended December 31, 2004, 2003 and 2002, respectively.
The assumptions used to determine net periodic benefit costs for years ended December 31, 2004, 2003 and 2002 are shown in the table below. The discount rates, expected long-term rates of return on plan assets and rates of compensation increases used in determining net periodic benefit costs were as follows:
The assumptions used to determine benefit obligations at September 30, 2004, 2003 and 2002 and the expected long-term rates of return on plan assets in each of the years 2004, 2003 and 2002 are shown in the table below:
Allegheny’s general approach for determining the overall expected long-term rate of return on assets considers historical and expected future asset returns, the current and future targeted asset mix of the plan assets, historical and future expected real rates of return for equities and fixed income securities and historical and expected inflation statistics. The expected long-term rate of return on plan assets to be used to develop net periodic benefit costs for 2005 is 8.5%.
Assumed health care cost trend rates at December 31 are as follows:
For measuring obligations related to postretirement benefits other than pensions, a health care cost trend rate of 9.5% beginning with 2005 and grading down by 0.5% each year to an ultimate rate of 5.0%, and plan
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
provisions that limit future medical and life insurance benefits, were assumed. 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 allocated to AGC.
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) became law. Beginning in 2006, the federal government will provide subsidies for certain drug costs to companies that provide coverage that is actuarially equivalent to the drug coverage under Medicare Part D. Allegheny elected to follow the deferral provisions of FASB Staff Position (“FSP”) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-1”). FSP 106-1 permits employers that provide drug benefits to make a one-time election to defer accounting for any effects of the Medicare Act until guidance on the accounting for the federal subsidy is issued. On May 19, 2004, FASB issued Staff Position FSP FAS 106-2 (“FSP 106-2”), which supercedes FSP 106-1 and provides guidance on accounting for the effects of the new Medicare prescription drug legislation for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Allegheny adopted the provisions of FSP 106-2 as of July 1, 2004. The adoption of FSP 106-2 did not have a significant impact on Allegheny’s accumulated plan benefit obligation or its net periodic postretirement benefit costs.
NOTE 9: REGULATORY ASSETS AND LIABILITIES
AGC’s operations are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenues associated with deferred costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. Regulatory assets and Regulatory liabilities, reflected in the Balance Sheets at December 31 relate to:
NOTE 10: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of long-term debt, at December 31, were as follows:
The fair value of the long-term debt was estimated based on actual market prices or market prices of similar issues. The carrying amounts of cash equivalents and short-term debt approximate the fair values of such financial instruments because of the short maturities of those instruments.
ALLEGHENY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS-(Continued)
NOTE 11: JOINTLY OWNED ELECTRIC UTILITY PLANTS
AGC jointly owns an electric generation facility with a third party. AGC records its proportionate share of operating costs, assets and liabilities related to this generation facility in the corresponding lines in the Financial Statements. As of December 31, 2004 and 2003, AGC’s investment and accumulated depreciation in the Bath County generation station jointly owned with a third party, were as follows:
NOTE 12: QUARTERLY FINANCIAL INFORMATION (Unaudited)
NOTE 13: LETTERS OF CREDIT
AGC had no letters of credit outstanding as of December 31, 2004.
NOTE 14: COMMITMENTS AND CONTINGENCIES
Construction and Capital Program
AGC has entered into commitments for its capital programs for which expenditures are estimated to be $11.7 million for 2005 and $10.0 million for 2006.
Ordinary Course of Business
AGC is, from time to time, involved in litigation and other legal disputes in the ordinary course of business. AGC is of the belief that there are no other legal proceedings that could have a material effect on its business or financial condition.
R eport of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Allegheny Generating Company:
In our opinion, the accompanying balance sheets and the related statements of operations, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of Allegheny Generating Company (the “Company”) at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
March 10, 2005
S-1
SCHEDULE I
AE (Parent Company)
Condensed Financial Statements
See accompanying Notes to Condensed Financial Statements.
AE (Parent Company)
NOTES TO CONDENSED FINANCIAL STATEMENTS
NOTE 1: BASIS OF PRESENTATION
The condensed financial statements represent the financial information required by Securities and Exchange Commission Regulation S-X 210.12-04 for AE, a diversified utility holding company and the parent company of Allegheny Energy, Inc. These financial statements 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, therefore these financial statements should be read in conjunction with the Consolidated Financial Statements and related notes included herein.
AE has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements.
NOTE 2: CAPITALIZATION, COMMITMENTS AND CONTINGENCIES
See Note 3, “Capitalization,” and Note 27, “Commitments and Contingencies,” to Allegheny Energy, Inc.’s Consolidated Financial Statements for a description of AE’s capitalization, commitments and contingencies as of December 31, 2004.
At December 31, 2004, contractual maturities for AE’s long-term debt, for the next five years, excluding unamortized debt discounts and premiums of approximately $6.2 million.
S-
SCHEDULE II
ALLEGHENY ENERGY, INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
For Years Ended December 31, 2004, 2003 and 2002
(a)
Amount accrued to bad debt expense during the year.
(b)
Payment recoveries of bad debt accounts previously written off.
(c)
Uncollectible accounts written off to bad debt expense during the year. In 2004, the amount includes $1,722,744 for uncollectible accounts related to the gas business that have been reclassified to assets held for sale.
(d)
Balance for December 31, 2004 excludes the Allowance for uncollectible accounts for the gas business of $3,525,033. Prior year balances include Allowance for uncollectible accounts for the gas business of $1,626,346 and $1,452,775 for December 31, 2003 and 2002, respectively.
S-3
SCHEDULE II
MONONGAHELA POWER COMPANY AND SUBSIDIARIES
Valuation and Qualifying Accounts
For Years Ended December 31, 2004, 2003 and 2002
(a)
Amount accrued to bad debt expense during the year.
(b)
Payment recoveries of bad debt accounts previously written off.
(c)
Uncollectible accounts written off to bad debt expense during the year. In 2004, the amount includes $1,722,744 for uncollectible accounts related to the gas business that have been reclassified to assets held for sale.
(d)
Balance for December 31, 2004 excludes the Allowance for uncollectible accounts for the gas business of $3,525,033. Prior year balances include Allowance for uncollectible accounts for the gas business of $1,626,346 and $1,452,775 for December 31, 2003 and 2002, respectively.
S-4
SCHEDULE II
THE POTOMAC EDISON COMPANY AND SUBSIDIARIES
Valuation and Qualifying Accounts
For Years Ended December 31, 2004, 2003 and 2002
(a)
Amount accrued to bad debt expense during the year.
(b)
Payment recoveries of bad debt accounts previously written off.
(c)
Uncollectible accounts written off to bad debt expense during the year.
I TEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable.
I TEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures. Each Registrant carried out an evaluation, under the supervision and with the participation of its management, including the its principal executive officer and principal financial officer, of the effectiveness of its disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, as of December 31, 2004 (the “Evaluation Date”). Based on that evaluation, the principal executive officer and principal financial officer of each Registrant have concluded that the applicable Registrant’s disclosure controls and procedures as of December 31, 2004 were effective to ensure that (a) material information relating to each Registrant is accumulated and made known to the Registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure and (b) is recorded, processed, summarized and reported within the time periods specified in SEC’s rules and forms.
It should be noted that any system of controls, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Because of these and other inherent limitations of control systems, there is only reasonable assurance that each Registrant’s controls will succeed in achieving their goals under all potential future conditions.
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.
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, 2004. 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, 2004, AE’s internal control over financial reporting is effective based on those criteria.
Management’s assessment of the effectiveness of AE’s internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that appears herein.
