10-Q/A 1 te_10q-a.txt AMENDMENT NO. 2 SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q/A AMENDMENT NO. 2 (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------------- ----------------- Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. ----------- ----------------------------------- ------------------ 1-3583 THE TOLEDO EDISON COMPANY 34-4375005 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ---- ----- Indicate by check mark whether each registrant is an accelerated filer ( as defined in Rule 12b-2 of the Act): Yes X No ---- ----- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: OUTSTANDING CLASS AS OF MAY 9, 2003 ----- ----------------- The Toledo Edison Company, $5 par value 39,133,887 This Form 10-Q/A includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential", "expect", "believe", "estimate" and similar words. This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms "anticipate", "potential", "expect", "believe", "estimate" and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), availability and cost of capital, inability of the Davis-Besse Nuclear Power Station to restart (including because of an inability to obtain a favorable final determination from the Nuclear Regulatory Commission) in the fall of 2003, inability to accomplish or realize anticipated benefits from strategic goals, further investigation into the causes of the August 14, 2003, power outage, and other similar factors. EXPLANATORY NOTE We are filing this Amendment No. 2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (the "Report") to correct typographical errors in Item 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION of the Report. This Amendment has no effect on previously reported results of operations or financial position. The complete amended and restated Item 2, which is included in its entirety below, reflects the following corrections: Under the heading "RESTATEMENTS": Under the subheading "Transition Cost Amortization": In the last sentence of the second paragraph, the reference to the three months ended June 30, 2002 and 2003 should have read March 31, 2002 and 2003. Under the heading "CAPITAL RESOURCES AND LIQUIDITY": Under the subheading "Cash Flows from Operating Activities", the column in the table showing the 2003 amounts is corrected as follows: Operating Cash Flows As originally filed As corrected ------------------------------------------------------------- (In millions) Cash earnings (1) $ 30 $ 37 Working capital and other (60) (67) ------------------------------------------------------------- Total $(30) $(30) ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Under the subheading "Cash Flows from Operating Activities", the column in the table showing the 2002 amounts is corrected as follows: Operating Cash Flows As originally filed As corrected ------------------------------------------------------------- (In millions) Cash earnings (1) $29 $42 Working capital and other 37 24 ------------------------------------------------------------- Total $66 $66 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. TABLE OF CONTENTS Pages Part I Financial Information The Toledo Edison Company Consolidated Statements of Income........................ * Consolidated Balance Sheets.............................. * Consolidated Statements of Cash Flows.................... * Report of Independent Auditors........................... * Management's Discussion and Analysis of Results of Operations and Financial Condition..................... 1-9 Part II. Other Information * Indicates the items that have not been revised and are not included in this Form 10-Q/A. Reference is made to the original 10-Q, as previously amended, for complete text of such items. THE FOLLOWING ITEM HAS BEEN AMENDED IN THIS AMENDMENT No. 2: PART I ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THE TOLEDO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE conducts business in portions of Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain them as their power supplier. TE provides power directly to wholesale customers under previously negotiated contracts, as well as to alternative energy suppliers under TE's transition plan. TE has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of TE are provided by FES - an affiliated company. RESTATEMENTS As further discussed in Note 1 to the Consolidated Financial Statements, FirstEnergy is restating its consolidated financial statements for the year ended December 31, 2002 and the three months ended March 31, 2003 and 2002. The restatements reflect a change in the method of amortizing the costs being recovered under the Ohio transition plan and recognition of above-market values of certain leased generation facilities. Transition Cost Amortization As discussed in Note 4 - Regulatory Matters, FirstEnergy's Ohio electric utilities recover transition costs, including regulatory assets, through an approved transition plan filed under Ohio's electric utility restructuring legislation. The plan, which was approved in July 2000, provides for the recovery of costs from January 1, 2001 through a fixed number of kilowatt-hour sales to all customers that continue to receive regulated transmission and distribution service, which is expected to end in 2007 for TE. FirstEnergy and the Ohio utilities amortize transition costs using the effective interest method. The amortization schedules originally developed at the beginning of the transition plan in 2001 in applying this method were based on total transition revenues, including revenues designed to