ITEM 1. BUSINESS
The Company
FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FirstEnergy's principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. These utility operating subsidiaries are referred to throughout as the “Companies.” FirstEnergy's consolidated revenues are primarily derived from electric service provided by its utility operating subsidiaries and the revenues of its other principal subsidiaries: FES; FSG; MYR; and FirstCom. In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FirstEnergy Ventures Corp., FENOC, FirstEnergy Securities Transfer Company, GPU Diversified Holdings, LLC, GPU Telecom Services, Inc., GPU Nuclear, Inc.; and FESC.
The Companies’ combined service areas encompass approximately 36,100 square miles in Ohio, New Jersey and Pennsylvania. The areas they serve have a combined population of approximately 11.2 million.
OE was organized under the laws of the State of Ohio in 1930 and owns property and does business as an electric public utility in that state. OE also has ownership interests in certain generating facilities located in the Commonwealth of Pennsylvania (see Item 2
Item 2 - Properties). OE engages in the generation, distribution and sale of electric energy to communities in a 7,500 square mile area of central and northeastern Ohio. OE also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 2.8 million.
OE owns all of Penn's outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business and owns property in the State of Ohio (see Item 2 - Properties). Penn furnishes electric service to communities in a 1,500 square mile area of western Pennsylvania. The area served by Penn has a population of approximately 0.3 million.
CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the generation, distribution and sale of electric energy in an area of approximately 1,700 square miles in northeastern Ohio. It also has ownership interests in certain generating facilities in Pennsylvania (see Item 2 - Properties). CEI also engages in the sale, purchase and interchange of electric energy with other electric companies. The area CEI serves has a population of approximately 1.9 million.
TE was organized under the laws of the State of Ohio in 1901 and does business as an electric public utility in that state. TE engages in the generation, distribution and sale of electric energy in an area of approximately 2,500 square miles in northwestern Ohio. It also has interests in certain generating facilities in Pennsylvania (see Item 2 - Properties). TE also engages in the sale, purchase and interchange of electric energy with other electric companies. The area TE serves has a population of approximately 0.8 million.
ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns transmission assets that were formerly owned by the Ohio Companies and Penn. ATSI owns and operates major, high-voltage transmission facilities, which consist of approximately 7,100 circuit miles (5,814 pole miles) of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. There are 37 interconnections with six neighboring control areas. ATSI's transmission system offers gateways into the East through high capacity ties with PJM through Penelec, Duquesne Light Company and Allegheny Energy, Inc. into the North through multiple 345 kV high capacity ties with MEC, and into the South through ties with AEP and DPL. ATSI is the control area operator for the Ohio Companies and Penn service areas. ATSI plans, operates and maintains the transmission system in accordance with the requirements of the NERC and applicable regulatory agencies to ensure reliable service to FirstEnergy's customers (see Transmission Rate Matters for a discussion of ATSI's participation in the MISO).
JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in northern, western and east central New Jersey. The area JCP&L serves has a population of approximately 2.5 million.
Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides primarily transmission and distribution services in eastern and south central Pennsylvania. The area it serves has a population of approximately 1.2 million.
Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.7 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves a population of about 13,400 in Waverly, New York and its vicinity.
FES was organized under the laws of the State of Ohio in 1997 and provides energy-related products and services, and through its FGCO subsidiary, operates FirstEnergy's nonnuclear generation businesses. FENOC was organized under the laws of the State of Ohio in 1998 and operates the Companies’ nuclear generating facilities. FSG is the parent company of several HVAC and energy management companies; MYR is a utility infrastructure construction service company. FirstCom provides telecommunication services (local and long-distance phone service). FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies.
Divestitures
FirstEnergy completed the sale of its international operations in January 2004 with the sales of its remaining 20.1 percent interest in Avon on January 16, 2004, and 28.67 percent interest in TEBSA on January 30, 2004. Impairment charges related to Avon and TEBSA were recorded in the fourth quarter of 2003 and no gain or loss was recognized upon the sales in 2004. Avon, TEBSA and other international assets sold in 2003 were originally acquired as part of FirstEnergy's November 2001 merger with GPU.
FirstEnergy sold its 50 percent interest in GLEP on June 23, 2004. Proceeds of $220 million included cash of $200 million and the right, valued at $20 million, to participate for up to a 40% interest in future wells in Ohio. This transaction produced an after-tax loss of $7 million, or $0.02 per share of common stock, including the benefits of prior tax capital losses that had been previously fully reserved, which offset the capital gain from the sale.
Risks Factors That May Affect Results
Changes in Commodity Prices Could Adversely Affect Our Margins
While much of our generation serves customers under retail rates set by regulatory bodies, we also purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal and natural gas) can affect our profit margins in both competitive and non-competitive markets. Changes in the market prices of electricity, which are affected by changes in fuel costs and other factors, may impact our financial results and financial position by increasing the amount we pay to purchase power to supply PLR obligations in Ohio and Pennsylvania.
Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:
·
severe or unexpected weather or seasonality;
·
changes in electricity usage;
·
illiquidity in wholesale power and other markets;
·
transmission or transportation constraints, inoperability or inefficiencies;
·
availability of competitively priced alternative energy sources;
·
changes in supply and demand for energy commodities;
·
changes in power production capacity;
·
outages at our power production facilities or those of our competitors;
·
changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products;
·
natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events; and
Complex and Changing Government Regulations Could Have a Negative Impact on Our Results of Operations
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influences our operating environment. Changes in or reinterpretations of existing laws or regulations or the imposition of new laws or regulations could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.
The Continuing Availability and Operation of Generating Units is Dependent on Retaining the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC
We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on operating results from future regulatory activities of any of these agencies.
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws Could Adversely Affect Cash Flow and Profitability
FirstEnergy’s subsidiaries’ operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur significant costs toward environmental monitoring, installation of pollution control equipment, emission fees, maintenance, upgrading, remediation and permitting at all of our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, changes in environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we might not recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address the relevant standards and interpretations in the future. If FirstEnergy fails to comply with environmental laws and regulations, even if caused by factors beyond its control or new interpretations of longstanding requirements, that failure may result in the assessment of civil or criminal liability and fines.
Risks of Nuclear Generation that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning
FirstEnergy is subject to the risks of nuclear generation, including but not limited to the following:
·
the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
·
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States;
·
uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate; and
·
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Unlike our fossil plants, which have been leased to and operated by FGCO since 2001, new capital costs as well as fuel, operation and maintenance expenses for the nuclear plants continue to be borne by CEI, TE, OE and Penn.
The Companies’ respective interests in nuclear facilities are insured under NEIL, policies issued for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. We have also obtained approximately $1.5 billion of insurance coverage for replacement power costs for the Companies’ respective interests in nuclear facilities. Under these policies, we can be assessed a maximum of approximately $67.5 million for incidents at any covered nuclear facility occurring during a policy year which are in excess of accumulated funds available to the insurer for paying losses.
Operational Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment
Operation of power plants, transmission and distribution facilities involves many risks, including the breakdown or failure of equipment or processes, accidents, labor disputes, stray voltage and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of those facilities may be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Operation of our power plants below expected capacity levels could result in lost revenues or increased expenses, including higher maintenance costs that we may not be able to recover from customers. Unplanned outages may require us to incur significant replacement power costs. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages may result.
We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires significant capital and other resources. Failure to provide safe and reliable service due to equipment failure in the electric system could adversely affect our operating results through reduced revenues and increased capital and maintenance costs.
Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
Workforce demographic issues are a national phenomenon that is of particular concern to the electric utility industry. The median age of utility workers is significantly higher than the national average. Today, nearly one-half of the utility workforce is age 45 or higher. Consequently, the utility industry faces the difficult challenge of finding ways to retain its aging skilled workforce while recruiting new talent in the hopes of decreasing losses in critical knowledge and skills due to retirements. Mitigating these risks may require additional financial commitments.
Regulatory Changes in the Electric Industry Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations
As a result of the actions taken by state legislative bodies over the last few years, major changes in the electric utility business have occurred and are continuing to take place in parts of the United States, including Ohio, Pennsylvania and New Jersey. These changes have resulted in fundamental alterations in the way integrated utilities conduct their business.
Increased competition resulting from restructuring efforts could have a significant adverse financial impact on FirstEnergy and its subsidiaries and consequently on their results of operations. Increased competition could result in increased pressure to lower prices, including the price of electricity. Retail competition and the unbundling of regulated electric service could have a significant adverse financial impact on us due to potential impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. We cannot predict the extent and timing of entry by additional competitors into the electric markets.
The FERC and U.S. Congress propose from time to time significant changes in the structure and conduct of the electric utility industry. If the restructuring and deregulation efforts result in increased competition or unrecoverable costs, our business and results of operations may be adversely affected. We cannot predict the extent and timing of further efforts to restructure, deregulate or re-regulate our business or the industry.
Weather Conditions such as Tornadoes, Hurricanes, Storms and Droughts, as Well as Seasonal Temperature Variations
Weather conditions directly influence the demand for electric power. In our service areas, demand for power peaks during the hot summer months, with market prices also typically peaking at that time. As a result, overall operating results may fluctuate on a seasonal and quarterly basis. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, storms and droughts, may cause outages and property damage which may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned, as described above, would be particularly burdensome during a peak demand period.
