EX-13 31 pp_ex13-4.txt EX 13-4 PENN ANNUAL REPORT PENNSYLVANIA POWER COMPANY 2003 ANNUAL REPORT TO STOCKHOLDERS Pennsylvania Power Company, an electric utility operating company of FirstEnergy Corp. and a wholly owned subsidiary of Ohio Edison Company, provides electric service to approximately 156,000 customers in western Pennsylvania. Contents Page -------- ---- Selected Financial Data........................................... 1 Management's Discussion and Analysis.............................. 2-10 Statements of Income.............................................. 11 Balance Sheets.................................................... 12 Statements of Capitalization...................................... 13 Statements of Common Stockholder's Equity......................... 14 Statements of Preferred Stock..................................... 14 Statements of Cash Flows.......................................... 15 Statements of Taxes............................................... 16 Notes to Financial Statements..................................... 17-30 Reports of Independent Auditors................................... 31-32
PENNSYLVANIA POWER COMPANY SELECTED FINANCIAL DATA 2003 2002 2001 2000 1999 --------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) Operating Revenues...................... $526,867 $506,407 $498,401 $383,112 $ 329,234 ======== ======== ======== ======== ========== Operating Income........................ $ 47,320 $ 60,922 $ 55,178 $ 39,979 $ 32,063 ======== ======== ======== ======== ========== Income Before Cumulative Effect of Accounting Change................. $ 37,833 $ 47,717 $ 41,041 $ 22,847 $ 12,648 ======== ======== ======== ======== ========== Net Income.............................. $ 48,451 $ 47,717 $ 41,041 $ 22,847 $ 12,648 ======== ======== ======== ======== ========== Earnings on Common Stock................ $ 45,263 $ 44,018 $ 37,338 $ 19,143 $ 8,278 ======== ======== ======== ======== ========== Total Assets............................ $879,379 $907,748 $960,097 $988,909 $1,015,616 ======== ======== ======== ======== ========== CAPITALIZATION AS OF DECEMBER 31: Common Stockholder's Equity............. $230,786 $229,374 $223,788 $213,851 $ 199,608 Preferred Stock- Not Subject to Mandatory Redemption.. 39,105 39,105 39,105 39,105 39,105 Subject to Mandatory Redemption...... -- 13,500 14,250 15,000 15,000 Long-Term Debt.......................... 130,358 185,499 262,047 270,368 274,821 -------- -------- -------- -------- ---------- Total Capitalization.................... $400,249 $467,478 $539,190 $538,324 $ 528,534 ======== ======== ======== ======== ========== CAPITALIZATION RATIOS: Common Stockholder's Equity............. 57.7% 49.1% 41.5% 39.7% 37.8% Preferred Stock- Not Subject to Mandatory Redemption.. 9.8 8.3 7.3 7.3 7.4 Subject to Mandatory Redemption...... -- 2.9 2.6 2.8 2.8 Long-Term Debt.......................... 32.5 39.7 48.6 50.2 52.0 ----- ----- ------ ----- ----- Total Capitalization.................... 100.0% 100.0% 100.0% 100.0% 100.0% ===== ===== ====== ===== ===== DISTRIBUTION KILOWATT-HOUR DELIVERIES (Millions): Residential............................. 1,506 1,533 1,391 1,387 1,325 Commercial.............................. 1,283 1,268 1,220 1,198 1,105 Industrial.............................. 1,464 1,505 1,540 1,665 1,495 Other................................... 6 6 6 6 6 ----- ----- ----- ----- ----- Total................................... 4,259 4,312 4,157 4,256 3,931 ===== ===== ===== ===== ===== CUSTOMERS SERVED: Residential............................. 137,170 136,410 134,956 121,066 117,440 Commercial.............................. 18,455 18,397 18,153 16,634 16,307 Industrial.............................. 219 220 224 177 175 Other................................... 85 85 87 87 87 ------- ------- ------- ------- ------- Total................................... 155,929 155,112 153,420 137,964 134,009 ======= ======= ======= ======= ======= NUMBER OF EMPLOYEES..................... 201 201 256 275 895
PENNSYLVANIA POWER COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion 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), adverse regulatory or legal decisions and the outcome of governmental investigations, availability and cost of capital, the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits from strategic goals, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities market, further investigation into the causes of the August 14, 2003, regional power outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to the outage, a denial of or material change to the Company's Application related to its Rate Stabilization Plan, and other similar factors. Results of Operations --------------------- Earnings on common stock in 2003 increased 2.8% to $45.3 million from $44.0 million in 2002. Earnings in 2003 included an after-tax credit of $10.6 million from the cumulative effect of an accounting change due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations," (see Note 1(H)). Income before the cumulative effect in 2003 decreased 20.7% to $37.8 million from $47.7 million in 2002. The lower results for 2003 were primarily due to higher nuclear operating costs and purchased power costs. These increased costs were partially offset by higher operating revenues, lower fuel costs and reduced financing costs. Earnings on common stock in 2002 