recover costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments) but not in the financial statements prepared under GAAP. The Ohio electric utilities have revised their amortization schedules under the effective interest method to consider only revenues relating to transition regulatory assets recognized on the GAAP balance sheet. The impact of this change will result in higher amortization of these regulatory assets in the first several years of the transition cost recovery period, versus the method previously applied. The change in method results in no change in total amortization of the regulatory assets recovered under the transition period through the end of 2009. The amortization expense under the revised method (see Note 1) increased by $16.4 million and $15.4 million for the three months ended March 31, 2002 and 2003, respectively. Above-Market Lease Costs In 1997, FirstEnergy Corp. was formed through a merger between OE and Centerior Energy Corp. The merger was accounted for as an acquisition of Centerior, the parent company of TE, under the purchase accounting rules of Accounting Principles Board (APB) Opinion No. 16. In connection with the reassessment of the accounting for the transition plan, FirstEnergy reassessed its accounting for the Centerior purchase and determined that above market lease liabilities should have been recorded at the time of the merger. Accordingly, as of 2002, FirstEnergy recorded additional adjustments associated with the 1997 merger between OE and Centerior to reflect certain above market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE had previously entered into sale-leaseback arrangements. and TE recorded an increase in goodwill related to the above market lease costs for Beaver Valley Unit 2 since regulatory accounting for nuclear generating assets had been discontinued prior to the merger date and it was determined that this additional liability would have increased goodwill at the date of the merger. The corresponding impact of the above market lease liabilities for the Bruce Mansfield Plant were recorded as regulatory assets because regulatory accounting had not been discontinued at that time for the fossil generating assets and recovery of these liabilities was provided for under the transition plan. 1 The total above market lease obligation of $111 million associated with Beaver Valley Unit 2 will be amortized through the end of the lease term in 2017. The additional goodwill has been recorded on a net basis, reflecting amortization that would have been recorded through 2001 when goodwill amortization ceased with the adoption of SFAS 142. The total above market lease obligation of $298 million associated with the Bruce Mansfield Plant is being amortized through the end of 2016. Before the start of the transition plan in 2001, the regulatory asset would have been amortized at the same rate as the lease obligation. Beginning in 2001, the remaining unamortized regulatory asset would have been included in TE's amortization schedule for regulatory assets and amortized through the end of the recovery period - approximately 2007 for TE. RESULTS OF OPERATIONS Earnings on common stock in the first quarter of 2003 increased to $21.9 million from a loss of $4.4 million in the first quarter of 2002. Earnings on common stock in the first quarter of 2003 included an after-tax credit of $25.6 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations." Loss before the cumulative effect was $1.4 million in the first quarter of 2003, compared to net income of $0.3 million for the same period of 2002. Improved results in the first quarter of 2003 reflected reduced financing costs and lower operating expenses. Substantially offsetting these improvements were lower operating revenues from reduced kilowatt-hour sales. Operating revenues decreased by $20.7 million or 8.2% in the first quarter of 2003 from the same period in 2002. The lower revenues resulted from reduced kilowatt-hour sales which were partially offset by the effects of colder weather on distribution deliveries to residential and commercial customers. Kilowatt-hour sales to retail customers declined by 3.5% in the first quarter of 2003 from the same quarter of 2002, which reduced generation sales revenue by $11.6 million. Electric generation services provided by alternative suppliers as a percent of total sales deliveries in TE's franchise area increased to 21.8% in the first quarter of 2003 from 14.4% in the first quarter of 2002. Distribution deliveries increased 5.8% in the first quarter of 2003 compared to the corresponding quarter of 2002, with increases in all customer sectors (residential, commercial and industrial). As a result, revenues from electricity throughput increased by $20.7 million in the first quarter of 2003 from the first quarter of 2002. The increase reflected higher unit prices, which accounted for two-thirds of the increase and higher volumes. Distribution deliveries benefited from substantially higher residential and commercial demand, due in larger part to colder than normal weather, that was moderated by the continued effect of a sluggish economy and its impact on demand by industrial customers in TE's franchise area. Transition plan incentives, provided to customers to encourage switching to alternative energy providers, reduced operating revenues by $2.2 million in the first quarter of 2003 compared with the same period last year. These revenue reductions are deferred for future recovery under TE's transition plan and do not materially affect current period earnings. Sales revenues from wholesale customers decreased by $21.0 million (primarily to FES) in the first quarter of 2003 compared with the first quarter of 2002, due to reduced nuclear generation from the extended outage of the Davis-Besse Plant (see Davis-Besse Restoration). Changes in electric generation sales and distribution deliveries in the first quarter of 2003 from the first quarter of 2002 are summarized in the following table: Changes in Kilowatt-Hour Sales ---------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (3.5)% Wholesale............................. (28.1)% ---------------------------------------------------- Total Electric Generation Sales........... (15.2)% ==================================================== Distribution Deliveries: Residential........................... 