A Downgrade in Credit Ratings Could Negatively Affect Our Ability to Access Capital
We rely on access to capital markets as a significant source of liquidity for capital requirements not satisfied by cash flows from operations. Any inability to maintain our current credit ratings could affect, particularly during times of uncertainty in the capital markets, our ability to raise capital on favorable terms which, in turn, could impact our ability to grow our businesses. A credit rating downgrade would likely also increase our interest costs.
On July 22, 2004, S&P updated its analysis of U.S. utility FMB in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies including JCP&L and Penn. JCP&L’s FMB credit rating was upgraded to BBB+ from BBB and Penn’s FMB credit rating was upgraded to BBB from BBB-.
On August 26, 2004, S&P lowered its rating on certain Met-Ed Senior Notes to BBB- from BBB. The rationale for the ratings change was that Met-Ed’s senior secured notes, in aggregate, now comprise greater than 80% of Met-Ed’s total debt outstanding. According to the terms of the senior note indenture, once the 80% threshold is reached, the collateral mortgage bond security falls away and all senior secured notes that were secured by Met-Ed’s senior note indenture become unsecured. The one notch lower rating reflects this loss of collateral security. The BBB senior secured rating on Met-Ed’s FMB remain unchanged.
Also on August 26, 2004, S&P stated that a favorable outcome of the Ohio Rate Stabilization Plan auction process and a favorable resolution of pending environmental litigation would support a higher ratings outlook, or possibly a higher rating. On September 14, 2004, S&P stated that FirstEnergy’s $500 million voluntary contribution to its pension plan was credit neutral.
On December 10, 2004, S&P reaffirmed its ‘BBB-‘ corporate credit rating on FirstEnergy and kept the outlook stable. S&P noted that the stable outlook reflects FirstEnergy’s improving financial profile and cash flow certainty through 2006. S&P stated that should the two refueling outages at the Davis-Besse and Perry nuclear plants scheduled for the first quarter of 2005 be completed successfully without any significant negative findings and delays, FirstEnergy’s outlook would be revised to positive. S&P also stated that a ratings upgrade in the next several months did not seem likely, as remaining issues of concern to S&P, primarily the outcome of environmental litigation and SEC investigations, are not likely to be resolved in the short term.
Financial Performance Risks Related to the Economic Cycles of the Electric Utility Industry
Our business follows the economic cycles of our customers. Sustained downturns or sluggishness in the economy generally affects the markets in which the Companies operate and negatively influences the Companies’ energy operations. Declines in demand for electricity as a result of economic downturns will reduce overall electricity sales and lessen our cash flows, especially as industrial customers reduce production, resulting in less consumption of electricity. Economic conditions also impact our collection rates of accounts receivable.
We May Ultimately Incur Liability in Connection with Federal Proceedings
On October 20, 2004, FirstEnergy was notified by the SEC that the previously disclosed informal inquiry initiated by the SEC's Division of Enforcement in September 2003 relating to the restatements in August 2003 of previously reported results by FirstEnergy and the Ohio Companies, and the Davis-Besse extended outage, has become the subject of a formal order of investigation. The SEC's formal order of investigation also encompasses issues raised during the SEC's examination of FirstEnergy and the Companies under PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy received a second subpoena asking for documents relating to issues raised during the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition and results of operations.
In late 2003, FENOC received a subpoena from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at Davis-Besse. We are unable to predict the outcome of this investigation. On December 10, 2004, FirstEnergy received a letter from the United States Attorney's Office stating that FENOC is a target of the federal grand jury investigation into alleged false statements relating to the Davis-Besse outage made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter also said that the designation of FENOC as a target indicates that, in the view of the prosecutors assigned to the matter, it is likely that federal charges will be returned against FENOC by the grand jury. On February 10, 2005, FENOC received an additional subpoena for documents related to root cause reports regarding reactor head degradation and the assessment of reactor head management issues at Davis-Besse. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002.
On August 12, 2004, the NRC notified FENOC that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. FENOC operates the Perry Nuclear Power Plant, which is either owned or leased by OE, CEI, TE and Penn. Although the NRC noted that the plant continues to operate safely, the agency has indicated that its increased oversight will include an extensive NRC team inspection to assess the equipment problems and the sufficiency of FENOC’s corrective actions. The outcome of these matters could include NRC enforcement action or other impacts on operating authority. As a result, these matters could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition.
Utility Regulation
As a registered public utility holding company, FirstEnergy is subject to regulation by the SEC under PUHCA. The SEC has determined that the electric facilities of the Companies constitute a single integrated public utility system under the standards of PUHCA. PUHCA regulates FirstEnergy with respect to accounting, the issuance of securities, the acquisition and sale of utility assets, securities or any other interest in any business, and entering into, and performance of, service, sales and construction contracts among its subsidiaries, and certain other matters. PUHCA also limits the extent to which FirstEnergy may engage in nonutility businesses or acquire additional utility businesses. Each of the Companies' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the state in which each operates - in Ohio by the PUCO, in New Jersey by the NJBPU and in Pennsylvania by the PPUC. With respect to their wholesale and interstate electric operations and rates, the Companies are subject to regulation, including regulation of their accounting policies and practices, by the FERC. Under Ohio law, municipalities may regulate rates, subject to appeal to the PUCO if not acceptable to the utility.
Regulatory Accounting
FirstEnergy accounts for the effects of regulation through the application of SFAS 71 to its operating utilities when their rates:
·
are established by a third-party regulator with the authority to set rates that bind customers;
·
are cost-based; and
·
can be charged to and collected from customers.
An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. SFAS 71 is applied only to the parts of the business that meet the above criteria. If a portion of the business applying SFAS 71 no longer meets those requirements, previously recorded regulatory assets are removed from the balance sheet in accordance with the guidance in SFAS 101.
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:
·
restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the
Companies;
·
establishing or defining the PLR obligations to customers in the Companies' service areas;
·
providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive
generation market;
·
itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery
charges;
·
continuing regulation of the Companies' transmission and distribution systems; and
·
requiring corporate separation of regulated and unregulated business activities.
The EUOC recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Companies' respective transition and regulatory plans. Based on those plans, the Companies continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Companies continue the application of SFAS 71 to those operations.
Reliability Initiatives
In late 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force) regarding enhancements to regional reliability. With respect to each of these reliability enhancement initiatives, FirstEnergy submitted its response to the respective entity according to any required response dates. In 2004, we completed implementation of all actions and initiatives related to enhancing area reliability, improving voltage and reactive management, operator readiness and training, and emergency response preparedness recommended for completion in 2004. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with minor exceptions noted, that we had completed the recommended enhancements, policies, procedures and actions it had recommended be completed by June 30, 2004. In addition, FirstEnergy requested, and NERC provided, a technical assistance team of experts to assist in implementing and confirming timely and successful completion of various initiatives. The NERC-assembled independent verification team confirmed on July 14, 2004, that FirstEnergy had implemented the NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the U.S. - Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004, with minor exceptions noted by FirstEnergy. On December 28, 2004, FirstEnergy submitted a follow-up to its June 30, 2004 Certification and Report of Completion to NERC addressing the minor exceptions, which are now essentially complete.
FirstEnergy is proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new, or material upgrades, to existing equipment. FirstEnergy notes, however, that FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. Finally, the PUCO is continuing to review the FirstEnergy filing that addressed upgrades to control room computer hardware and software and enhancements to the training of control room operators, before determining the next steps, if any, in the proceeding.
On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. On July 16, 2003, the NJBPU initiated an investigation into the cause of JCP&L's outages of the July 4, 2003 weekend. The NJBPU selected a Special Reliability Master (SRM) to oversee and make recommendations on appropriate courses of action necessary to ensure system-wide reliability. Additionally, pursuant to the stipulation of settlement that was adopted in the NJBPU's Order of March 13, 2003 in its docket relating to the investigation of outages in August 2002, the NJBPU, through an independent auditor working under direction of the NJBPU Staff, undertook a review and focused audit of JCP&L's Planning and Operations and Maintenance programs and practices (Focused Audit). Subsequent to the initial engagement of the auditor, the scope of the review was expanded to include the outages during July 2003.
Both the independent auditor and the SRM submitted interim reports primarily addressing improvements to be made prior to the next occurrence of peak loads in the summer of 2004. On December 17, 2003, the NJBPU adopted the SRM's interim recommendations related to service reliability. With the assistance of the independent auditor and the SRM, JCP&L and the NJBPU staff created a Memorandum of Understanding (MOU) that set out specific tasks to be performed by JCP&L and a timetable for completion. On March 29, 2004, the NJBPU adopted the MOU and endorsed JCP&L's ongoing actions to implement the MOU. On June 9, 2004, the NJBPU approved a Stipulation that incorporates the final report of the SRM and the Executive Summary and Recommendation portions of the final report of the Operations Audit. A Final Order in the Focused Audit docket was issued by the NJBPU on July 23, 2004. JCP&L continues to file compliance reports reflecting activities associated with the MOU and Stipulation.
In May 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. Evidentiary hearings have been scheduled for September 2005. FirstEnergy is unable to predict the outcome of this proceeding.
On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed's, Penelec's and Penn's “service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring” in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability, ongoing periodic performance reporting and communications with customers and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. The settlement also outlines an expedited remediation process to address any alleged non-compliance with terms of the settlement and an expedited PPUC hearing process if remediation is unsuccessful. On November 4, 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.