Changes in Internal Control Over Financial Reporting. During the quarter ended December 31, 2004, AE completed its implementation of a new internal control framework that was designed to remediate previously identified material weaknesses in internal controls and comply with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002.
I TEM 9B. OTHER INFORMATION
Not Applicable.
PART III
I TEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Directors of the Registrants
The names, ages and business experience during the past five years of the directors of AE, Monongahela (“MP”), Potomac Edison (“PE”) and AGC and their terms of office are set forth below:
(a)
At AE’s 2004 Annual Meeting of Stockholders, AE’s stockholders voted in favor of a stockholder proposal for the annual election of directors. AE plans to implement the declassification of its board of directors at its 2005 Annual Meeting of Stockholders. The directors who are not up for reelection at that meeting will resign, and each director will stand for reelection in 2005, to serve until AE’s 2006 Annual Meeting of Stockholders and until a successor is duly elected and qualified.
(b)
H. Furlong Baldwin has been a director since November 2003. Mr. Baldwin has been Chairman of the Board of The Nasdaq Stock Market, Inc. (“Nasdaq”) since 2003 and has been a director of Nasdaq since 2000. Mr. Baldwin is also a director of W.R. Grace & Co., Platinum Underwriters Holdings, Ltd. and the Wills Group. From 1976 to 2001, Mr. Baldwin was President and Chief Executive Officer of Mercantile Bankshares Corp. and Mercantile Safe Deposit & Trust Co. Mr. Baldwin is a former director of Mercantile Bankshares Corp., Constellation Energy Group, CSX Corp and the St. Paul Companies, Inc. and a former Governor of the National Association of Securities Dealers, Inc. He is a member and former Chairman of the Johns Hopkins Medicine Board of Trustees and a member (emeritus) of the Johns Hopkins University Board of Trustees.
(c)
Eleanor Baum has been a director since 1988. Dr. Baum has been Dean of the Albert Nerken School of Engineering of The Cooper Union for the Advancement of Science and Art since 1987. Dr. Baum is a director of Avnet, Inc. and United States Trust Company and is past Chair of the Engineering Workforce Commission. Dr. Baum is a Fellow of the Institute of Electrical and Electronic Engineers and past Chairman of the Board of Governors of the New York Academy of Sciences. She is a former President of the Accreditation Board for Engineering and Technology and a former President of the American Society for Engineering Education.
(d)
John P. Campbell has been the President of AE Supply since July 2004. He has also been a director of Monongahela, Potomac Edison and AGC since July 2004. Prior to joining Allegheny, Mr. Campbell was responsible for Mirant Corporation’s worldwide generation portfolio from March 2004 to July 2004. He was Managing Director of Coal-Fired Generation for Reliant Energy, Inc. (“Reliant”) from February 2002 to February 2004. Prior to that, he was the East Region Engineering Director for Reliant. See “Executive Officers of the Registrants” below.
(e)
Paul J. Evanson has been Chairman of the Board, President, Chief Executive Officer and a director of AE since June 2003. Mr. Evanson is the Chair of the Executive Committee. He has also been a director of Monongahela, Potomac Edison and AGC since June 2003. Prior to joining Allegheny, Mr. Evanson was President of Florida Power & Light Company, the principal subsidiary of FPL Group, Inc., and a director of FPL Group, Inc. from 1995 to 2003. Mr. Evanson also is a director of Lynch Interactive Corporation. See “Executive Officers of the Registrants” below.
(f)
Cyrus F. Freidheim, Jr. has been a director since October 2003. Mr. Freidheim has served as Chairman of the Board of Chiquita Brands International, Inc. (“Chiquita”) since 2002 and was Chief Executive Officer of Chiquita from 2002 to 2003. Mr. Freidheim was formerly Vice Chairman of Booz-Allen Hamilton, Inc., at which he also served in various other leadership capacities from 1996 to 2002. Mr. Freidheim also serves as a director of Household International, Inc.
(g)
Julia L. Johnson has been a director since November 2003. Ms. Johnson has been President of NetCommunications, LLC since 2000. She is a director of MasTec and of NorthWestern Corporation. Ms. Johnson is a member of the Department of Energy/National Association of Regulatory Utility Commissioners Energy Market Access Board and the Florida State Board of Education. Ms. Johnson was Senior Vice President of Communications and Marketing for Milcom Technologies from 2000 to 2001. She was Chairman of the Florida Public Service Commission (the “Florida PSC”) from 1997 to 1999 and served as a Commissioner of the Florida PSC from 1992 to 1999.
(h)
Ted J. Kleisner has been a director since 2001. Mr. Kleisner has been President of CSX Hotels, Inc. since 1987 and President of The Greenbrier Resort and Club Management Company since 1989. He is a director of Hershey Entertainment and Resorts Company and the American Hotel and Lodging Association. Mr. Kleisner is a member of the Executive Advisory Board for the Daniels College of Business at the University of Denver and a member of the Boards of Trustees for the Virginia Episcopal School and the Culinary Institute of America.
(i)
Steven H. Rice has been a director since 1986. Mr. Rice has been an attorney and bank consultant for over 15 years. He is a former director of La Jolla Bank and La Jolla Bancorp, Inc., former President of La Jolla Bank, Northeast Region, former President and Chief Executive Officer of Stamford Federal Savings Bank, former President of The Seamen’s Bank for Savings and former director of the Royal Insurance Group, Inc.
(j)
Joseph H. Richardson has been a Vice President of AE and the President and a director of Monongahela and Potomac Edison since August 2003. Mr. Richardson has also been a director of AGC since August 2003. Prior to joining Allegheny, Mr. Richardson served as President and Chief Executive Officer and as a director of Global Energy Group from March 2002 to August 2003. Prior to that, he served as President and Chief Executive Officer and as a director of Florida Power Corporation. See “Executive Officers of the Registrants” below.
(k)
Gunnar E. Sarsten has been a director since 1992. He has been a Consulting Professional Engineer since 1994. He is a former President and Chief Operating Officer of Morrison Knudsen Corporation, former President and Chief Executive Officer of United Engineers & Constructors International, Inc. and former Deputy Chairman of the Third District Federal Reserve Bank in Philadelphia.
(l)
Jeffrey D. Serkes has been Senior Vice President and Chief Financial Officer of AE since July 2003. Mr. Serkes has also been a director of Monongahela, Potomac Edison and AGC since July 2003. Prior to joining Allegheny, Mr. Serkes was President of JDS Opportunities LLC from May 2002 to June 2003. Prior to that, Mr. Serkes was employed with IBM as Vice President, Finance, Sales and Distribution, from June 1999 to May 2002, and Vice President and Treasurer from January 1995 to May 1999. Mr. Serkes also serves as a director and as chair of the audit and compensation committees of Refac, a Delaware corporation. See “Executive Officers of the Registrants” below.
(m)
Michael H. Sutton has been a director since February 2004. Mr. Sutton has been an independent consultant on accounting and auditing regulation since 1999. He is a director of Krispy Kreme Doughnuts, Inc. Mr. Sutton is a former Chief Accountant for the SEC and a former senior partner and National Director of Accounting and Auditing Professional Practice for Deloitte & Touche LLP.
Executive Officers of the Registrants
The names of the executive officers of each Registrant, their ages, the positions they hold, and their business experience during the past five years appear below. All officers of the registrants are elected annually.