increased 17.9% to $44.0 million from $37.3 million in 2001. The earnings increase in 2002 primarily resulted from increased operating revenues and lower financing costs, which were partially offset by higher operating expenses and taxes and reduced other income. Operating revenues increased by $20.5 million, or 4%, in 2003 as compared to 2002. The higher revenues primarily resulted from increased wholesale revenues of $24.6 million in 2003, along with higher retail generation sales revenues of $2.5 million due to higher unit prices -- partially offset by a 1% decrease in retail kilowatt-hour sales. These electric generation revenue increases were partially offset by $5.1 million of lower revenues from distribution deliveries. Wholesale revenue increases from sales to FirstEnergy Solutions Corp. (FES) reflected higher unit prices, which were partially offset by lower kilowatt-hour sales due to reduced nuclear generation available for sale to FES. Operating revenues increased by $8.0 million, or 1.6%, in 2002 as compared to 2001. The return of customers previously served by alternative generation suppliers contributed to the revenue increase. Retail kilowatt-hour sales increased by 7.8% in 2002 from the prior year, with increases in the residential and commercial sectors contributing to a $15.8 million increase in generation sales revenue. Sales of electric generation by alternative suppliers as a percent of total sales delivered in our franchise area decreased to 0.4% in 2002 from 4.1% in 2001. Distribution deliveries increased 3.7% in 2002 as compared to 2001, which increased revenues from electricity throughput by $3.9 million in 2002 from the prior year. The higher distribution deliveries resulted from additional residential and commercial demand due to warmer summer weather that was offset in part by the effect of continued sluggishness in the economy on demand by industrial customers. Sales revenues from wholesale customers decreased by $14.3 million in 2002 compared to 2001, due to a decline in market prices. Changes in KWH Sales 2003 2002 ------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (1.0)% 7.8% Wholesale............................. (11.6)% 12.0% ------------------------------------------------------------------- Total Electric Generation Sales......... (7.4)% 10.3% ================================================================== Distribution Deliveries: Residential........................... (1.8)% 10.2% Commercial and industrial............. (1.0)% 0.5% ------------------------------------------------------------------- Total Distribution Deliveries........... (1.3)% 3.7% ================================================================== 2 Operating Expenses and Taxes Total operating expenses and taxes increased by $34.1 million in 2003 and $2.3 million in 2002 from the prior year. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes 2003 2002 --------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel.......................................... $(3.7) $ 1.6 Purchased power costs......................... 8.8 5.1 Nuclear operating costs....................... 38.9 (24.6) Other operating costs......................... 2.6 5.4 -------------------------------------------------------------------- Total operation and maintenance expenses.... 46.6 (12.5) Provision for depreciation and amortization... (2.9) (0.3) General taxes................................. (2.0) 10.3 Income taxes.................................. (7.6) 4.8 -------------------------------------------------------------------- Total operating expenses and taxes.......... $34.1 $ 2.3 ===================================================================== Lower fuel costs in 2003, compared with 2002, resulted from reduced nuclear generation. The increased purchased power costs in 2003 reflected higher unit costs and increased kilowatt-hour purchases. Higher nuclear operating costs occurred, in large part, due to the refueling outages at Beaver Valley Unit 1 (65.00% ownership); Perry (5.24% ownership) and Beaver Valley Unit 2 (13.74% ownership) in 2003, compared with one refueling outage at Beaver Valley Unit 2 in 2002. Charges for depreciation and amortization decreased by $2.9 million in 2003 compared to 2002, primarily from lower charges resulting from the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," ($1.4 million for 2003) and revised service life assumptions for nuclear generating plants ($1.2 million for 2003). Higher fuel and purchased power costs in 2002 compared with 2001, resulted from a $4.2 million increase in power purchased from FES, reflecting higher kilowatt-hours purchased due to increased kilowatt-hour sales and lower unit prices. Nuclear operating costs decreased $24.6 million, primarily due to one less refueling outage in 2002 compared to 2001. The $5.4 million increase in other operating costs resulted principally from higher employee benefit costs. General taxes decreased $2 million in 2003 from 2002 principally due to settled property tax claims. General taxes increased by $10.3 million in 2002 from 2001 as a result of additional property taxes and gross receipt taxes. Net Interest Charges Net interest charges continued to trend lower, decreasing by $2.8 million in 2003 and by $2.2 million in 2002, compared to the prior year. We continued to redeem and refinance outstanding debt, with 2003 redemptions totaling $41.7 million (including mandatorily redeemable preferred stock). These redemptions will result in annualized savings of approximately $3.2 million. Cumulative Effect of Accounting Change Results for 2003 include an after-tax credit to net income of $10.6 million recorded upon the adoption of SFAS 143 in January 2003. We identified applicable legal obligations as defined under the new 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 $78 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $9 million. The ARO liability at the date of adoption was $121 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, we had recorded decommissioning liabilities of $120 million. We expect substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, it recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was an $18.2 million increase to income, or $10.6 million net of income taxes. Capital Resources and Liquidity ------------------------------- Through net debt and preferred stock redemptions, we continue to reduce the cost of debt and preferred stock, and improve our financial position in 2003. During 2003, we reduced our total outstanding debt by approximately $30.5 million. Preferred stock subject to mandatory redemption is now classified as debt under SFAS 150. 3 Changes in Cash Position As of December 31, 2003, we had $40,000 of cash and cash equivalents, compared with $1.2 million as of December 31, 2002. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Our net cash from operating activities is provided by our regulated energy services. Net cash provided from operating activities was $129 million in 2003, $106 million in 2002 and $93 million in 2001. Cash provided from 2003, 2002 and 2001 operating activities are as follows: Operating Cash Flows 2003 2002 2001 ------------------------------------------------------------- (In millions) Cash earnings (1)............. $ 98.8 $115.8 $101.6 Working capital and other..... 29.7 (10.0) (8.3) ------------------------------------------------------------- Total......................... $128.5 $105.8 $ 93.3 ============================================================= (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities increased to $129 million in 2003 compared with $106 million in 2002 due to a $40 million reduction in working capital and other requirements partially offset by a $17 million decrease in cash earnings. Cash Flows From Financing Activities In 2003 and 2002, the net cash used for financing activities of $76 million and $75 million, respectively, primarily reflects the redemptions of debt and preferred stock shown below and dividend payments. The following table provides details regarding new issues and redemptions during 2003 and 2002: Securities Issued or Redeemed 2003 2002 ------------------------------------------------------------- (In millions) New Issues ---------- Pollution Control Notes.............. $ -- $14.5 Short-Term Borrowings, Net........... 11.3 -- Redemptions ----------- First Mortgage Bonds................. 41.0 1.0 Pollution Control Notes.............. -- 14.5 Capital Fuel Leases.................. -- 40.7 Preferred Stock...................... 0.8 0.8 Other, principally redemption premiums........................... 0.1 0.6 -------------------------------------------------------------- $41.9 $57.6 In 2001, net cash flow used for financing activities totaled $51 million, primarily due to long-term debt redemptions and $31 million of dividend payments. We had about $0.4 million of cash and temporary investments and short-term indebtedness of $11.3 million as of December 31, 2003. At the end of 2003, we had the capability to issue $451 million of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings in 2003 under the earnings coverage test contained in our charter, we could issue $244 million of preferred stock (assuming no additional debt was issued). We have the ability to borrow from our regulated affiliates and FirstEnergy to meet our short-term working capital requirements. FirstEnergy Service Company administers this money pool and tracks surplus funds of FirstEnergy and the respective regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2003 was 1.47%. Our access to capital markets and costs of financing are dependent on the ratings of our securities, OE and FirstEnergy. The following table shows securities' ratings following the downgrade by Moody's Investors Service in February 2004. The ratings outlook on all securities is stable. 4 Ratings of Securities ----------------------------------------------------------------------------- Securities S&P Moody's Fitch ----------------------------------------------------------------------------- FirstEnergy Senior unsecured BB+ Baa3 BBB- OE Senior secured BBB Baa1 BBB+ Senior unsecured BB+ Baa2 BBB Preferred stock BB Ba1 BBB- Penn Senior secured BBB- Baa1 BBB+ Senior unsecured (1) BB+ Baa2 BBB Preferred stock BB Ba1 BBB- ------------------------------------------------------------------------------ (1) Penn's only senior unsecured debt obligations are pollution control revenue refunding bonds issued in the name of the Ohio Air Quality Development Authority to which this rating applies. On September 30, 2003, Fitch Ratings lowered the senior unsecured ratings of FirstEnergy to "BBB-" from "BBB." In addition, Fitch affirmed the ratings of OE and the Company. Fitch announced that the Rating