PUCO Rate Matters
In October 2003, the Ohio Companies filed an application for a Rate Stabilization Plan with the PUCO to establish generation service rates beginning January 1, 2006, in response to PUCO concerns about price and supply uncertainty following the end of the Ohio Companies' transition plan market development period. On February 24, 2004, the Ohio Companies filed a revised Rate Stabilization Plan to address PUCO concerns related to the original Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process. On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In the second quarter of 2004, the Ohio Companies implemented the accounting modifications related to the extended amortization periods and interest costs deferral on the deferred customer shopping incentive balances. On October 1 and October 4, 2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO order and associated entries on rehearing.
The revised Rate Stabilization Plan extends current generation prices through 2008, ensuring adequate generation supply at stabilized prices, and continues the Ohio Companies' support of energy efficiency and economic development efforts. Other key components of the revised Rate Stabilization Plan include the following:
·
extension of the transition cost amortization period for OE from 2006 to as late as 2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as late as mid-2008;
·
deferral of interest costs on the accumulated customer shopping incentives as new regulatory assets; and
·
ability to request increases in generation charges during 2006 through 2008, under certain limited conditions, for increases in fuel costs and taxes.
On December 9, 2004, the PUCO rejected the auction price results from a required competitive bid process and issued an entry stating that the pricing under the approved revised Rate Stabilization Plan will take effect on January 1, 2006. The PUCO may cause the Ohio Companies to undertake, no more often than annually, a similar competitive bid process to secure generation for the years 2007 and 2008. Any acceptance of future competitive bid results would terminate the Rate Stabilization Plan pricing, but not the related approved accounting, and not until twelve months after the PUCO authorizes such termination.
NJBPU Rate Matters
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of December 31, 2004, the accumulated deferred cost balance totaled approximately $446 million. New Jersey law allows for securitization of JCP&L's deferred balance upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. On February 14, 2003, JCP&L filed for approval of the securitization of the deferred balance. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.
In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L's annual revenues effective August 1, 2003 and disallowed $153 million of deferred energy costs. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II proceeding be conducted to review whether JCP&L is in compliance with current service reliability and quality standards. The BPU also ordered that any expenditures and projects undertaken by JCP&L to increase its system's reliability will be reviewed as part of the Phase II proceeding, to determine their prudence and reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L's service. Any reduction would be retroactive to August 1, 2003. JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculating interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. JCP&L filed an August 15, 2003 interim motion for rehearing and reconsideration with the NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances, (2) the capital structure including the rate of return, (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning costs. Management is unable to predict when a decision may be reached by the NJBPU.
On July 16, 2004, JCP&L filed the Phase II petition and testimony with the NJBPU, requesting an increase in base rates of $36 million for the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The Ratepayer Advocate filed testimony on November 16, 2004 and JCP&L submitted rebuttal testimony on January 4, 2005. Settlement conferences are ongoing.
JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balance with the exception of 300 MW from JCP&L's NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. The BGS auction for periods beginning June 1, 2004 was completed in February 2004 and new BGS tariffs reflecting the auction results became effective June 1, 2004. The NJBPU decision on the BGS post transition year three process was announced on October 22, 2004, approving with minor modifications the BGS procurement process filed by JCP&L and the other New Jersey electric distribution companies and authorizing the continued use of NUG committed supply to serve 300 MW of BGS load. The auction for the supply period beginning June 1, 2005 was completed in February 2005.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study (see Exhibit 13, Note 11 - Asset Retirement Obligations). This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The Ratepayer Advocate filed comments on February 28, 2008. A schedule for further proceedings has not yet been set.
In response to the ongoing work stoppage by the members of IBEW System Council U-3, the NJBPU has made inquiries of JCP&L regarding its preparedness to assure service reliability and respond to storm or other emergency conditions during the strike. JCP&L has responded to these inquiries and has provided the requested information.
PPUC Rate Matters
In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings, which approved the FirstEnergy/GPU merger and provided Met-Ed and Penelec PLR deferred accounting treatment for energy costs. A February 2002 Commonwealth Court of Pennsylvania decision affirmed the PPUC decision regarding approval of the merger, remanded the issues of quantification and allocation of merger savings to the PPUC and denied the PLR deferral accounting treatment. In October 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec filed supplements to their tariffs which were effective October 2003 that reflected the CTC rates and shopping credits in effect prior to the June 21, 2001 order.
In response to its October 8, 2003 petition, the PPUC approved June 30, 2004 as the date for Met-Ed's and Penelec's NUG trust fund refunds and denied their accounting request regarding the CTC rate/shopping credit swap by requiring Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. Met-Ed and Penelec subsequently filed with the Commonwealth Court, on October 31, 2003, an Application for Clarification with the judge, a Petition for Review of the PPUC's October 2 and October 16 Orders, and an application for reargument if the judge, in his clarification order, indicates that Met-Ed's and Penelec's Objection was intended to be denied on the merits. The Reargument Brief before the Commonwealth Court was filed January 28, 2005.
In accordance with PPUC directives, Met-Ed and Penelec have been negotiating with interested parties in an attempt to resolve the merger savings issues that are the subject of remand from the Commonwealth Court. These companies' combined portion of total merger savings is estimated at approximately $31.5 million. If no settlement can be reached, Met-Ed and Penelec will take the position that any portion of such savings should be allocated to customers during each company's next rate proceeding.
Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR energy costs during the term of the agreement with FES. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.
Transmission Rate Matters
On November 1, 2004, ATSI requested authority from the FERC to defer approximately $54 million of vegetation management costs ($13 deferred as of December 31, 2004 pending authorization) estimated to be incurred from 2004 through 2007. The FERC issued an order granting approval of the deferral on March 2, 2005.
ATSI and MISO filed with the FERC on December 2, 2004, seeking approval for ATSI to have transmission rates established based on a FERC-approved cost of service formula rate included in Attachment O under the MISO tariff. The ATSI Network Service net revenue requirement increased under the formula rate to approximately $159 million. On January 28, 2005, the FERC accepted for filing the revised tariff sheets to become effective February 1, 2005, subject to refund, and ordered a public hearing be held to address the reasonableness of the proposal to eliminate the voltage-differentiated rate design for the ATSI zone.
On December 30, 2004, the Ohio Companies filed an application with the PUCO seeking tariff adjustments to recover increases of approximately $30 million in transmission and ancillary service-related costs beginning January 1, 2006. The Ohio Companies also filed an application for authority to defer costs such as those associated with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate increase, as applicable, from October 1, 2003 through December 31, 2005.
On January 12, 2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of transmission-related costs beginning January 1, 2005, estimated to be approximately $8 million per month.
On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville. Under the FERC’s decision, CEI may be responsible for a portion of new energy market charges imposed by MISO when its energy markets begin in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.
PJM and MISO were ordered by the FERC to develop a common market between the regions by October 31, 2004. The FERC also initiated a Section 206 investigation into the reasonableness of the “through-and-out” transmission rates charged by PJM and MISO. By order issued November 17, 2003, as modified by subsequent orders, MISO, PJM, and certain unaffiliated transmission owners in the Midwest were directed to eliminate rates for point-to-point service between the two RTOs effective December 1, 2004. On October 1, 2004, proponents of a Regional Pricing Plan and a Unified Plan filed competing proposals for FERC’s consideration. Protests and reply comments were filed with the FERC. On November 18, 2004, FERC issued an order conditionally accepting the Regional Pricing Plan and directing compliance filings by MISO and PJM. On November 24, 2004, compliance filings were submitted to FERC that proposed surcharges for collection of lost revenues in both MISO and PJM for December 1, 2004 through March 31, 2006. Numerous parties protested the proposed surcharges on January 7, 2005. On February 10, 2005, FERC issued an order setting the case for hearing. The outcome of this proceeding cannot be predicted.
On January 31, 2005, certain PJM transmission owners made filings pursuant to a settlement agreement approved by FERC in Docket ER04-156-000. JCP&L, Met-Ed and Penelec were parties to that proceeding. Three filings were made. First, the settling transmission owners submitted a filing justifying continuation of their existing “license plate” rate design within the PJM RTO. Second, the settling transmission owners proposed a revised Schedule 12 to the PJM Tariff designed to harmonize the rate treatment of new and existing transmission facilities. Finally, Baltimore Gas & Electric Company and certain public utility affiliates of PEPCO Holdings, Inc. made a filing to implement a transmission cost of service formula rate for their load zones within PJM. JCP&L, Met-Ed and Penelec did not join in this filing. Interventions and protests were due on these filings in late February, and we expect the FERC to act in late March 2005 on the filings.
On August 6, 2004, FERC issued an order conditionally approving the MISO’s proposed energy market tariff effective March 1, 2005. FERC affirmed this order on rehearing on November 6, 2004. The implementation of MISO’s energy market is subject to successful completion of market test runs and approval of certain compliance filings. On January 27, 2005, MISO announced that financially binding market activities would be postponed until April 1, 2005 to permit additional testing of systems and training. FirstEnergy affiliates have been certified as market participants and will participate in the MISO markets when they begin operation.
Capital Requirements
Capital expenditures for the Companies, FES and FirstEnergy's other subsidiaries for the years 2005 through 2007 excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the construction of generating capacity, facilities for environmental compliance, transmission lines, distribution lines, substations and other assets.
During the 2005-2007 period, maturities of, and sinking fund requirements for, long-term debt and preferred stock of FirstEnergy and its subsidiaries are:
* CEI has an additional $21 million due to associated companies in 2006-2007.