Name
Age
AE
MP
PE
AGC
Paul J. Evanson (a)
Chairman, President,
CEO and Director
Chairman, CEO and Director
Chairman, CEO and Director
Chairman, CEO and Director
John P. Campbell (b)
Vice President
Director
Director
Vice President
Director
Edward Dudzinski (c)
Vice President
Vice President
Vice President
Thomas R. Gardner (d)
Vice President, Controller and Chief Accounting Officer
Controller
Controller
Vice President and Controller
Philip L. Goulding (e)
Vice President
Joseph H. Richardson (f)
Vice President
President and Director
President and Director
Director
Jeffrey D. Serkes (g)
Senior Vice President and CFO
Vice President and Director
Vice President and Director
Vice President and
Director
(a)
Paul J. Evanson has been Chairman of the Board, President, Chief Executive Officer and a director of AE since June 2003. Mr. Evanson is the Chair of the Executive Committee. He has also been Chairman, Chief Executive Officer and a director of Monongahela, Potomac Edison and AGC since June 2003. Prior to joining Allegheny, Mr. Evanson was President of Florida Power & Light Company, the principal subsidiary of FPL Group, Inc., and a director of FPL Group, Inc. from 1995 to 2003. Mr. Evanson also is a director of Lynch Interactive Corporation.
(b)
John P. Campbell has been the President of AE Supply since July 2004. He has also been a Vice President of AE, a director of Monongahela and Potomac Edison and a Vice President and director of AGC since July 2004. Prior to joining Allegheny, Mr. Campbell was responsible for Mirant Corporation’s worldwide generation portfolio from March 2004 to July 2004. He was Managing Director, Coal-Fired Generation for Reliant from February 2002 to February 2004. Prior to that, he was the East Region Engineering Director for Reliant.
(c)
Edward Dudzinski has been Vice President, Human Resources, of AE since August 2004. He has also been a Vice President of Monongahela and Potomac Edison 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 DuPont. Prior to that, he served in various other executive and leadership positions at DuPont.
(d)
Thomas R. Gardner has been Vice President, Controller and Chief Accounting Officer of AE since October 2003. He has also been the Controller of Monongahela and Potomac Edison and a Vice President and the Controller of AGC since October 2003. Prior to joining Allegheny, Mr. Gardner was employed with Deloitte & Touche LLP from 1997 to 2003, most recently as a partner.
(e)
Philip L. Goulding has been Vice President, Strategic Planning and Chief Commercial Officer of AE since October 2003. Prior to joining Allegheny, Mr. Goulding led the North American energy practice of L.E.K. Consulting from 1999 to October 2003.
(f)
Joseph. H. Richardson has been a Vice President of AE since August 2003. He has also been the President and a director of Monongahela and Potomac Edison and a director of AGC since August 2003. Prior to joining Allegheny, Mr. Richardson served as President and Chief Executive Officer and as a director of Global Energy Group from March 2002 to August 2003. Prior to that, he served as President and Chief Executive Officer and as a director of Florida Power Corporation.
(g)
Jeffrey D. Serkes has been Senior Vice President and Chief Financial Officer since July 2003. Mr. Serkes has also been a Vice President and director of Monongahela, Potomac Edison and AGC since July 2003. Prior to joining Allegheny, Mr. Serkes was President of JDS Opportunities LLC from May 2002 to June 2003. Prior to that, Mr. Serkes was employed with IBM as Vice President, Finance, Sales and Distribution, from June 1999 to May 2002, and Vice President and Treasurer from January 1995 to May 1999. Mr. Serkes also serves as a director and as chair of the audit and compensation committees of Refac, a Delaware corporation.
Code of Business Conduct and Ethics
In early 2004, Allegheny adopted 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.
Audit Committee Financial Expert
The Board of Directors of AE has determined that one member of its audit committee, Michael H. Sutton, is an audit committee financial expert within the meaning of the SEC’s rules, and is independent within the meaning of Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act. Each of the respective Boards of Directors of AGC, Monongahela and Potomac Edison has determined that it does not have an audit committee financial expert.
Audit Committees of Listed Issuers
The information required to be provided pursuant to Item 401(i) of Regulation S-K with respect to AE is incorporated by reference to “Committees of the Board of Directors-Audit Committee” from AE’s definitive proxy statement to be filed with the SEC. Monongahela is exempt from the audit committee requirements of Rule 10A-3 under the Exchange Act under paragraph (c) of such Rule, which provides certain exemptions, including an exemption for companies that are consolidated subsidiaries of companies that are subject to the rule. Monongahela believes that its reliance on an available exemption from this rule is appropriate given that AE’s audit committee, the members of which meet applicable independence and financial literacy standards, perform an oversight function with respect to certain aspects of AE’s consolidated financial reporting. Potomac Edison and AGC are not listed issuers within the meaning of the SEC’s rules.
Website Access
Allegheny’s Code of Business Conduct and Ethics, its Corporate Governance Guidelines and the Charters for the Audit Committee, Management Compensation and Development Committee and Nominating and Governance Committee of AE’s Board of Directors are available on AE’s website, www.alleghenyenergy.com, in the Corporate Governance section. Amendments to these documents are also available on AE’s website. Copies of each of these documents are available free of charge to any stockholder upon request.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires AE’s directors and executive officers and persons who own more than 10% of a registered class of AE’s equity securities to file with the SEC and the New York Stock Exchange reports on Forms 3, 4 and 5 concerning their ownership of the common stock and other equity securities of AE. Under SEC rules, AE must be furnished with copies of these reports.
Based on AE’s review of these filings, AE believes that all of its directors, executive officers and stockholders who are required to file reports filed all of such reports on a timely basis during the year ended December 31, 2004, except that John Campbell filed one late Form 4 with respect to stock options and stock units granted to him in July 2004, and Mr. Furlong, Dr. Baum, Ms. Johnson, Mr. Kleisner, Mr. Freidheim, Mr. Rice, Mr. Sarsten and Mr. Sutton each filed one late Form 4 in connection with shares of AE common stock issued to them in October 2004 under AE’s Non-Employee Director Stock Plan. AE does not know of any failure by any of these persons to file a report required by Section 16(a) on a timely basis during the prior fiscal year except as otherwise reported in AE’s previous Annual Report on Form 10-K.
I TEM 11. EXECUTIVE COMPENSATION
The annual compensation paid by Allegheny to its Chief Executive Officer and each of its four highest paid executive officers as of December 31, 2004 and to one other individual (collectively, the “named executive officers”) was as follows for 2004 and 2003:
Summary Compensation Table (a)
Annual Compensation
(a)
The individuals appearing in this table performed policy-making functions in 2004. The compensation shown is for all services in all capacities to AE and its subsidiaries. All salaries, annual incentives and long-term payouts of these executives are paid by AESC.
(b)
Positions held in 2004. See “Directors and Executive Officers of the Registrants-Executive Officers of the Registrants” for a description of Allegheny’s current executive officers.
(c)
Incentive awards are based upon performance in the year in which the figure appears, but are paid in the following year, except for $83,333 paid to Mr. Gardner and $350,100 paid to Mr. Hertzog in 2004 based upon performance in 2004.
(d)
Messrs. Evanson, Serkes, Goulding and Richardson entered into employment agreements in 2003, under which they were to be granted stock units to induce them to accept employment at Allegheny. These stock units were granted on February 18, 2004. The amounts shown represent the dollar value of stock units issued under AE’s Stock Unit Plan, based on the closing price of $13.35 per share of AE’s common stock on the New York Stock Exchange on the grant date. Each stock unit represents one share of AE common stock. Holders of stock units are credited with any dividends that would be payable on the shares. On February 18, 2004, 2,049,439 units were granted to Mr. Evanson, 714,795 units were granted to Mr. Serkes, 150,000 units were granted to Mr. Goulding and 109,926 units were granted to Mr. Richardson. One-fifth of Mr. Evanson’s stock units vest on each June 9 from 2004 through 2008. One-third of Mr. Serkes’ stock units
vest on each July 3 from 2004 through 2006. One-fifth of Mr. Goulding’s stock units vest on each October 13 from 2004 through 2008. One-fifth of Mr. Richardson’s units vest on each August 25 from 2004 through 2008. The unvested portion of each stock unit grant is subject to forfeiture upon termination of the holder’s employment with Allegheny.