10.9% Commercial............................ 11.7% Industrial............................ 0.3% --------------------------------------------------- Total Distribution Deliveries............. 5.8% =================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $15.5 million in the first quarter of 2003 from the first quarter of 2002. The following table presents changes from the prior year by expense category. 2 Operating Expenses and Taxes - Change ---------------------------------------------------------------- Increase (Decrease) (In millions) (Revised) Fuel............................................. $ (3.7) Purchased power costs............................ (8.2) Nuclear operating costs.......................... (9.1) Other operating costs............................ 6.9 ---------------------------------------------------------------- Total operation and maintenance expenses....... (14.1) Provision for depreciation and amortization...... (2.2) General taxes.................................... 1.3 Income taxes..................................... (0.5) ---------------------------------------------------------------- Total operating expenses and taxes............. $(15.5) ================================================================ Lower fuel costs in the first quarter of 2003, compared with the same quarter of 2002, resulted from reduced nuclear generation (down 30%). The lower purchased power costs reflected fewer kilowatt-hours required for customer needs. Two scheduled refueling outages in the first quarter of 2002 (Beaver Valley Unit 2 and Davis-Besse) and the absence of refueling outages in the first quarter of 2003 more than offset incremental costs associated with the extended outage of Davis-Besse, producing the lower nuclear operating costs. The increase in other operating costs resulted in part from higher employee benefit costs. Charges for depreciation and amortization decreased $2.2 million in the first quarter of 2003 compared with the first quarter of 2002, attributable to several factors - higher shopping incentive deferrals ($2.2 million) and lower charges resulting from the implementation of SFAS 143 ($4.0 million), including revised service life assumptions for generating plants ($3.0 million). Nearly offsetting these decreases were increased amortization of regulatory assets being recovered under TE's transition plan ($2.5 million) and recognition of depreciation on the Bay Shore generating plant ($1.5 million), which had been held pending sale in the first quarter of 2002 but was subsequently retained by FirstEnergy in the fourth quarter of 2002. Net Interest Charges Net interest charges continued to trend lower, decreasing by $4.7 million in the first quarter of 2003 from the same period last year, reflecting security redemptions and refinancings since the end of the first quarter of 2002. TE's net debt redemptions totaled $53.4 million during the first quarter of 2003, which will result in annualized savings of $4.2 million. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an after-tax credit to net income of $25.6 million. TE identified applicable legal obligations as defined under the new accounting standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $41.1 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $5.5 million. The asset retirement obligation liability at the date of adoption was $172 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, TE had recorded decommissioning liabilities of $179.6 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $43.8 million increase to income, or $25.6 million net of income taxes. CAPITAL RESOURCES AND LIQUIDITY TE's cash requirements in 2003 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next three years, TE expects to meet its contractual obligations with cash from operations. Thereafter, TE expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of March 31, 2003, TE had $1.4 million of cash and cash equivalents, compared with $20.7 million as of December 31, 2002. The major sources for changes in these balances are summarized below. 3 Cash Flows From Operating Activities Cash provided by (used for) operating activities during the first quarter of 2003, compared with the corresponding period in 2002 were as follows: Operating Cash Flows 2003 2002 ------------------------------------------------------------- (In millions) Cash earnings (1).................... $37 $42 Working capital and other............ (67) 24 ------------------------------------------------------------- Total................................ $(30) $66 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash used for operating activities was $30 million in the first quarter of 2003, a $96 million change from the $66 million provided by operating activities in the first quarter of 2002. The decrease in funds from operating activities resulted from a $97 million decrease in working capital - principally reduced accounts payable (primarily to associated companies) which contributed $56.8 million to the decrease in working capital requirements. Cash Flows From Financing Activities In the first quarter of 2003, net cash provided from financing activities increased to $23 million from net cash used for financing of $25 million in the first quarter of 2002. The increase in cash provided from financing activities primarily resulted from additional short-term borrowings from associated companies and a slight reduction in security redemptions and repayments. TE had approximately $7.9 million of cash and temporary investments and approximately $248 million of short-term indebtedness as of March 31, 2003. TE is currently precluded from issuing first mortgage bonds or preferred stock based upon applicable earnings coverage tests as of March 31, 2003. Cash Flows From Investing Activities Net cash used for investing activities decreased $26 million between the first quarter of 2003 and the same quarter of 2002 due to reduced capital expenditures and a reduction in the Shippingport Capital Trust investment. During the last three quarters of 2003, capital requirements for property additions and capital leases are expected to be about $52 million, including $9 million for nuclear fuel. TE has additional requirements of approximately $43 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2003. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. On January 21, 2003, Standard and Poor's (S&P) indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa, which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining FirstEnergy's current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the JCP&L rate case, successful hedging of its short power position, and continued capture of projected merger savings. On April 14, 2003, S&P again affirmed its "BBB" corporate credit rating for FirstEnergy. The S&P outlook remained negative, but S&P improved FirstEnergy's business position from a "6" to a "5" (on a scale of 1 to 10 with 1 considered the least risky). S&P also reiterated that the key issues being monitored by the agency included the timely restart of Davis-Besse, the JCP&L rate case, capture of merger synergies, and controlling capital expenditures at estimated levels. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt, could put additional pressure on the credit ratings of FirstEnergy and, correspondingly, its subsidiaries, including TE. On August 14, 2003, Moody's Investors Service placed the debt ratings of FirstEnergy and all of its subsidiaries under review for possible downgrade. Moody's stated that the review was prompted by: (1) weaker than expected operating performance and cash flow generation; (2) less progress than expected in reducing debt; (3) continuing high leverage relative to its peer group; and (4) negative impact on cash flow and earnings from the continuing nuclear plant outage at Davis-Besse. Moody's further stated that, in anticipation of Davis-Besse returning to service in the near future and FirstEnergy's continuing to significantly reduce debt and improve its financial profile, "Moody's does not expect that the outcome of the review will result in FirstEnergy's senior unsecured debt rating falling below investment-grade." 4 Other Obligations Obligations not included on TE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of March 31, 2003, the present value of these sale and leaseback operating lease commitments, net of trust investments, totaled $509 million. TE sells substantially all of its retail customer receivables, which provided $49 million of off-balance sheet financing as of March 31, 2003. EQUITY PRICE RISK Included in TE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $90 million as of March 31, 2003 and December 31, 2002. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $9 million reduction in fair value as of March 31, 2003. OUTLOOK Beginning in 2001, TE's customers were able to select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. TE has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE's Ohio customers elects to obtain power from an alternative supplier, TE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. TE has continuing PLR responsibility to its franchise customers through December 31, 2005. Regulatory assets are costs which have been authorized by The Public Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. Regulatory assets declined $20.8 million to $557.4 million as of March 31, 2003 from the balance as of December 31, 2002, resulting from recovery of transition plan regulatory assets. As part of TE's transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. TE is also required to provide 160 megawatts (MW) of low cost supply to unaffiliated alternative suppliers that serve customers within its service area. TE's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. Davis-Besse Restoration On April 30, 2002, the Nuclear Regulatory Commission (NRC) initiated a formal inspection process at the Davis-Besse nuclear plant. This action was taken in response to corrosion found by FENOC in the reactor vessel head near the nozzle penetration hole during a refueling outage in the first quarter of 2002. The purpose of the formal inspection process is to establish criteria for NRC oversight of the licensee's performance and to provide a record of the major regulatory and