The Companies’ and FES's respective investments for additional nuclear fuel, and nuclear fuel investment reductions as the fuel is consumed, during the 2005-2007 period are presented in the following table. The table also displays the Companies’ operating lease commitments, net of capital trust cash receipts for the 2005-2007 period.
Short-term borrowings outstanding as of December 31, 2004, consisted of $29 million of bank borrowings (OE - $25 million and HVACs - $4 million), and $142 million of OES Capital, Incorporated. OES Capital is a wholly owned subsidiary of OE whose borrowings are secured by customer accounts receivable purchased from OE. OES Capital can borrow up to $170 million under a receivables financing agreement at rates based on certain bank commercial paper. FirstEnergy and OE had $1.4 billion available under $1.75 billion of revolving lines of credit as of December 31, 2004. FirstEnergy may borrow under these facilities and could transfer any of its borrowings to its subsidiaries. These revolving credit facilities, combined with an aggregate $550 million of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet our short-term working capital requirements and those of our subsidiaries. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $1.7 billion as of December 31, 2004. An additional source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. In 2004, the holding company received $782 million of cash dividends on common stock from its subsidiaries.
Based on their present plans, the Companies could provide for their cash requirements in 2005 from the following sources: funds to be received from operations; available cash and temporary cash investments as of December 31, 2004 (Company’s nonutility subsidiaries - $51 million, and OE - $1 million); the issuance of long-term debt (for refunding purposes); and funds available under revolving credit arrangements.
The extent and type of future financings will depend on the need for external funds as well as market conditions, the maintenance of an appropriate capital structure and the ability of the Companies to comply with coverage requirements in order to issue FMB and preferred stock. The Companies will continue to monitor financial market conditions and, where appropriate, may take advantage of economic opportunities to refund debt and preferred stock to the extent that their financial resources permit.
The coverage requirements contained in the first mortgage indentures under which the Companies issue FMB provide that, except for certain refunding purposes, the Companies may not issue FMB unless applicable net earnings (before income taxes), calculated as provided in the indentures, for any period of twelve consecutive months within the fifteen calendar months preceding the month in which such additional bonds are issued, are at least twice annual interest requirements on outstanding FMB, including those being issued. At the end of 2004, the Ohio Companies and Penn had the aggregate capability to issue approximately $4.4 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE and CEI are also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $641 million and $588 million, respectively, as of December 31, 2004. Under the provisions of its senior note indenture, JCP&L may issue additional FMB only as collateral for senior notes. As of December 31, 2004, JCP&L had the capability to issue $644 million of additional senior notes upon the basis of FMB collateral.
OE’s, Penn’s, TE’s and JCP&L's respective articles of incorporation prohibit the sale of preferred stock unless applicable gross income, calculated as provided in the articles of incorporation, is equal to at least 1-1/2 times the aggregate of the annual interest requirements on indebtedness and annual dividend requirements on preferred stock outstanding immediately thereafter. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L could issue a total of $4.5 billion of preferred stock (assuming no additional debt was issued) as of the end of 2004. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock.
To the extent that coverage requirements or market conditions restrict the Companies’ abilities to issue desired amounts of FMB or preferred stock, the Companies may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold and could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred.
As of December 31, 2004, approximately $1.0 billion was remaining under FirstEnergy's shelf registration statement, filed with the SEC in 2003, to support future securities issues. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units.
Nuclear Regulation
The construction, operation and decommissioning of nuclear generating units are subject to the regulatory jurisdiction of the NRC including the issuance by it of construction permits, operating licenses, and possession only licenses for decommissioning reactors. The NRC's procedures with respect to the amendment of nuclear reactor operating licenses afford opportunities for interested parties to request adjudicatory hearings on health, safety and environmental issues subject to meeting NRC "standing" requirements. The NRC may require substantial changes in operation or the installation of additional equipment to meet safety or environmental standards, subject to the backfit rule requiring the NRC to justify such new requirements as necessary for the overall protection of public health and safety. The possibility also exists for modification, denial or revocation of licenses. As a result of the merger with GPU, FirstEnergy now owns the TMI-2 and the Saxton Nuclear Experimental Facility. Both facilities are in various stages of decommissioning. TMI-2 is in a post-defueling monitored storage condition, with decommissioning planned in 2014, absent an extension of the operating license to the owner of TMI-1. Saxton is in the final stages of decommissioning, with license termination and final site restoration scheduled for the third quarter of 2005. Beaver Valley Unit 1 was placed in commercial operation in 1976, and its operating license expires in 2016. Davis-Besse was placed in commercial operation in 1977, and its operating license expires in 2017. Perry Unit 1 and Beaver Valley Unit 2 were placed in commercial operation in 1987, and their operating licenses expire in 2026 and 2027, respectively. FirstEnergy submitted a license renewal application with the NRC seeking to extend the operation of Beaver Valley Units 1 and 2 to 2036 and 2047, respectively.
Davis-Besse, which is operated by FENOC, began its scheduled refueling outage on February 16, 2002. The plant was originally scheduled to return to service by the end of March 2002. During the refueling outage, FENOC found corrosion in the reactor vessel head near some of the control rod drive mechanism penetration nozzles, created by boric acid deposits from leaks in the nozzles. As a result, the NRC issued a confirmatory action letter stating that restart of the plant would be subject to prior NRC approval, and it established an Inspection Manual Chapter 0350 Oversight Panel to ensure close NRC oversight of Davis-Besse’s corrective actions.
On March 8, 2004, FENOC received NRC authorization to restart Davis-Besse and the plant achieved full power on April 4, 2004.
The NRC granted restart authorization in an order containing several commitments for Davis-Besse. Those requirements include ongoing independent assessments of the site’s operational performance, safety culture and safety conscious work environment, and corrective action and engineering programs for five years, as well as visual inspection of the reactor head and lower vessel during the plant’s mid-cycle outage, which took place in late January and early February of 2005.
In 2002, FENOC spent approximately $115 million in additional nuclear-related operation and maintenance costs, approximately $120 million in replacement power costs and approximately $63 million in capital expenditures related to the reactor head and restart. In 2003, FENOC spent approximately $93 million in additional nuclear-related operation and maintenance costs, approximately $196 million in replacement power costs and approximately $21 million in capital expenditures related to the reactor head and restart. In 2004, FENOC spent approximately $900,000 in additional nuclear-related operation and maintenance costs and approximately $64 million in replacement power costs during the remaining period of the outage.
The NRC has promulgated and continues to promulgate orders and regulations related to the safe operation of nuclear power plants and standards for decommissioning clean-up and final license termination. The Companies cannot predict what additional orders and regulations (including post-September 11, 2001 security enhancements) may be promulgated, design changes required or the effect that any such regulations or design changes or additional clean-up standards for final site release, or the consideration thereof, may have upon their nuclear plants. Although the Companies have no reason to anticipate an accident at any of their nuclear plants, if such an accident did happen, it could have a material but currently undeterminable adverse effect on FirstEnergy's consolidated financial position. In addition, such an accident at any operating nuclear plant, whether or not owned by the Companies, could result in regulations or requirements that could affect the operation, licensing, or decommissioning of plants that the Companies do own with a consequent but currently undeterminable adverse impact, and could affect the Companies’ abilities to raise funds in the capital markets.
Nuclear Insurance
The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $10.8 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $300 million; and (ii) $10.5 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $100.6 million (but not more than $10 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, the Companies’ maximum potential assessment under these provisions would be $402.4 million (OE-$107.5 million, Penn-$84.5 million, CEI-$121.4 million and TE-$89.0 million) per incident but not more than $40.0 million (OE-$10.7 million, Penn-$8.4 million, CEI-$12.1 million and TE-$8.8 million) in any one year for each incident.
In addition to the public liability insurance provided pursuant to the Price-Anderson Act, the Companies have also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. The Companies are members of NEIL which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, the Companies have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.488 billion (OE-$397.2 million, Penn-$280.1 million, CEI-$478.9 million and TE-$332.1 million) for replacement power costs incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. The Companies’ present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $10.4 million (OE-$2.8 million, Penn-$2.0 million, CEI-$3.3 million and TE-$2.3 million).
The Companies are insured as to their respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, $2.75 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. The Companies pay annual premiums for this coverage and are liable for retrospective assessments of up to approximately $57.1 million (OE-$16.0 million, Penn-$11.2 million, CEI-$17.5 million, TE-$11.6 million, JCP&L-$0.2 million, Met-Ed-$0.4 million and Penelec-$0.2 million) during a policy year. On September 30, 2003, CEI and TE tendered Proofs of Loss under the Nuclear Electric Insurance Limited (NEIL) Property Damage and Accidental Outage Policies for the Davis-Besse Nuclear Power Station related to an outage that began in 2002 at that station. The property damage losses claimed by CEI and TE total $77.9 million and the Accidental Outage losses claimed by CEI and TE total $106.7 million. On December 18, 2004, NEIL denied CEI’s and TE’s claims. CEI and TE are considering their options with respect to pursuing an arbitration of this matter.
The Companies intend to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of the Companies’ plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by the Companies’ insurance policies, or to the extent such insurance becomes unavailable in the future, the Companies would remain at risk for such costs.
The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.06 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. The Companies are unable to predict what effect these requirements may have on the availability of insurance proceeds to the Companies for the Companies’ bondholders.