As of December 31, 2004, based on the closing price of $19.71 per share of AE’s common stock on the New York Stock Exchange on that date, Mr. Evanson held 1,639,551 unvested stock units having an aggregate value of $32,315,550, Mr. Serkes held 476,530 unvested stock units having an aggregate value of $9,392,406, Mr. Goulding held 120,000 unvested stock units having an aggregate value of $2,365,200 and Mr. Richardson held 87,941 unvested stock units having an aggregate value of $1,733,317.
(e)
The figures in this column include the premium paid for the group life insurance plan. In addition, amounts in this column include Allegheny’s contribution for the Employee Stock Ownership and Savings Plan (the “ESOSP”). For 2004, the figures shown include amounts representing the life insurance premiums on Allegheny’s group life insurance plan and ESOSP contributions, respectively, as follows: Mr. Evanson, $3,708 and $3,385; Mr. Serkes, $3,708 and $3,462; Mr. Goulding, $2,981 and $3,269; Mr. Richardson, $2,981 and $4,038; Mr. Gardner, $2,240 and $3,385; and Mr. Hertzog, $3,352 and $0. For 2003, the figures shown include amounts representing the life insurance premiums on the basic group life insurance plan and ESOSP contributions, respectively, as follows: Mr. Evanson, $2,163 and $3,111; Mr. Serkes, $1,854 and $1,962; Mr. Goulding $742 and $0; Mr. Richardson, $1,236 and $462; Mr. Gardner $560 and $0; and Mr. Hertzog, $1,669 and $0.
(f)
Mr. Evanson joined Allegheny on June 16, 2003. The figure in the All Other Compensation column for 2004 includes $96,800 for relocation expenses. The figure in the All Other Compensation column for 2003 includes an initial make-whole payment of $6,300,000 and $92,056 for relocation expenses.
(g)
Mr. Serkes joined Allegheny on July 7, 2003. The figure in the All Other Compensation column for 2004 includes $125,140 for relocation expenses and $1,806 for personal use of a corporate jet. The figure in the All Other Compensation column for 2003 includes an initial make-whole payment of $250,000 and $71,937 for relocation expenses.
(h)
Mr. Goulding joined Allegheny on October 13, 2003. The figure in the All Other Compensation column for 2003 includes an initial make-whole payment of $600,000 and $41,756 for relocation expenses.
(i)
Mr. Richardson joined Allegheny on August 25, 2003. The figure in the All Other Compensation column for 2003 includes $72,628 for relocation expenses.
(j)
Mr. Gardner joined Allegheny on October 13, 2003. The figure in the All-Other Compensation column for 2004 includes $70,502 for relocation expenses. The figure in the All Other Compensation column for 2003 includes a $90,000 sign-on bonus in connection with his employment offer and $8,678 for relocation expenses.
(k)
Mr. Hertzog joined Allegheny on July 28, 2003 and resigned effective December 10, 2004. The figure in the All Other Compensation column for 2004 includes $79,166 for relocation expense, $1,457 for personal use of a corporate jet and $5,250,402 paid in connection with his resignation. Amounts in the All Other Compensation column payable in connection with Mr. Hertzog’s resignation include (a) $800,100 representing a severance payment, (b) $604,167 representing 17 months of accrued pension benefits plus an additional 12 months of pension benefits; (c) $738,000 relating to the cancellation of vested and unvested stock options, based on the difference between an assumed price of AE common stock and the exercise price for 120,000 options (representing 60,000 vested stock options and an additional 60,000 options scheduled to vest on the next vesting date), (d) $3,041,126 relating to the cancellation of vested and unvested stock units based on an assumed market price for 155,955.2 shares of AE common stock (representing 77,977.6 vested stock units and 77,977.6 stock units scheduled to vest on the next vesting date) and (e) other amounts relating to medical insurance and accrued vacation. The figure in the All Other Compensation column for 2003 includes an initial make-whole payment of $800,000 and $71,330 for relocation expenses.
Option Grants in the Last Fiscal Year
The following table sets forth information for each named executive officer with regard to stock options granted in 2004.
(a)
Messrs. Evanson, Serkes, Goulding, Richardson and Gardner entered into employment agreements in 2003, under which they were to be granted stock options to induce them to accept employment at Allegheny. These stock options were granted on February 18, 2004. Mr. Hertzog’s stock options were cancelled in connection with his resignation.
(b)
Based on the closing price of a share of AE’s common stock on the New York Stock Exchange on February 18, 2004.
(c)
The amounts shown are based on the Black-Scholes option-pricing model. For more information regarding the assumptions underlying the determination of grant date present value, see Note 18, “Stock-Based Compensation,” to the Consolidated Financial Statements.
Aggregate Option Exercises in Last Fiscal Year and FY-End Option Values
The following table sets forth information for each named executive officer with regard to stock options held at December 31, 2004. None of the named executive officers exercised options in 2004.
(a)
The amounts shown are based on the closing price of a share of AE’s common stock on the New York Stock Exchange on December 31, 2004, minus the exercise price. All of the options shown on the table above have an exercise price of $13.35 per share.
Group Life Insurance Plan
Allegheny provides life insurance to all eligible employees under a group life insurance plan that pays a death benefit equal to the insured’s base salary, excluding bonuses, during employment, or $25,000 during retirement.
ESOSP
The 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. Each eligible employee can elect to have from 2% to 12% of his or her compensation contributed to the ESOSP on a pre-tax basis and an additional
1% to 6% on a post-tax basis. Participants direct the investment of contributions to specified mutual funds or to investments in AE common stock. Allegheny matches 50% of pre-tax contributions, up to 6% of an employee’s compensation, with common stock of AE. For 2003 and 2004, the maximum amount of compensation to be factored into these calculations was $200,000 and $205,000, respectively. Pre-tax contributions may be withdrawn only if financial hardship requirements are met or employment is terminated.
Retirement Plan
Allegheny maintains a retirement plan covering substantially all employees (the “Retirement Plan”). The Retirement Plan is a noncontributory, trusteed pension plan designed to meet the requirements of Section 401(a) of the Internal Revenue Code of 1986, as amended (the “Code”). Each covered employee is eligible for retirement at normal retirement date (age 65), with early retirement permitted.
Allegheny also maintains a SERP for executive officers and other senior managers. All executive officers, except Messrs. Evanson and Serkes, are participants in the SERP. An officer will be eligible to receive benefits under the SERP only if he or she has been credited with at least 10 years of service with Allegheny and has reached his or her 55th birthday. Under the SERP, an eligible participant will receive a supplemental retirement benefit equal to his or her average compensation multiplied by the sum of: (a) 2% for each year of service up to 25; (b) 1% for each year of service from 25 to 30 and (c) 0.5% for each year of service from 30 to 40, less benefits paid under the Retirement Plan and less 2% for each year that a participant retires prior to his or her 60th birthday. The SERP also provides for use of average compensation in excess of the Code maximums.
A participant’s benefits are capped at 60% of average compensation (including for this purpose retirement benefits paid under the Retirement Plan and benefits payable from other employers), less 2% for each year the participant retires prior to reaching age 60.
The SERP defines average compensation as 12 times the average monthly earnings, including overtime and other salary payments actually earned, whether or not payment is deferred, for the 36 consecutive calendar months constituting the period of highest average monthly salary, together with 100% of the actual award paid under the Annual Incentive Plan.