Outlook is Stable for the securities of FirstEnergy, and all of the securities of its electric utility operating companies. Fitch stated that the changes to the long-term ratings were "driven by the high debt leverage of the parent, FirstEnergy. Despite management's commitment to reduce debt related to the GPU merger, subsequent cash flows have been vulnerable to unfavorable events, slowing the pace of FirstEnergy's debt reduction efforts. The Stable Outlook reflects the success of FirstEnergy's recent common equity offering and management's focus on a relatively conservative integrated utility strategy." On December 23, 2003, Standard & Poor's (S&P) lowered its corporate credit ratings on FirstEnergy and its regulated utility subsidiaries to "BBB-" from "BBB" and lowered FirstEnergy's senior unsecured debt rating to "BB+" from "BBB-". Except for OE's senior secured issue rating, which was left unchanged, all other subsidiary ratings were lowered one notch as well. The ratings were removed from CreditWatch with negative implications, where they had been placed by S&P on August 18, 2003, and the Ratings Outlook returned to Stable. The rating action followed a revision in S&P's assessment of FirstEnergy's consolidated business risk profile to `6' from `5' (`1' equals low risk, `10' equals high risk), with S&P citing operational and management challenges as well as heightened regulatory uncertainty for its revision of our business risk assessment score. S&P's rationale for its revisions in FirstEnergy's ratings included uncertainty regarding the timing of the Ohio Rate Plan filing, the pending final report on the August 14 regional outage (see Power Outage), the outcome of the remedial phase of litigation relating to the Sammis plant (see Environmental Matters), and the extended Davis-Besse outage and the related pending subpoena. S&P further stated that the restart of Davis-Besse and a supportive Ohio Rate Plan extension will be vital positive developments that would aid an upgrade of FirstEnergy's ratings. S&P's reduction of FirstEnergy's credit ratings in December 2003 triggered cash and letter-of-credit collateral calls in addition to higher interest rates for some outstanding borrowings. On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured debt to Baa3 from Baa2. The ratings of OE and the Company were confirmed. Moody's said that the lower ratings were prompted by: "1) high consolidated leverage with significant holding company debt, 2) a degree of regulatory uncertainty in the service territories in which the company operates, 3) risks associated with investigations of the causes of the August 2003 blackout, and related securities litigation, and 4) a narrowing of the ratings range for the FirstEnergy operating utilities, given the degree to which FirstEnergy increasingly manages the utilities as a single system and the significant financial interrelationship among the subsidiaries." Cash Flows From Investing Activities Net cash used in investing activities totaled $53.9 million in 2003. The net cash used for investing resulted from increased property additions and nuclear plant decommissioning trust investments partially offset by loan payments from the Company's parent company, OE. Expenditures for property additions include expenditures supporting our distribution of electricity. Net cash used in investing activities totaled $29.3 million in 2002. The net cash used for investing resulted from increased property additions, which were offset in part by loan payments from associated companies. In 2001, net cash used in investing activities totaled $45.9 million, principally due to property additions and loans to associated companies, which were offset in part by sales of assets to associated companies. Our cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing our net debt and preferred stock outstanding. Our capital spending for the period 2004-2006 is expected to be about $143 million (excluding nuclear fuel) of which approximately $64 million applies to 2004. Investments for additional nuclear fuel during the 2004-2006 period are 5 estimated to be approximately $34 million, of which about $20 million relates to 2004. During the same periods, our nuclear fuel investments are expected to be reduced by approximately $35 million and $17 million, respectively, as the nuclear fuel is consumed. We had no other material obligations as of December 31, 2003 that have not been recognized on our Balance Sheet. Contractual Obligations ----------------------- Our cash contractual obligations as of December 31, 2003 that we consider firm obligations are as follows:
Contractual Obligations Total 2004 2005-2006 2007-2008 Thereafter ----------------------------------------------------------------------------------------------------------------- (In millions) Long-term debt.................. $211 $63 $ 2 $ 2 $144 Preferred stock (1)............. 14 1 2 11 -- Short-term borrowings........... 11 11 -- -- -- Purchases (2)................... 121 20 30 28 43 ---------------------------------------------------------------------------------------------------------------- Total........................ $357 $95 $34 $41 $187 ================================================================================================================ (1) Subject to mandatory redemption. (2) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing.