Environmental Matters
Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position. These environmental regulations affect FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $430 million for 2005 through 2007, which is included in the $3.3 billion of forecasted capital expenditures for 2005 through 2007.
Clean Air Act Compliance
The Companies are required to meet federally approved SO2 regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The Companies believe they are complying with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Companies' facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85 percent reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOx emissions are contributing significantly to ozone levels in the eastern United States. The Companies believe their facilities are also complying with the NOx budgets established under State Implementation Plans (SIPs) through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.
National Ambient Air Quality Standards
In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule" covering a total of 29 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx and SO2 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO2 emissions would be reduced by approximately 3.6 million tons annually by 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NOx emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a "co-benefit" from implementation of SO2 and NOx emission caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.
W. H. Sammis Plant
In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of "best available control technology" and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase of the trial to address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been delayed without rescheduling by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it "may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act." The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy's, OE's and Penn's respective financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2004.
Regulation of Hazardous Waste
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.
The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of December 31, 2004, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $65 million as of December 31, 2004. The Companies accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the United States Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity - the ratio of emissions to economic output - by 18 percent through 2012.
The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO2 emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies' diversified generation sources which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to the Companies' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to the Companies' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality, when aquatic organisms are pinned against screens or other parts of a cooling water intake system and entrainment, which occurs when aquatic species are drawn into a facility's cooling water system. The Companies are conducting comprehensive demonstration studies, due in 2008, to determine the operational measures, equipment or restoration activities, if any, necessary for compliance by their facilities with the performance standards. FirstEnergy is unable to predict the outcome of such studies. Depending on the outcome of such studies, the future cost of compliance with these standards may require material capital expenditures.
Fuel Supply
FirstEnergy currently has long-term coal contracts to provide approximately 18.4 million tons for the year 2005. The contracts are shared among the Companies based on various economic considerations. This contract coal is produced primarily from mines located in Pennsylvania, Kentucky, Wyoming and West Virginia. The contracts expire at various times through December 31, 2021.
The Companies estimate their 2005 coal requirements to be approximately 22.4 million tons (OE - 6.7 million, Penn - 7.7 million, CEI - 6.0 million, and TE - 2.0 million) to be met from the long-term contracts discussed above and spot market purchases. See “Environmental Matters” for factors pertaining to meeting environmental regulations affecting coal-fired generating units.
CEI, TE, OE and Penn have contracts for uranium material and conversion services through 2008. The enrichment services are contracted for all of the enrichment requirements for nuclear fuel through 2006. A portion of enrichment requirements is also contracted through 2011. Fabrication services for fuel assemblies are contracted for the next two reloads for Beaver Valley Unit 1, the next two reloads for Beaver Valley Unit 2 (through approximately 2007 and 2006, respectively), the next reload for Davis-Besse (through approximately 2006) and through the operating license period for Perry (through approximately 2026). The Davis-Besse fabrication contract also has an extension provision for services through the current operating license period (about 2017). In addition to the existing commitments, the Companies intend to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.
On-site spent fuel storage facilities are expected to be adequate for Perry through 2011; facilities at Beaver Valley Units 1 and 2 are expected to be adequate through 2015 and 2008, respectively. With the plant modifications completed in 2002, Davis-Besse has adequate storage through the remainder of its current operating license period. After current on-site storage capacity is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities. The Federal Nuclear Waste Policy Act of 1982 provides for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. CEI, TE, OE and Penn have contracts with the U.S. Department of Energy (DOE) for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. On February 15, 2002, President Bush approved the DOE's recommendation of Yucca Mountain for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The approval by President Bush enables the process to proceed to the licensing phase. Based on the DOE schedule published in the July 1999 Draft Environmental Impact Statement, the Yucca Mountain Repository is currently projected to start receiving spent fuel in 2010. The Repository is expected to be delayed further as the result of an announced delay in submission of the license application. The Companies intend to make additional arrangements for storage capacity as a contingency for further delays with the DOE acceptance of spent fuel for disposal past 2010.
System Capacity and Reserves
The 2004 net maximum hourly demand for each of the Companies was: OE-5,461 MW (including an additional 273 MW of firm power sales under a contract which extends through 2005) on June 9, 2004; Penn-987 MW (including an additional 56 MW of firm power sales under a contract which extends through 2005) on June 15, 2004; CEI-4,126 MW on August 27, 2004; TE-2,032 MW on August 3, 2004; JCP&L-5,457 MW on August 20, 2004; Met-Ed-2,548 MW on August 3, 2004; and Penelec-2,830 MW on December 20, 2004. JCP&L's load was auctioned off in the New Jersey BGS Auction, transferring the full 5,100 MW load obligation to other parties for the supply period beginning June 1, 2005. FES participated in the auction and won a segment of that load.
Based on existing capacity plans, ongoing arrangements for firm purchase contracts, and anticipated term power sales and purchases, FirstEnergy has sufficient supply resources to meet load obligations. The current FirstEnergy capacity portfolio contains 13,387 MW of owned generation and approximately 1,600 MW of long-term purchases from NUGs. Any remaining load obligations will be met through a mix of multi-year forward purchases, short-term forward purchases (less than one year) and spot market purchases.
The Companies’ sources of generation during 2004 were:
Regional Reliability
The Ohio Companies and Penn participate with 24 other electric companies operating in nine states in ECAR, which was organized for the purpose of furthering the reliability of bulk power supply in the area through coordination of the planning and operation by the ECAR members of their bulk power supply facilities. The ECAR members have established principles and procedures regarding matters affecting the reliability of the bulk power supply within the ECAR region. Procedures have been adopted regarding: i) the evaluation and simulated testing of systems’ performance; ii) the establishment of minimum levels of daily operating reserves; iii) the development of a program regarding emergency procedures during conditions of declining system frequency; and iv) the basis for uniform rating of generating equipment.
The transmission facilities of JCP&L, Met-Ed and Penelec are operated by PJM. PJM is the organization responsible for the operation and control of the bulk electric power system throughout major portions of five Mid-Atlantic states and the District of Columbia. PJM is dedicated to meeting the reliability criteria and standards of NERC and the Mid-Atlantic Area Council.
Competition
The Companies compete with other utilities for intersystem bulk power sales and for sales to municipalities and cooperatives. The Companies also compete with suppliers of natural gas and other forms of energy in connection with their industrial and commercial sales and in the home climate control market, both with respect to new customers and conversions, and with all other suppliers of electricity. To date, there has been no substantial cogeneration by the Companies’ customers.
As a result of actions taken by state legislative bodies over the last few years, major changes in the electric utility business are occurring in parts of the United States, including Ohio, New Jersey and Pennsylvania where FirstEnergy's utility subsidiaries operate. These changes have resulted in fundamental alterations in the way traditional integrated utilities and holding company systems, like FirstEnergy, conduct their business. In accordance with the Ohio electric utility restructuring law under which Ohio electric customers could begin choosing their electric generation suppliers starting in January 2001, FirstEnergy has further aligned its business units to accommodate its retail strategy and participate in the competitive electricity marketplace in Ohio. The organizational changes deal with the unbundling of electric utility services and new ways of conducting business. FirstEnergy’s competitive segment participates in deregulated energy markets in Ohio, Pennsylvania, New Jersey and Michigan.
Competition in Ohio’s electric generation began on January 1, 2001. FirstEnergy moved the operation of the generation portion of its business to its competitive business unit as reflected in its approved Ohio transition plan. The Companies continue to provide generation services to regulated franchise customers who have not chosen an alternative, competitive generation supplier, except in New Jersey where JCP&L's obligation to provide BGS has been removed through a transitional mechanism of auctioning the obligation (see "NJBPU Rate Matters"). In September 2002, Met-Ed and Penelec assigned their PLR responsibility to FES through a wholesale power sale agreement. Under the terms of the wholesale agreement, FES assumed the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The agreement will be automatically extended on an annual basis unless any party elects to cancel the agreement by November 1 of the preceding year (see "PPUC Rate Matters" for further discussion). The Ohio Companies and Penn obtain their generation through power supply agreements with FES.
Research and Development
The Companies participate in funding the Electric Power Research Institute (EPRI), which was formed for the purpose of expanding electric research and development under the voluntary sponsorship of the nation’s electric utility industry - public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The major portion of EPRI research and development projects is directed toward practical solutions and their applications to problems currently facing the electric utility industry.
Executive Officers
The executive officers are elected at the annual organization meeting of the Board of Directors, held immediately after the annual meeting of stockholders, and hold office until the next such organization meeting, unless the Board of Directors shall otherwise determine, or unless a resignation is submitted.
Mrs. Vespoli and Messrs. Alexander, Marsh and Wagner are the executive officers, as noted above, of OE, Penn, CEI, TE, Met-Ed and Penelec. Mrs. Vespoli and Messrs. Marsh, Morgan and Wagner are the executive officers of JCP&L.
* Indicates position held at least since January 1, 2000.
Employees
As of January 1, 2005, FirstEnergy’s nonutility subsidiaries and the Companies had a total of 15,245 employees located in the United States as follows:
Approximately 7,218 of the above employees (including 720 for OE, 635 for CEI, 317 for TE, 153 for Penn, 1,155 for JCP&L, 490 for Met-Ed and 605 for Penelec) are covered by collective bargaining agreements.