The following table shows estimated maximum annual benefits payable to participants in the SERP following retirement (assuming payments on a normal life annuity basis and not including any survivor benefit) to an employee in specified remuneration and years of credited service classifications. These amounts are based on an estimated average compensation, retirement at age 65, without consideration of any effect of various options which may be elected prior to retirement. The benefits under the SERP are not subject to any deduction for Social Security or any other offset amounts.
PENSION PLAN TABLE
(a)
The earnings of Messrs. Goulding, Richardson and Gardner covered by the SERP correspond substantially to the amounts shown for them in the Summary Compensation Table.
(b)
As of December 31, 2004, Messrs. Goulding, Richardson and Gardner each had been credited with one full year of service. Following five years of service, Messrs. Goulding, Richardson and Gardner will be credited with an additional five years under the SERP. Following ten years of service, Messrs. Goulding Richardson and Gardner will be credited with a further five years under the SERP.
Early Retirement Option Program
In August 2002, and again in March and April 2003, AE offered a voluntary early retirement program (the “ERO”) to the executive officers and other employees who would be age 50 or older as of October 1, 2003. The ERO provided AE with the right to designate a retirement date for each electing employee between June 1, 2003 and January 1, 2005. A number of Allegheny’s executive officers and other employees opted to retire under the ERO.
Annual Incentive Plan
The Annual Incentive Plan (the “AIP”), which was approved by AE’s stockholders at the 2004 Annual Meeting, was established to: (a) recognize and reward executives who have contributed significantly to Allegheny’s success and to their respective business units; (b) align the corporate vision, goals and business strategy with compensation strategy and (c) provide a compensation environment that will attract, motivate and retain executives. The Management Compensation and Development Committee (the “Committee”) established a target award level for each participant. Each award is conditioned on Allegheny’s achievement of the performance threshold established by the Committee and the achievement of other financial, operational and corporate objectives. Each participant’s award is adjusted based on individual performance, but in no case may a participant’s award exceed 200% of his or her target award level.
The target awards for 2004 under the AIP were determined by the Committee. Participants could earn from zero to 200% of the target award. For 2004, the targets were $927,000 for Mr. Evanson and from $120,000 to $500,000 for the other named executive officers. Targets for other participants were up to $120,000, or up to approximately 40% of 2004 base salary. AIP awards are paid in the year after the year for which they are granted.
Certain executive officers were granted awards for 2003 under the provisions of their employment agreements. Awards earned for performance in 2003 and 2004 are disclosed in the Summary Compensation Table for the individuals named.
Long-Term Incentive Plan
AE’s Board of Directors and stockholders approved the 1998 Long-Term Incentive Plan (the “LTIP”) to assist Allegheny in attracting and retaining key employees and directors and motivating performance. The LTIP is administered by the Committee, which may delegate to an executive officer the power to determine the employees (other than himself or herself) eligible to receive awards. The Committee may from time to time designate key employees and directors to participate in the LTIP for a particular year. The number of shares of AE common stock initially authorized for issuance under the LTIP is 10 million, subject to adjustments for recapitalizations or other changes to AE’s common shares. No participant in the LTIP may be granted more than 600,000 shares (or rights or options in respect of more than 600,000 shares) in any calendar year. For purposes of this limit, shares subject to an award that is to be earned over a period of more than one calendar year will be allocated to the first calendar year in which the shares may be earned. The LTIP will terminate on May 14, 2008.
Stock Option Awards
The LTIP permits awards of options to purchase AE common stock on terms and conditions determined by the Committee. Stock options are issued at strike prices equal to the fair market value (as defined in the LTIP) of AE common stock as of the date of the option grant. The terms of option awards are set forth in option award agreements. The Committee may award non-qualified stock options or incentive stock options (each as defined in the LTIP). No participant in the LTIP may receive incentive stock option awards under the LTIP or any other Allegheny compensation plan that would result in incentive stock options to purchase shares of AE common stock with an aggregate fair market value of more than $100,000 first becoming exercisable by the participant in any one calendar year.
Options awarded under the LTIP will terminate upon the first to occur of: (a) the option’s expiration under the terms of the related option award agreement; (b) termination of the award following termination of the participant’s employment under the rules described in the next paragraph or (c) 10 years after the date of the option grant. The Committee may accelerate the exercise period of awarded options and may extend the exercise period of options granted to employees who have been terminated.
In the event of the termination of employment of a participant in the LTIP, options not exercisable at the time of the termination will expire as of the date of the termination, and exercisable options will expire 90 days from the date of termination. In the event of termination of a participant’s employment due to retirement or disability, options not exercisable will expire as of the date of termination, and exercisable options will expire one year after the date of termination. In the event of the death of a participant in the LTIP, all options not exercisable at the time of death will expire, and exercisable options will remain exercisable by the participant’s beneficiary until the first to occur of one year from the time of death or, if applicable, one year from the date of the termination of the participant’s employment due to retirement or disability.
The Committee may establish dividend equivalent accounts with respect to awarded options. A participant’s dividend equivalent account will be credited with notional amounts equal to dividends that would be payable on the shares for which the participant’s options are exercisable, assuming that the shares were issued to the participant. The participant or other holder of the option will be entitled to receive cash from the dividend equivalent account at the time or times and subject to the terms and conditions as the Committee determines and provides in the applicable option award agreement. If an option terminates or expires prior to exercise, the dividend equivalent account related to the option will be concurrently eliminated and no payment in respect of the account will be made.
The Committee may permit the exercise of options or the payment of applicable withholding taxes through tender of previously acquired shares of AE common stock or through reduction in the number of shares issuable upon option exercise. The Committee may grant reload options to participants in the event that participants pay option exercise prices or withholding taxes by these methods.
In the event of a change of control of Allegheny (as defined in the LTIP), unless provided to the contrary in the applicable option award agreement, all options outstanding on the date of the change in control will become immediately vested and fully exercisable.
Restricted Share Awards
The Committee may grant restricted shares of common stock on terms, conditions and restrictions determined by the Committee. The restrictions, terms and conditions may be based on performance standards, period of service, share ownership or other criteria. Performance-based awards are subject to the same performance targets as described under “Performance Awards” below. The terms of restricted stock awards are set forth in award agreements. No restricted share awards were issued under the LTIP in 2004.
Performance Awards
The Committee may grant performance awards, which will consist of a right to receive a payment that is either measured by the fair market value of a specified number of shares of AE common stock, increases in the fair market value of AE common stock during an award period and/or consists of a fixed cash amount. Performance awards may be made in conjunction with or in addition to restricted stock awards. Award periods are determined by the Committee. The Committee may permit newly eligible participants to receive performance awards after an award period has commenced.
The Committee establishes performance targets in connection with performance awards. In the case of awards intended to be deductible for federal income tax purposes, performance targets generally relate to operating income, return on investment, return on stockholders’ equity, stock price appreciation, earnings before interest, taxes and depreciation/amortization, earnings per share and/or growth in earnings per share. The Committee prescribes formulas to determine the percentage of the awards earned based on the degree to which award targets are achieved. Allegheny may make payments in respect of performance awards in cash, shares of AE common stock or a combination of both.
In the event of a participant’s retirement during an award period, the participant will not receive a performance award unless otherwise determined by the Committee, in which case the participant will be entitled to a prorated portion of the award. In the event of the death or disability of a participant during an award period, the participant or his or her representative will be entitled to a prorated portion of the performance award. A participant will not be entitled to a performance award if his or her employment terminates prior to the conclusion of an award period, provided that the Committee may determine in its discretion to pay performance awards, including full (i.e., non-prorated) awards, to any participant whose employment is terminated. In the event of a change of control of Allegheny, all performance awards for all award periods will immediately become payable to all participants and will be paid within 30 days after the change in control.