licensee actions taken, and technical issues resolved, leading to the NRC's approval of restart of the plant. Restart activities include both hardware and management issues. In addition to refurbishment and installation work at the plant, FirstEnergy has made significant management and human performance changes with the intent of establishing the proper safety culture throughout the workforce. Work was completed on the reactor head during 2002 and is continuing on efforts designed to enhance the unit's reliability and performance. FirstEnergy is also accelerating maintenance work that had been planned for future refueling and maintenance outages. At a meeting with the NRC in November 2002, FirstEnergy discussed plans to test the bottom of the reactor for leaks and to install a state-of-the-art leak-detection system around the reactor. The additional maintenance work being performed has expanded the previous estimates of restoration work. FirstEnergy anticipates that the unit will be ready for restart in the first half of the summer of 2003 after completion of the additional maintenance work and regulatory reviews. The NRC must authorize restart of the plant following its formal inspection process before the unit can be returned to service. While the additional maintenance work has delayed FirstEnergy's plans to reduce debt levels FirstEnergy believes such investments in the unit's future safety, reliability and performance to be essential. 5 Significant delays in Davis-Besse's return to service, which depends on the successful resolution of the management and technical issues as well as NRC approval, could trigger an evaluation for impairment of the nuclear plant (see Significant Accounting Policies below). Incremental expenses associated with the extended Davis-Besse outage in the first quarter of 2003 totaled $88.6 million, including $36.3 million for maintenance work and $52.3 million for fuel and purchased power. TE's ownership share is 48.62% of those expenses. It is anticipated that an additional $13.7 million in maintenance costs will be spent during the remainder of the Davis-Besse outage. Replacement power costs are expected to be $15 million per month in the non-summer months and $20-25 million per month during the summer. Environmental Matters TE believes it is in compliance with the current sulfur dioxide (SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized regulations requiring additional NOx reductions in the future from our Ohio and Pennsylvania facilities. Various regulatory and judicial actions have since sought to further define NOx reduction requirements (see Note 2C - Environmental Matters). TE continues to evaluate its compliance plans and other compliance options. Violations of federally approved SO2 regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day a 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. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants. The EPA identified mercury as the hazardous air pollutant of greatest concern. The EPA established a schedule to propose regulations by December 2003 and issue final regulations by December 2004. The future cost of compliance with these regulations may be substantial. 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 has issued its final regulatory determination 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. TE believes it is in compliance with the current SO2 and nitrogen oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990. SO2 reductions are being achieved by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOx reductions 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' Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx emissions from projected 2007 emissions) across a region of nineteen states and the District of Columbia, including New Jersey, Ohio and Pennsylvania, based on a conclusion that such NOx emissions are contributing significantly to ozone pollution in the eastern United States. State Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx budgets established by the EPA. Pennsylvania submitted a SIP that requires compliance with the NOx budgets at the Companies' Pennsylvania facilities by May 1, 2003 and Ohio submitted a SIP that requires compliance with the NOx budgets at the Companies' Ohio facilities by May 31, 2004. TE has been named as a "potentially responsible party" (PRP) 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 be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of March 31, 2003, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. TE has total accrued liabilities of approximately $0.2 million as of March 31, 2003. The effects of compliance on TE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect its earnings and competitive position to the extent TE competes with companies that are not subject to such regulations 6 and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. TE believes it is in material compliance with existing regulations, but is unable to predict how and when applicable environmental regulations may change and what, if any, the effects of any such change would be. Legal Matters Various lawsuits, claims and proceedings relayed to TE's normal business operations are pending against TE, the most significant of which are described above. SIGNIFICANT ACCOUNTING POLICIES TE prepares its consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect TE's financial results. All of TE's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting those specific factors. TE's more significant accounting policies are described below. Regulatory Accounting TE is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine TE is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in Ohio, a significant amount of regulatory assets have been recorded. As of March 31, 2003, TE's regulatory assets totaled $557.4 million. TE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition TE follows the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet been billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over distribution lines o Allocations to distribution companies within the FirstEnergy system o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. 