On December 8, 2004, employees represented by IBEW System Council U-3 began a strike against JCP&L. JCP&L continues to utilize management, other non-union personnel from around FirstEnergy's system and contractors to perform service reliability and priority maintenance work while the union members are on strike. The labor agreement between JCP&L and System Council U-3 originally expired on October 31, 2003 but was extended several times and ultimately expired on December 7, 2004. JCP&L and the leadership of System Council U-3 continue to negotiate in an attempt to reach a new agreement and end the work stoppage. It is unknown when such an agreement will be reached or when the work stoppage will end. On January 31, 2005, IBEW Local 245, ratified a three-year contract agreement with TE, FENOC, and FGCO. On February 4, 2005, IBEW Local 272, representing approximately 350 employees of the Bruce Mansfield Plant, ratified a three-year contract with FGCO.
FirstEnergy Website
Each of the registrant's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy's internet website at www.firstenergycorp.com. These reports are posted on the website as soon as reasonably practicable after they are electronically filed with the SEC.
ITEM 2. PROPERTIES
The Companies’ respective first mortgage indentures constitute, in the opinion of the Companies’ counsel, direct first liens on substantially all of the respective Companies’ physical property, subject only to excepted encumbrances, as defined in the indentures. See “Leases” and “Capitalization” notes to the respective financial statements for information concerning leases and financing encumbrances affecting certain of the Companies’ properties.
The Companies own, individually or together as tenants in common, and/or lease, the generating units in service as of March 1, 2005, shown on the table below.
Notes:
(a)
CEI’s interests consist of 1.68% owned and 28.60% leased and TE's interests are leased.
(b)
OE’s interests consist of 20.22% owned and 21.66% leased for Beaver Valley Unit 2; and 17.42% owned (representing portion leased from a wholly owned subsidiary of OE) and 12.58% leased for Perry.
(c)
TE’s interests consist of 1.65% owned and 18.26% leased.
Prolonged outages of existing generating units might make it necessary for the Companies, depending upon the demand for electric service upon their system, to use to a greater extent than otherwise, less efficient and less economic generating units, or purchased power, and in some cases may require the reduction of load during peak periods under the Companies’ interruptible programs, all to an extent not presently determinable.
The Companies’ generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Companies’ overhead and underground transmission lines aggregate 14,978 pole miles.
The Companies’ electric distribution systems include 114,177 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of 91,117,000 kilovolt-amperes.
The transmission facilities that are owned and operated by ATSI also interconnect with those of AEP, DPL, Duquesne, Allegheny, MEC and Penelec. The transmission facilities of JCP&L, Met-Ed and Penelec are physically interconnected and are operated on an integrated basis as part of the PJM RTO.
FirstEnergy's distribution and transmission systems as of December 31, 2004, consist of the following:
*
Represents transmission lines of 69kv and above in service areas of OE, Penn, CEI and TE.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 13, Commitments, Guarantees and Contingencies, of the Notes to Consolidated Financial Statements contained in Item 8 for a description of certain legal proceedings involving FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The information required by Item 5. regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included on page 5 of FirstEnergy’s 2004 Annual Report to Stockholders (Exhibit 13). The information required for OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec is not applicable because they are wholly owned subsidiaries.
The table below includes information on a monthly basis for the fourth quarter, regarding purchases made by FirstEnergy of its common stock.
(a)
Share amounts reflect purchases on the open market to satisfy FirstEnergy’s obligations to deliver common stock under its Executive and Director Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the Executive and Director Incentive Compensation Plan.
(b)
FirstEnergy does not currently have any publicly announced plan or program for share purchases.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required for items 6 through 8 is incorporated herein by reference to Selected Financial Data, Management’s Discussion and Analysis of Results of Operations and Financial Condition, and Financial Statements included on the pages shown in the following table in the respective company’s 2004 Annual Report to Stockholders (Exhibit 13).
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Each registrant’s Chief Executive Officer and Chief Financial Officer have reviewed and evaluated such registrant’s disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the respective Chief Executive Officer and Chief Financial Officer concluded that such registrant’s disclosure controls and procedures are effective.
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework, management conducted an evaluation of the effectiveness of the registrants’ internal control over financial reporting under the supervision of each registrant’s chief executive officer and chief financial officer. Based on that evaluation, management concluded that the registrants’ internal control over financial reporting was effective as of December 31, 2004. Management’s assessment of the effectiveness of the registrants’ 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 reports included in each registrant’s 2004 Annual Report to Stockholders and incorporated by reference hereto.
Changes in Internal Controls over Financial Reporting
There were no changes in the registrants’ internal controls over financial reporting during the fourth quarter of 2004 that have materially affected, or are reasonably likely to materially affect, the registrants’ internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Severance Agreements
On February 15, 2005, in response to a shareholder proposal at the 2004 Annual Meeting that received the affirmative vote of approximately 64 percent of the votes cast, the Board of Directors adopted a new policy with respect to severance agreements. The Board’s policy requires that any future severance agreement offered to any FirstEnergy employee that would be triggered by a change in control of FirstEnergy limit the multiplier of base salary and target short-term incentive compensation to 2.99 times. The Board’s policy also requires that such severance agreements only contain such other terms, conditions and provisions as may be recommended by the Compensation Committee and approved by the independent directors of the Board and, at the discretion of such independent directors, approved by the shareholders. The Board’s policy also requires that the Compensation Committee retain an independent third-party consultant to periodically review the prevailing competitive practices concerning severance agreements triggered by a change in control and report on such review to the Board.
In accordance with this policy, the Compensation Committee authorized, and FirstEnergy entered into, separate severance agreements with Guy L. Pipitone, Mark T. Clark, Lynn M. Cavalier and Richard R. Grigg on March 7, 2005, effective immediately. Severance benefits are limited to 2.99 times base salary and target short-term incentive compensation for Ms. Cavalier and Messrs. Clark and Grigg. Severance benefits are limited to 2.0 times base salary and target short-term incentive compensation for Mr. Pipitone. In addition, the Compensation Committee recommended, and the Board approved, the following additional terms. With respect to the retirement benefits of Ms. Cavalier and Messrs. Clark and Grigg, (a) three years will be added to his or her age and service at termination, (b) pension benefits will be calculated with the enhanced age and service, and (c) benefits will be paid out no earlier than an adjusted age of 55. With regard to health care, he or she will receive health care benefits on the same terms as an active employee for three years. Lastly, with regard to life insurance, he or she will receive life insurance benefits on the same terms as an active employee for three years. Mr. Pipitone’s agreement provides that, in regard to retirement plans, (a) two years will be added to his age and service at termination, (b) pension benefits will be calculated with the enhanced age and service, and (c) benefits will be paid out no earlier than an adjusted age of 55. In regard to health care, he will receive health care benefits on the same terms as an active employee for two years. Lastly, in regard to life insurance, he will receive life insurance benefits on the same terms as an active employee for two years.
Under the agreements, a change in control includes the acquisition of the beneficial ownership of 50 percent or more of the outstanding shares of common stock or other voting stock of FirstEnergy, a change in the majority of the members of the Board of Directors, or a reorganization, merger, or dissolution of FirstEnergy. The agreements are intended to ensure that the individuals are free from personal distractions in the context of a potential change in control, when the Board needs the objective assessment and advice of these executives to determine whether an offer is in the best interests of the Company and its shareholders. The principal severance benefits may be triggered when the individual is terminated or resigns for good reason, which generally is defined as a material change, following a change of control, inconsistent with the individual’s previous job duties or compensation.
Under all of the above severance agreements, the executive would be prohibited for two years from working for or with competing entities after receiving severance benefits from this change in control agreement.
FirstEnergy also has in place separate severance agreements with Anthony J. Alexander, Richard H. Marsh, Carole B. Snyder, and Leila L. Vespoli, in the form applicable to Ms. Cavalier and Messrs. Clark and Grigg described above, except that such agreements provide for a benefit equal to 2.99 times the sum of the individual’s base salary plus the average of his or her annual incentive compensation awards over the past three years. Additionally, in the case of Mr. Alexander, he is eligible for the specified severance benefits if he resigns, for any reason, during a 90-day period commencing 18 months following a change in control. Because the agreements for Mr. Marsh, Ms. Vespoli, and Ms. Snyder do not become effective until January 1, 2006, they remain covered under the severance agreements that were previously in place for each of them through December 31, 2005.
FirstEnergy also has in place separate severance agreements with Kevin J. Keough and Kathryn W. Dindo in the form applicable to Mr. Pipitone as described above, except that such agreements provide for a benefit equal to 2.00 times the sum of the individual’s base salary plus the average of his or her annual incentive compensation awards over the past three years.
Executive Bonus Plan
FirstEnergy adopted an Executive Bonus Plan effective November 3, 2004. The plan was established for the purpose of providing for the purchase of personal life insurance for participants who are each deemed to be a member of a select group of highly compensated and/or management employees of FirstEnergy and its subsidiaries. The plan is part of an integrated executive compensation program that is intended to attract, retain and motivate certain key executives who are in a position to make significant contributions to the operation and profitability of FirstEnergy for the benefit of stockholders and customers. Employees of FirstEnergy and its subsidiaries who are or become subject to the provisions of Section 402 of the Sarbanes-Oxley Act of 2002, as amended, and are designated by the CEO or, in the case of the CEO, by the Compensation Committee of the Board, are eligible to participate in the Plan.
Policies under the plan will insure the participant’s life and shall provide a death benefit equal to the participant’s annual base salary as of a specified date.