The Committee may, unless the relevant award agreement otherwise specifies, cancel, rescind or suspend an award if the LTIP participant engages in competitive activity, discloses confidential information, solicits employees, customers, partners or suppliers of Allegheny or undertakes any other action determined by the Committee to be detrimental to Allegheny. No performance awards were issued under the LTIP in 2004.
Termination of Certain Provisions
Section 162(m) of the Code precludes a public corporation from taking a deduction for compensation in excess of $1 million for its chief executive officer or any of its four other highest paid executive officers, unless certain criteria are satisfied. The LTIP contains provisions intended to ensure that certain restricted share awards and performance awards to “covered employees” under Section 162(m) of the Code are exempt from the $1 million deduction limit contained in that section of the Code. Those exemptive provisions, by their terms and under the applicable IRS regulations, expired as of May 14, 2003. Any pending, but unvested, awards issued under such provisions are unaffected by the provisions’ expiration, but any future restricted stock or performance awards to covered employees will not be eligible for the exemption from the Section 162(m) limit unless the provisions are reapproved by the stockholders. AE may seek stockholder reauthorization of the LTIP with respect to these provisions, but has no present intention to do so. AE may choose alternative methods to compensate covered employees who would have received compensation under the terminated provisions of the LTIP had these provisions not terminated. The Committee will continue to monitor developments and assess alternatives for preserving the deductibility of compensation to the extent reasonably practicable, consistent with the Committee’s compensation policies as determined to be in the best interests of AE and its stockholders.
Stock Unit Plan
The Board of Directors approved the Stock Unit Plan to assist Allegheny in attracting key executives. Allegheny has awarded stock units to certain named executives officers under the terms of their respective employment agreements or employment offers. For more information regarding these grants, see “Summary Compensation Table” above.
Agreements with Certain Executive Officers
Change In Control Contracts
Prior to 2003, AE had change in control agreements with certain executive officers. AE terminated all of these change in control agreements effective December 31, 2003. In 2003 and 2004, AE entered into employment agreements, as discussed below, with newly-appointed executive officers. These employment agreements contain change in control provisions that are discussed in more detail below with respect to some of the named executive officers.
Employment Agreement with Paul J. Evanson
Paul J. Evanson’s employment agreement with AE and AESC has a five-year term that began on June 16, 2003. The agreement provides for a base salary of $900,000, subject to inflation adjustment. Mr. Evanson is eligible to receive annual incentive compensation under the AIP, with a target bonus opportunity of 100% of his base salary and a maximum bonus opportunity of 200% of his base salary. In lieu of benefits under the SERP, Mr. Evanson accrues a lump sum cash payment of $66,667 for each month that he is employed by Allegheny, to be paid on termination of employment.
Pursuant to his employment agreement, on February 18, 2004, Mr. Evanson received a grant of options to purchase 1,500,000 shares of AE’s common stock under the LTIP and 2,049,439 stock units under the provisions of the agreement providing for stock unit grants based in part on AE’s stock price as of specified dates. Mr. Evanson’s employment agreement was amended as of February 18, 2004 to delay the grant date of the stock options from January 2, 2004 until February 18, 2004, which was five business days after receipt of SEC confirmation as to the issuance of these grants. The stock units also were issued on February 18, 2004. One-fifth of the options and units vest on each June 9 from 2004 through 2008, provided Mr. Evanson remains employed by Allegheny on each vesting date. The units are payable in stock on each vesting date. Upon the occurrence of a change in control of AE, or termination of Mr. Evanson’s employment without cause or due to death or disability, all unvested options and stock units will immediately vest.
If Mr. Evanson is terminated without cause (as defined in the agreement) or if Mr. Evanson resigns for good reason (as defined in the agreement) or following certain change in control events, AE will pay Mr. Evanson a cash severance payment equal to three times the sum of his base salary and target bonus amount and his target bonus prorated for that year. AE will also pay Mr. Evanson a cash payment of $4,000,000, representing payments in lieu of benefits under the SERP, calculated as if he had been employed by AE for five years.
Mr. Evanson has agreed to certain confidentiality, non-competition and non-solicitation covenants. His employment agreement provides that Mr. Evanson will be indemnified against costs and liabilities arising from legal proceedings brought against him in relation to his employment and entitles him to gross-up payments in the event his compensation is subject to excise tax.
Employment Agreement with Jeffrey D. Serkes
Jeffrey D. Serkes’ employment agreement with AE and AESC has a three-year term that began on July 7, 2003. The agreement provides for a base salary of $500,000. Mr. Serkes is eligible to receive annual incentive compensation under the AIP, with a target bonus opportunity of 100% of his base salary and a maximum bonus opportunity of 200% of his base salary. In lieu of benefits under the SERP, Mr. Serkes accrues a lump sum cash payment of $41,667 for each month employed by Allegheny, to be paid at age 55 or earlier, if specified events occur.
Pursuant to his employment agreement, on February 18, 2004, Mr. Serkes received a grant of options to purchase 550,000 shares of AE’s common stock under the LTIP and 714,795 stock units under the provisions of the agreement providing for stock unit grants based in part on AE’s stock price as of specified dates. Mr. Serkes’
employment agreement was amended as of February 18, 2004 to delay the grant date of the stock options from January 2, 2004 until February 18, 2004, which was five business days after receipt of SEC confirmation as to the issuance of these grants. The stock units also were issued on February 18, 2004. One-third of the options and units vest on each July 3 from 2004 through 2006, provided Mr. Serkes remains employed by Allegheny on each vesting date. The units are payable in stock on each vesting date. Upon the occurrence of a change in control of AE, or termination of Mr. Serkes’ employment without cause or due to death or disability, all unvested options and stock units will immediately vest.
If Mr. Serkes is terminated without cause (as defined in the agreement) or if Mr. Serkes resigns for good reason (as defined in the agreement) or following certain change in control events, AE will pay Mr. Serkes a cash severance payment up to three times the sum of his base salary and target bonus amount, his target bonus prorated for that year and a cash payment equal to the greater of $1,500,000 and his accrued payment in lieu of benefits under the SERP.
Mr. Serkes has agreed to certain confidentiality, non-competition and non-solicitation covenants. His employment agreement provides that Mr. Serkes will be indemnified against costs and liabilities arising from legal proceedings brought against him in relation to his employment and entitles him to gross-up payments in the event his compensation is subject to excise tax.
Employment Agreement with Philip L. Goulding
Philip L. Goulding’s employment agreement with AE and AESC has a five-year term that began on October 13, 2003. The agreement provides for a base salary of $400,000. Mr. Goulding will be eligible to receive an annual incentive compensation under the AIP, with a target bonus opportunity of 75% of his base salary and a maximum bonus opportunity of 150% of his base salary. Mr. Goulding is eligible to participate in the SERP.
Pursuant to his employment agreement, on February 18, 2004, Mr. Goulding received a grant of options to purchase 746,403 shares of AE’s common stock under the LTIP and 150,000 stock units under the provisions of the agreement providing for stock unit grants based in part on AE’s stock price as of specified dates. One-fifth of the options and units vest on each October 13 from 2004 through 2008, provided Mr. Goulding remains employed by Allegheny on each vesting date. The units are payable in stock on each vesting date. Upon the occurrence of a change in control of AE, or termination of Mr. Goulding’s employment without cause or due to death or disability, all unvested options and stock units will immediately vest.
If Mr. Goulding is terminated without cause (as defined in the agreement) or is required to relocate, or if, following certain change in control events, Mr. Goulding resigns for good reason (as defined in the agreement), AE will pay Mr. Goulding a cash severance payment up to three times the sum of his base salary and target bonus amount and his target bonus prorated for that year and will credit Mr. Goulding for additional specified years for the purpose of determining benefits under the SERP.