7 In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, FirstEnergy reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. The market values of FirstEnergy's pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002 and 2001, plan assets earned (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon FirstEnergy's projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, FirstEnergy will not be required to fund its pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to the 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In developing TE's restructuring plan, the PUCO determined allowable transition costs based on amounts recorded on the EUOC's regulatory books. These costs exceeded those deferred or capitalized on TE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). TE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the transition plan for each respective company. In computing the transition cost amortization, TE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," TE periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment other than of a temporary nature has occurred, TE recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates its goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value including goodwill, an impairment for goodwill must be recognized in the financial statements. If impairment were to occur, TE would recognize a loss - calculated as the difference between the implied fair value of a reporting unit's goodwill and the carrying value of the goodwill. TE's annual review was completed in the third quarter of 2002. The results of that review indicated no impairment of goodwill. The forecasts used in TE's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on its future evaluations of goodwill. As of March 31, 2003, TE had approximately $505 million of goodwill. 8 RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (TE's third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. TE currently has transactions which may fall within the scope of this interpretation and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. TE currently consolidates the majority of these entities and believes it will continue to consolidate following the adoption of FIN 46. One of these entities TE is currently consolidating is the Shippingport Capital Trust, which reacquired a portion of the off-balance sheet debt issued in connection with the sale and leaseback of its interest in the Bruce Mansfield Plant. Ownership of the trust includes a 4.85 percent interest by nonaffiliated parties and a 0.34 percent equity interest by Toledo Edison Capital Corp., a majority owned subsidiary. 9 PART II. OTHER INFORMATION --------------------------- Item 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit Number ------- TE 31.1 Certification letter from chief executive officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. 31.2 Certification letter from chief financial officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. 32.1 Certification letter from chief executive officer and chief financial officer, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE has not filed as an exhibit to this Form 10-Q/A any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of TE, but hereby agrees to furnish to the Commission on request any such documents. (b) Reports on Form 8-K TE TE filed eleven reports on Form 8-K since December 31, 2002. A report dated January 17, 2003 reported updated information related with efforts to prepare Davis-Besse for a safe and reliable return to service. A report dated March 11, 2003 reported updated Davis-Besse information including the installation of the new reactor head on the reactor vessel. A report dated March 17, 2003 reported updated Davis-Besse information. A report dated April 16, 2003 reported Davis-Besse information. A report dated May 1, 2003 reported an updated Davis-Besse ready for restart schedules. A report dated May 9, 2003 reported updated Davis-Besse information. A report dated June 5, 2003 reported updated Davis Besse information. A report dated July 24, 2003, reported updates to the schedule and cost estimates for Davis-Besse. A report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI and TE financial statements and restatement and reaudit of 2001 CEI and TE financial statements. A report dated August 7, 2003 reported the pending restatement and reaudit of 2000 CEI and TE financial statements. A report dated September 12, 2003 reported that FE, OE, CEI and TE have received an informal data request from the Securities and Exchange Commission related to the recent restatement of their 2002 financial statements. 10 SIGNATURE Pursuant to the requirements 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. September 24, 2003 THE TOLEDO EDISON COMPANY Registrant /s/ Harvey L. Wagner ---------------------------------------- Harvey L. Wagner Vice President and Controller Chief Accounting Officer 11