A copy of the plan was filed as an exhibit to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2004.
Executive and Director Incentive Compensation Plan Awards
On March 3, 2005, FirstEnergy notified the following executive officers that they were to receive the indicated performance-based restricted stock unit awards and restricted stock awards under the FirstEnergy Executive and Director Incentive Compensation Plan:
(1)
Period of Restriction expires upon the earlier of (i) March 1, 2008, (ii) recipient’s death, (iii) recipient’s termination
from employment due to disability and (iv) a change in control occurs.
(2)
Period of Restriction expires upon the earlier of (i) March 1, 2010, (ii) recipient’s death, (iii) recipient’s termination
from employment due to disability and (iv) a change in control occurs.
(3)
Period of Restriction expires upon the earlier of (i) March 1, 2015, (ii) recipient’s death, (iii) recipient’s termination
from employment due to disability and (iv) a change in control occurs.
Each award become effective upon acknowledgement by the recipient. The Plan gives recipients the right to acquire stock after the Period of Restriction indicated above, and subject to forfeiture and other provisions under the Plan and the agreements between FirstEnergy and the recipient. The forms of the respective performance-based restricted stock unit and restricted stock agreements are filed as exhibits to this Annual Report on Form 10-K.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
FirstEnergy
The information required by Item 10, with respect to Identification of FirstEnergy’s Directors and with respect to reports required to be filed under Section 16 of the Securities Exchange Act of 1934, is incorporated herein by reference to FirstEnergy’s 2005 Proxy Statement filed with the SEC pursuant to Regulation 14A and, with respect to Identification of Executive Officers, to “Part I, Item 1. Business - Executive Officers” herein.
The Board of Directors has determined that Ernest J. Novak, Jr., an independent director, is the audit committee financial expert.
FirstEnergy makes available on its website at http://www.firstenergycorp.com/ir its Corporate Governance Policies and the charters for each of the following committees of the Board of Directors: Audit; Corporate Governance; Compensation; Finance; and Nuclear. The Corporate Governance Policies and Board committee charters are also available in print upon written request to David W. Whitehead, Corporate Secretary, FirstEnergy Corp., 76 South Main Street, Akron, OH 44308-1890.
FirstEnergy has adopted a Code of Business Conduct, which applies to all employees, including the Chief Executive Officer, the Chief Financial Officer and the Chief Accounting Officer. In addition, the Board of Directors has its own Code of Business Conduct. These Codes can be found on our website provided in the previous paragraph or upon written request to the Corporate Secretary.
Pursuant to Section 303A.12(a) of the New York Stock Exchange Listed Company Manual, the Company submitted the Annual CEO Certification to the NYSE on June 16, 2004.
OE, Penn, CEI, TE, JCP&L, Met-Ed and Penelec
A. J. Alexander, R. H. Marsh and R. R. Grigg are the Directors of OE, Penn, CEI, TE, Met-Ed and Penelec. Information concerning these individuals is shown in the “Executive Officers” section of Item 1. S. E. Morgan, C. E. Jones, L. L. Vespoli, B. S. Ewing, M. A. Julian, G. E. Persson and S. C. Van Ness are the Directors of JCP&L.
Mr. Ewing (Age 44) has served as FirstEnergy Service Company’s Vice President - Energy Delivery since 2003. From 1999 to 2003, Mr. Ewing served as Director of Operations Services - Northern Region.
Mr. Julian (Age 48) has served as FirstEnergy Service Company’s Vice President - Energy Delivery since 2003. From 2001 to 2003, Mr. Julian served as Director of Energy Delivery Technical Services. He was Director of Operations Services - Northern Region from 2000 to 2001 and Director of Operations Support Services - Central Region from 1999-2000.
Mrs. Persson (Age 74) has served in the New Jersey Division of Consumer Affairs Elder Fraud Investigation Unit since 1999. She previously served as liaison (Special Assistant Director) between the New Jersey Division of Consumer Affairs and various state boards. Prior to 1995, she was owner and President of Business Dynamics Associated of Red Bank, NJ. Mrs. Persson is a member of the United States Small Business Administration National Advisory Board, the New Jersey Small Business Advisory Council, the Board of Advisors of Brookdale Community College and the Board of Advisors of Georgian Court College.
Mr. Van Ness (Age 71) has been Of Counsel in the firm of Hubert, Van Ness, Cayci and Goodell, LP of Princeton, NJ since 1998. Prior to that he was affiliated with the law firm of Pico, Mack, Kennedy, Jaffe, Perrella and Yoskin of Trenton, NJ since 1990. He is also a director of The Prudential Insurance Company of America.
Information concerning the other Directors of JCP&L is shown in the “Executive Officers” section of Item 1.
Section 16(a) Beneficial Ownership Reporting Compliance - OE, Penn, CEI, TE, JCP&L, Met-Ed and Penelec
Prior to February 2005, FirstEnergy and OE, Penn, CEI, TE, JCP&L, Met-Ed and Penelec (the “Reporting Subsidiaries”) recommended to persons who were insiders of both FirstEnergy and a Reporting Subsidiary or Reporting Subsidiaries that single insider reports be filed with respect to FirstEnergy and the Reporting Subsidiaries rather than separate reports for each. This position was based in part on an instruction to the insider reporting forms that applies in the case of registered public utility holding companies. Insiders of FirstEnergy and the Reporting Subsidiaries filed Forms 3 in this manner and further, did not set forth information about any Reporting Subsidiary on grounds that they had no holdings of any such issuer.
It recently came to FirstEnergy’s attention that there is a difference of opinion as to the proper method of reporting where a subsidiary of a registered public utility holding company has equity securities registered under the Securities Exchange Act of 1934 (as do the Reporting Subsidiaries). SEC guidance in this area is unclear, and industry practice varies. After further review, FirstEnergy and the Reporting Subsidiaries determined to recommend that their insiders follow a more conservative approach and file separate reports for each Reporting Subsidiary.
Accordingly, in March 2005, Forms 3 will be filed on behalf of the following insiders in respect of the Reporting Subsidiaries indicated: Richard H. Marsh, Leila L. Vespoli, Charles E. Jones, Harvey L. Wagner, Thomas C. Navin, in each case, for all of the Reporting Subsidiaries: Anthony J. Alexander and Richard R. Grigg, in each case, for all of the Reporting Subsidiaries except JCP&L: Gelorma E. Persson, Stanley C. Van Ness, Bradley S. Ewing, Mark A. Julian and Stephen E. Morgan, in each case, for JCP&L; Kevin J. Keough, Thomas A. Clark and Jeffrey A. Elser for OE, Ronald P. Lantzy for OE and Met-Ed; Dennis E. Chack and Paul W. Allison for CEI; and James M. Murray and Charles H. Krueger for TE. Although arguably these Forms are not required to be filed at all particularly since the reporting persons have no holdings in the Reporting Subsidiaries, the Reporting Subsidiaries nonetheless are reporting these Forms 3 as having not yet been filed for purposes of this Report on Form 10-K.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec -
The information required by Items 11, 12 and 13 is incorporated herein by reference to FirstEnergy’s 2005 Proxy Statement filed with the SEC pursuant to Regulation 14A.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
A summary of the audit and audit-related fees rendered by PricewaterhouseCoopers LLP for the years ended December 31, 2004 and 2003 are as follows:
(1)
Professional services rendered for the audits of FirstEnergy’s annual financial statements and reviews of financial statements included in FirstEnergy’s Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.
(2)
Assurance and related services principally related to: (i) audits of employee benefit plans; (ii) consultation to ensure appropriate accounting and reporting in connection with FIN 46 and the Rate Stabilization Plan (OE, CEI and TE); and (iii) assistance with Sarbanes-Oxley.
Tax and Other Fees
There were no fees billed to FirstEnergy for tax services or other services not discussed above for the years ended December 31, 2004 and December 31, 2003.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements
Included in Part II of this report and incorporated herein by reference to the respective company’s 2004 Annual Report to Stockholders (Exhibit 13 below) at the pages indicated.
2. Financial Statement Schedules
Included in Part IV of this report:
Schedules other than the schedule listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.
3. Exhibits - FirstEnergy
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
(B) 3. Exhibits - Ohio Edison
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
3. Exhibits - Penn
Exhibit
Number
Exhibit
Number
Exhibit
Number
3. Exhibits - Common Exhibits to CEI and TE
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
Exhibit
Number
3.