Mr. Goulding has agreed to certain confidentiality, non-competition and non-solicitation covenants. His employment agreement provides that Mr. Goulding will be indemnified against costs and liabilities arising from legal proceedings brought against him in relation to his employment and entitles him to gross-up payments in the event his compensation is subject to excise tax.
Employment Agreement with Joseph H. Richardson
Joseph H. Richardson’s employment agreement with AE and AESC has a three-year term that began on August 25, 2003, subject to successive one-year renewals. The agreement provides for a base salary of $400,000. Mr. Richardson is eligible to receive annual incentive compensation under the AIP with a target bonus opportunity of 50% of his base salary and a maximum bonus opportunity of 100% of his base salary. Mr. Richardson is eligible to participate in the SERP.
Pursuant to his employment agreement, on February 18, 2004, Mr. Richardson received a grant of options to purchase 200,000 shares of AE’s common stock under the LTIP and 109,926 stock units under the provisions of the agreement providing for stock unit grants based in part on AE’s stock price as of specified dates. Mr. Richardson’s employment agreement was amended as of February 18, 2004 to delay the grant date of the stock options from January 2, 2004 until February 18, 2004, which was five business days after receipt of SEC confirmation as to the issuance of these grants. The stock units also were issued on February 18, 2004. One-fifth of the options and units vest on each August 25 from 2004 through 2008, provided Mr. Richardson remains employed by Allegheny on each vesting date. The units are payable in stock on each vesting date. Upon the occurrence of a change in control of AE, or termination of Mr. Richardson’s employment without cause or due to death or disability, all unvested options and stock units will immediately vest.
If Mr. Richardson is terminated without cause or if, following certain change in control events, Mr. Richardson resigns for good reason (as defined in the agreement), AE will pay Mr. Richardson a cash severance payment up to three times the sum of his base salary and target bonus amount and his target bonus prorated for that year and will credit Mr. Richardson for additional specified years for purposes of determining benefits under the SERP.
Mr. Richardson has agreed to certain confidentiality, non-competition and non-solicitation covenants. His employment agreement provides that Mr. Richardson will be indemnified against costs and liabilities arising from legal proceedings brought against him in relation to his employment and entitles him to gross-up payments in the event his compensation is subject to excise tax.
Agreement with Thomas R. Gardner
The agreement with Thomas R. Gardner provides for a base salary of $300,000. Mr. Gardner is eligible to receive annual incentive compensation under the AIP with a target bonus opportunity of 40% of his base salary and a maximum bonus opportunity of 80% of his base salary. In addition, Mr. Gardner received $83,333 of additional incentive compensation in 2004 based upon the achievement of certain performance targets in 2003. In 2005, Mr. Gardner is eligible to receive up to $83,334 of additional incentive compensation upon the achievement of a specific performance target. Mr. Gardner is eligible to participate in the SERP.
Pursuant to his employment agreement, on February 18, 2004, Mr. Gardner received a grant of options to purchase 248,801 shares of Allegheny’s common stock under the LTIP. One-fifth of the options vest on each October 2 from 2004 through 2008, provided Mr. Gardner remains employed by Allegheny on each vesting date. Upon the occurrence of a change in control of Allegheny, or termination of Mr. Gardner’s employment without cause or due to death or disability, all unvested options will immediately vest.
If Mr. Gardner is terminated following certain change in control events, AE will pay Mr. Gardner a cash severance payment of two times the sum of his base salary and target bonus amount and his target bonus prorated for that year and will credit Mr. Gardner for additional specified years for purposes of determining benefits under the SERP.
Mr. Gardner has agreed to certain confidentiality provisions.
Agreement with David B. Hertzog
David B. Hertzog resigned as Vice President and General Counsel effective December 10, 2004. In connection with his resignation and the termination of his employment agreement, Allegheny agreed to make a $5.6 million payment to him, representing (a) all wages, salary, bonuses, pension and benefit payments and other compensation that were owed to him pursuant to his employment agreement, (b) the value of vested stock options and stock units previously granted to him, (c) his target bonus for 2004 and (d) additional amounts representing separation payments and amounts in respect of Mr. Hertzog’s agreement to cancel any and all of his
rights under his employment agreement. Additional information about this payment is included on the Summary Compensation Table. Mr. Hertzog remains subject to the confidentiality, non-competition and non-solicitation covenants contained in his employment agreement.
Compensation Committee Interlocks and Insider Participation
The members of the Management Compensation and Development Committee of AE’s Board of Directors for the fiscal year ended December 31, 2004 were: Mr. Baldwin (Chair), Mr. Freidheim, Jr., Mr. Kleisner and Mr. Sarsten. There were no interlocking directorships and no insider participation on this committee during the fiscal year ended December 31, 2004.
Compensation of Directors
Effective January 1, 2004, AE’s outside directors receive for all services (a) $25,000 in retainer fees, (b) $1,250 for each Board meeting attended, and (c) $1,250 for each committee meeting attended, except for members of the Audit Committee who received $1,500 for each meeting of the Audit Committee attended. The Chair of the Audit Committee receives an additional fee of $12,500 per year, and the Chairs of the Finance, Management Compensation and Development, and Nominating and Governance Committees each receive an additional fee of $8,000 per year. In addition, in 2004, AE adopted the Non-Employee Director Stock Plan under which AE will issue up to 1,000 shares of AE common stock per quarter to each of its outside directors, as determined by the Board of Directors. Outside directors received 800 shares of AE common stock per quarter in 2004.
Under an unfunded deferred compensation plan, an outside director may elect to defer receipt of all or part of his or her director’s fees for succeeding calendar years. Compensation deferred under this plan is payable in equal annual installments or in a lump sum with accumulated interest when the director ceases to serve on AE’s Board of Directors.
Board Compensation Committee Report on Executive Compensation and Performance Graph
Information responsive to Items 402(k) and 402(l) of Regulation S-K is incorporated by reference to AE’s definitive Proxy Statement for its 2005 Annual Meeting of Stockholders filed with the SEC. In accordance with the rules and regulations of the SEC, this material shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C of the Exchange Act or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, notwithstanding any general incorporation by reference to this Annual Report on Form 10-K into any other filed document.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The table below shows the number of shares of AE common stock that are beneficially owned, directly or indirectly, by: (a) each director and named executive officer of AE, Monongahela, Potomac Edison and AGC, (b) each person believed to own beneficially more than five percent of AE’s outstanding common stock and (c) all directors and executive officers of each such company as a group as of March 7, 2005.
*
Indicates less than one percent.
(a)
The address for each stockholder listed, other than Canyon Capital Advisors, LLC, is: c/o Allegheny Energy, Inc., 800 Cabin Hill Drive, Greensburg, Pennsylvania 15601.
(b)
Includes the following options exercisable within 60 days of March 7, 2005: Mr. Evanson-300,000; Dr. Baum-23,000; Mr. Kleisner-20,000; Mr. Rice-23,000; Mr. Sarsten-23,000; Mr. Serkes-183,333; Mr. Goulding-149,280; Mr. Richardson-40,000; and Mr. Gardner-49,760.
Excludes the following unvested options granted on February 18, 2004: Mr. Evanson-1,200,000; Mr. Serkes-366,667; Mr. Goulding-597,123; Mr. Richardson-160,000; and Mr. Gardner-199,041. The unvested options held by Messrs. Evanson, Goulding and Richardson vest in equal installments annually through 2008. The unvested options held by Mr. Serkes vest in equal installments annually through 2006.
Excludes the following unvested stock units granted on February 18, 2004: Mr. Evanson-1,639,551; Mr. Serkes-476,530; Mr. Goulding-120,000; and Mr. Richardson-87,941. The unvested units held by Messrs. Evanson, Goulding, Richardson and Gardner vest in equal installments annually through 2008. The unvested units held by Mr. Serkes vest in equal installments annually through 2006.
Excludes the following deferred shares of common stock: Mr. Evanson-409,888; Mr. Freidheim-3,200; Mr. Rice-3,200; Mr. Sarsten-3,200; Mr. Sutton-1,600; Mr. Serkes-214,438; and Mr. Richardson-21,985.
(c)
The address of Canyon Capital Advisors, LLC is 9665 Wilshire Boulevard, Suite 200, Beverly Hills, California 90212.
Allegheny Equity Compensation Plan Information
(a)
Includes the LTIP and the Non-Employee Director Stock Plan.
(b)
Includes shares granted to directors under the Non-Employee Director Stock Plan which were deferred.
(c)
Includes the Stock Unit Plan.
(d)
Includes unvested units awarded under the Stock Unit Plan, as well as vested units that were deferred.
For more information regarding these equity compensation plans, see “Executive Compensation” and “Compensation of Directors” above.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
AE and its various subsidiaries, including AE Supply, Monongahela, Potomac Edison, West Penn and AGC and their respective subsidiaries, may enter into various operating transactions with each other. For more information regarding these intercompany transactions, see Note 1, “Summary of Significant Accounting Policies-Intercompany Transactions,” to the Consolidated Financial Statements.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit and Other Fees
Set forth below are fees paid to PwC in respect of audit and audit-related services, and for tax services and other services, rendered in 2004 and 2003. In 2004 and 2003, the only services provided by PwC were audit and audit-related services. All services provided to Allegheny by PwC require the prior review and approval of the Audit Committee.
Audit Fees
Fees and expenses for the audit of the 2004 financial statements and quarterly reviews were $8,421,065, including $2,595,000 paid in 2005. Fees and expenses for the audit of the 2003 financial statements and quarterly reviews were $5,195,000 including $3,604,000 paid in 2004.
Audit-Related Fees
Fees and expenses for audit-related services were $230,163 for 2004, including $138,500 paid in 2005. Fees and expenses for audit-related services in 2004 includes $157,180 that was related to benefit plan audits, and $96,000 of this amount was paid directly by the trust funds for those plans. Fees and expenses for audit-related services in 2004 also includes $54,275 paid for reproduction of certain audit workpapers, $10,600 for certain agreed upon procedures and $8,108 in software license fees. Fees and expenses for audit-related services were $93,520 for 2003, including $41,600 paid in 2004. Of these amounts, $33,100 was related to benefit plan audits and was paid directly by the trust funds for those plans. Audit-related services include assurance and other additional services related to the audit of Allegheny’s financial statements and quarterly reviews.
Tax Fees
There were no fees and expenses for tax advisory, planning and compliance services for 2003 or 2004.
All Other Fees
There were no fees and expenses for other services for 2003 or 2004.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(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 112.
(b)
Exhibits for AE, Monongahela, Potomac Edison and AGC are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO
SECTION 15(d) OF THE EXCHANGE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED
SECURITIES PURSUANT TO SECTION 12 OF THE EXCHANGE ACT
No annual report or proxy material has been sent to security holders for:
Monongahela
Potomac Edison
AGC
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 10, 2005
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.
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Date: March 10, 2005
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. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Date: March 10, 2005
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. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ALLEGHENY GENERATING COMPANY
By:
/s/ PAUL J. EVANSON
(Paul J. Evanson, Chairman and Chief Executive Officer)
Date: March 10, 2005
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. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in Allegheny Energy, Inc.’s Registration Statements on Form S-3 (Nos. 33-36716, 33-57027, 33-49791, 333-41638, 333-49086, 333-56786, 333-82176 and 333-121083) and Allegheny Energy, Inc.’s Registration Statements on Form S-8 (Nos. 333-65657, 333-31610, 33-40432, 333-113660, 333-117117 and 333-119397) of our report dated March 10, 2005 relating to the financial statements, financial statement schedules, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of control over financial reporting, which appears in this Form 10-K. We also hereby consent to the incorporation by reference in Monongahela Power Company’s Registration Statements on Form S-3 (Nos. 333-31493, 33-51301, 33-56262, 033-59131, 333-31493 and 333-38484) and The Potomac Edison Company’s Registration Statements on Form S-3 (Nos. 333-33413, 33-51305 and 33-59493) of our reports dated March 10, 2005 relating to the financial statements and financial statement schedules, which appear in this Form 10-K.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
March 10, 2005
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 JEFFREY D. SERKES, 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, 2004, 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 10, 2005
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Monongahela Power Company, an Ohio corporation, and The Potomac Edison Company, a Maryland and Virginia corporation, do hereby constitute and appoint PAUL J. EVANSON and JEFFREY D. SERKES, and each of them, a true and lawful attorney in his 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, 2004, under the Securities Exchange Act of 1934, as amended, and to any and all amendments, of said companies, 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 ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.
Dated: March 10, 2005
/s/ PAUL J. EVANSON
(Paul J. Evanson)
/s/ JEFFREY D. SERKES
(Jeffrey D. Serkes)
/s/ JOHN P. CAMPBELL
(John P. Campbell)
/s/ JOSEPH H. RICHARDSON
(Joseph H. Richardson)
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of Allegheny Generating Company, a Virginia corporation, do hereby constitute and appoint PAUL J. EVANSON and JEFFREY D. SERKES, and each of them, a true and lawful attorney in his 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, 2004, 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 ratify and confirm all that said attorneys or any one of them shall lawfully do or cause to be done by virtue hereof.
Dated: March 10, 2005
/s/ PAUL J. EVANSON
(Paul J. Evanson)
/s/ JEFFREY D. SERKES
(Jeffrey D. Serkes)
/s/ JOHN P. CAMPBELL
(John P. Campbell)
/s/ JOSEPH H. RICHARDSON
(Joseph H. Richardson)
E-1
EXHIBIT INDEX
(Rule 601(a))
Allegheny Energy, Inc.
E-1 (cont’d.)
EXHIBIT INDEX
(Rule 601(a))
Allegheny Energy, Inc.
E-1 (cont’d.)
EXHIBIT INDEX
(Rule 601(a))
Allegheny Energy, Inc.
E-2
EXHIBIT INDEX
(Rule 601(a))
Monongahela Power Company
E-2 (cont’d.)
EXHIBIT INDEX
(Rule 601(a))
Monongahela Power Company
*
There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the SEC on its request with copies of such Supplemental Indentures.
E-3
EXHIBIT INDEX
(Rule 601(a))
The Potomac Edison Company
E-3 (cont’d.)
EXHIBIT INDEX
(Rule 601(a))
The Potomac Edison Company
*
There are omitted the Supplemental Indentures which do no more than subject property to the lien of the above Indentures since they are not considered constituent instruments defining the rights of the holders of the securities. The Company agrees to furnish the SEC on its request with copies of such Supplemental Indentures.
E-4
EXHIBIT INDEX
(Rule 601(a))
Allegheny Generating Company
E-8 (cont’d.)
EXHIBIT INDEX
(Rule 601(a))
Allegheny Generating Company
*
Incorporated by reference to the designated exhibit to AGC’s registration statement on Form 10, File No. 0-14688.
**
Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a).
***
Incorporated by reference to Forms 8-K of the Company (0-14688) for December 1986, exh. 4(A), and December 1988, exh. 4.1.
****
Incorporated by reference to Form 10-Q of the Company (0-14688) for June 1989, exh. (a).