Exhibits - Cleveland Electric Illuminating (CEI)
Exhibit
Number
Exhibit
Number
3. Exhibits - Toledo Edison (TE)
Exhibit
Number
Exhibit
Number
Exhibit
Number
3. Exhibits - Exhibits for Jersey Central Power & Light Company (JCP&L)
Exhibit
Number
Exhibit
Number
Exhibit
Number
3. Exhibits - Exhibits for Metropolitan Edison Company (Met-Ed)
Exhibit
Number
Exhibit
Number
3. Exhibits - Exhibits for Pennsylvania Electric Company (Penelec)
Exhibit
Number
Exhibit
Number
3. Exhibits - Combined Exhibit for Met-Ed and Penelec
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedules
To the Board of Directors of
FirstEnergy Corp.:
Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated March 7, 2005 appearing in the 2004 Annual Report to Stockholders of FirstEnergy Corp. (which report, consolidated financial statements and assessment are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
March 7,
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedules
To the Board of Directors of
Ohio Edison Company:
Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated March 7, 2005 appearing in the 2004 Annual Report to Stockholders of Ohio Edison Company (which report, consolidated financial statements and assessment are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
March 7,
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedules
To the Board of Directors of
The Cleveland Electric Illuminating Company:
Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated March 7, 2005 appearing in the Annual Report to Stockholders of The Cleveland Electric Illuminating Company (which report, consolidated financial statements and assessment are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
March 7,
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedules
To the Board of Directors of
The Toledo Edison Company:
Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated March 7, 2005 appearing in the Annual Report to Stockholders of The Toledo Edison Company (which report, consolidated financial statements and assessment are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
March 7,
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedules
To the Board of Directors of
Pennsylvania Power Company:
Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated March 7, 2005 appearing in the Annual Report to Stockholders of Pennsylvania Power Company (which report, consolidated financial statements and assessment are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
March 7,
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedules
To the Board of Directors of
Jersey Central Power
& Light Company:
Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated March 7, 2005 appearing in the Annual Report to Stockholders of Jersey Central Power & Light Company (which report, consolidated financial statements and assessment are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
March 7,
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedules
To the Board of Directors of
Metropolitan Edison Company:
Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated March 7, 2005 appearing in the Annual Report to Stockholders of Metropolitan Edison Company (which report, consolidated financial statements and assessment are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
March 7,
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedules
To the Board of Directors of
Pennsylvania Electric Company:
Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated March 7, 2005 appearing in the Annual Report to Stockholders of Pennsylvania Electric Company (which report, consolidated financial statements and assessment are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
PricewaterhouseCoopers LLP
Cleveland, Ohio
March 7,
SCHEDULE II
FIRSTENERGY CORP.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.
(c) Includes a reclassification of a valuation allowance to a contingent liability.
SCHEDULE II
OHIO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
SCHEDULE II
THE TOLEDO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
________________________
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II
PENNSYLVANIA POWER COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II
METROPOLITAN EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.
SCHEDULE II
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
______________________
(a) Represents recoveries and reinstatements of accounts previously written off.
(b) Represents the write-off of accounts considered to be uncollectible.
SIGNATURES
Pursuant to the requirements of Section 13 or 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.
FIRSTENERGY CORP.
BY: /s/ Anthony J. Alexander
Anthony J. Alexander
President and Chief Executive Officer
Date: March 9, 2005
SIGNATURES
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 and in the capacities and on the date indicated:
/s/ George M. Smart
/s/ Anthony J. Alexander
George M. Smart
Anthony J. Alexander
Chairman of the Board
President and Chief Executive Officer
and Director (Principal Executive Officer)
/s/ Richard H. Marsh
/s/ Harvey L. Wagner
Richard H. Marsh
Harvey L. Wagner
Senior Vice President and Chief Financial
Vice President, Controller and Chief Accounting
Officer (Principal Financial Officer)
Officer (Principal Accounting Officer)
/s/ Paul T. Addison
/s/ Paul J. Powers
Paul T. Addison
Paul J. Powers
Director
Director
/s/ Carol A. Cartwright
/s/ Catherine A. Rein
Carol A. Cartwright
Catherine A. Rein
Director
Director
/s/ William T. Cottle
/s/ Robert C. Savage
William T. Cottle
Robert C. Savage
Director
Director
/s/ Russell W. Maier
/s/ Wes M. Taylor
Russell W. Maier
Wes M. Taylor
Director
Director
/s/ Ernest J. Novak, Jr.
/s/ Jesse T. Williams, Sr.
Ernest J. Novak, Jr.
Jesse T. Williams, Sr.
Director
Director
/s/ Robert N. Pokewaldt
/s/ Patricia K. Woolf
Robert N. Pokewaldt
Patricia K. Woolf
Director
Director
Date: March 9, 2005
SIGNATURES
Pursuant to the requirements of Section 13 or 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.
OHIO EDISON COMPANY
BY: /s/ Anthony J. Alexander
Anthony J. Alexander
President
Date: March 9, 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 and in the capacities and on the date indicated:
/s/ Anthony J. Alexander
/s/ Richard R. Grigg
Anthony J. Alexander
Richard R. Grigg
President and Director
Executive Vice President and Chief
(Principal Executive Officer)
Operating Officer and Director
/s/ Richard H. Marsh
/s/ Harvey L. Wagner
Richard H. Marsh
Harvey L. Wagner
Senior Vice President and Chief
Vice President and Controller
Financial Officer and Director
(Principal Accounting Officer)
(Principal Financial Officer)
Date: March 9, 2005
SIGNATURES
Pursuant to the requirements of Section 13 or 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 CLEVELAND ELECTRIC ILLUMINATING COMPANY
BY: /s/ Anthony J. Alexander
Anthony J. Alexander
President
Date: March 9, 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 and in the capacities and on the date indicated:
/s/ Anthony J. Alexander
/s/ Richard R. Grigg
Anthony J. Alexander
Richard R. Grigg
President and Director
Executive Vice President and Chief
(Principal Executive Officer)
Operating Officer and Director
/s/ Richard H. Marsh
/s/ Harvey L. Wagner
Richard H. Marsh
Harvey L. Wagner
Senior Vice President and Chief
Vice President and Controller
Financial Officer and Director
(Principal Accounting Officer)
(Principal Financial Officer)
Date: March 9, 2005
SIGNATURES
Pursuant to the requirements of Section 13 or 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 TOLEDO EDISON COMPANY
BY: /s/ Anthony J. Alexander
Anthony J. Alexander
President
Date: March 9, 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 and in the capacities and on the date indicated:
/s/ Anthony J. Alexander
/s/ Richard R. Grigg
Anthony J. Alexander
Richard R. Grigg
President and Director
Executive Vice President and Chief
(Principal Executive Officer)
Operating Officer and Director
/s/ Richard H. Marsh
/s/ Harvey L. Wagner
Richard H. Marsh
Harvey L. Wagner
Senior Vice President and Chief
Vice President and Controller
Financial Officer and Director
(Principal Accounting Officer)
(Principal Financial Officer)
Date: March 9, 2005
SIGNATURES
Pursuant to the requirements of Section 13 or 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.
JERSEY CENTRAL POWER & LIGHT COMPANY
BY: /s/ Stephen E. Morgan
Stephen E. Morgan
President
Date: March 9, 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 and in the capacities and on the date indicated:
/s/ Stephen E. Morgan
/s/ Richard H. Marsh
Stephen E. Morgan
Richard H. Marsh
President and Director
(Principal Executive Officer)
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
/s/ Harvey L. Wagner
/s/ Leila L. Vespoli
Harvey L. Wagner
Leila L. Vespoli
Vice President and Controller
(Principal Accounting Officer)
Senior Vice President and
General Counsel and Director
/s/ Charles E. Jones
/s/ Stanley C. Van Ness
Charles E. Jones
Stanley C. Van Ness
Director
Director
/s/ Gelorma E. Persson
/s/ Mark A. Julian
Gelorma E. Persson
Mark A. Julian
Director
Director
/s/ Bradley S. Ewing
Bradley S. Ewing
Director
Date: March 9, 2005
SIGNATURES
Pursuant to the requirements of Section 13 or 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.
METROPOLITAN EDISON COMPANY
BY: /s/ Anthony J. Alexander
Anthony J. Alexander
President
Date: March 9, 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 and in the capacities and on the date indicated:
/s/ Anthony J. Alexander
/s/ Richard R. Grigg
Anthony J. Alexander
Richard R. Grigg
President and Director
Executive Vice President and Chief
(Principal Executive Officer)
Operating Officer and Director
/s/ Richard H. Marsh
/s/ Harvey L. Wagner
Richard H. Marsh
Harvey L. Wagner
Senior Vice President and Chief
Vice President and Controller
Financial Officer and Director
(Principal Accounting Officer)
(Principal Financial Officer)
Date: March 9, 2005
SIGNATURES
Pursuant to the requirements of Section 13 or 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.
PENNSYLVANIA ELECTRIC COMPANY
BY: /s/ Anthony J. Alexander
Anthony J. Alexander
President
Date: March 9, 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 and in the capacities and on the date indicated:
/s/ Anthony J. Alexander
/s/ Richard R. Grigg
Anthony J. Alexander
Richard R. Grigg
President and Director
Executive Vice President and Chief
(Principal Executive Officer)
Operating Officer and Director
/s/ Richard H. Marsh
/s/ Harvey L. Wagner
Richard H. Marsh
Harvey L. Wagner
Senior Vice President and Chief
Vice President and Controller
Financial Officer and Director
(Principal Accounting Officer)
(Principal Financial Officer)
Date: March 9, 2005
SIGNATURES
Pursuant to the requirements of Section 13 or 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.
PENNSYLVANIA POWER COMPANY
BY: /s/ Anthony J. Alexander
Anthony J. Alexander
President
Date: March 9, 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 and in the capacities and on the date indicated:
/s/ Anthony J. Alexander
/s/ Richard R. Grigg
Anthony J. Alexander
Richard R. Grigg
President and Director
Executive Vice President and Chief
(Principal Executive Officer)
Operating Officer and Director
/s/ Richard H. Marsh
/s/ Harvey L. Wagner
Richard H. Marsh
Harvey L. Wagner
Senior Vice President and Chief
Vice President and Controller
Financial Officer and Director
(Principal Accounting Officer)
(Principal Financial Officer)
Date: March 9, 2005