Interest Rate Risk ------------------ Our exposure to fluctuations in market interest rates is reduced since a significant portion of our debt has fixed interest rates, as noted in the following table. The table below presents principal amounts and related weighted average interest rates by year of maturity for our investment portfolio, debt obligations and preferred stock with mandatory redemption provisions.
Comparison of Carrying Value to Fair Value ------------------------------------------------------------------------------------------------------------------ There- Fair Year of Maturity 2004 2005 2006 2007 2008 after Total Value ------------------------------------------------------------------------------------------------------------------- (Dollars in millions) Assets Investments Other Than Cash and Cash Equivalents- Fixed Income............... $6 $ 1 $1 $116 $124 $130 Average interest rate...... 7.8% 7.8% 7.8% 5.5% 5.6% __________________________________________________________________________________________________________________ Liabilities ------------------------------------------------------------------------------------------------------------------ Long-term Debt and Other Long-Term Obligations: Fixed rate.................... $63 $1 $1 $ 1 $1 $ 82 $149 $166 Average interest rate ..... 7.4% 9.7% 9.7% 9.7% 9.7% 6.5% 7.0% Variable rate................. $ 62 $ 62 $ 62 Average interest rate...... 1.8% 1.8% Preferred Stock Subject to Mandatory Redemption....... $ 1 $1 $1 $11 $ 14 $ 14 Average dividend rate...... 7.6% 7.6% 7.6% 7.6% 7.6% Short-term Borrowings......... $11 $ 11 $ 11 Average interest rate...... 1.7% 1.7% -------------------------------------------------------------------------------------------------------------------
Equity Price Risk ----------------- Included in our nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $50 million and $38 million as of December 31, 2003 and 2002, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of December 31, 2003 (see Note 1(K) - Cash and Financial Instruments). Outlook ------- We have 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. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. 6 Regulatory Matters- In late 2003, the Pennsylvania Public Utility Commission (PPUC) issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. We are currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. It is expected that these Orders will be finalized in March 2004. On January 16, 2004, the PPUC initiated a formal investigation of our levels of compliance with the Public Utility Code and the PPUC's regulations and orders with regard to reliable electric service. Hearings will be held in August 2004 in this investigation and the Administrative Law Judge has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order before December 16, 2004. We are unable to predict the outcome of the investigation or the impact of the PPUC Order. Environmental Matters We believe we are 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 5(C) - Environmental Matters). We continue to evaluate our compliance plans and other compliance options. Clean Air Act Compliance 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 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. We cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. W. H. Sammis Plant In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. 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. 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, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated 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 the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2003. 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. 7 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 failed to receive the two-thirds vote of the U.S. 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% through 2012. We cannot currently estimate the financial impact of climate change policies although the potential restrictions on carbon dioxide (CO2) emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Company is lower than many regional competitors due to the Company's diversified generation sources which includes the low or non-CO2 emitting gas-fired and nuclear generators. Power Outage On August 14, 2003, various states in the northeast United States and part of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. FirstEnergy continues to accumulate data and evaluate the status of its electrical system prior to and during the outage event, and continues to cooperate with the U.S.-Canada Power System Outage Task Force (Task Force) investigating the August 14th outage. The interim report issued by the Task Force on November 18, 2003 concluded that the problems leading up to the outage began in FirstEnergy's service area. Specifically, the interim report concludes, among other things, that the initiation of the August 14th outage resulted from the coincidence on that afternoon of the following events: (1) inadequate situational awareness at FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its transmission rights of way; and (3) failure of the interconnected grid's reliability organizations (Midwest ISO and PJM Interconnection) to provide effective diagnostic support. We believe that the interim report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th outage and that it does not adequately address the underlying causes of the outage. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct problems identified by the Task Force as events contributing to the August 14th outage and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software and improve the training of control room operators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding. On December 24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part of Ohio's power grid. The study has commenced and will examine the stability of the grid in critical points in the Cleveland and Akron areas; the status of projected power reserves during summer 2004 through 2008; and the need for new transmission lines or other grid projects. The FERC ordered the study to be completed within 120 days. At this time, we do not know how the results of the study will impact FirstEnergy. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described above. Critical Accounting Policies ---------------------------- We prepare our 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 our financial results. All of our 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. Our more significant accounting policies are described below. Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on our costs that the regulatory agencies determine we are 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. We continually review 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 We follow 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 year. The determination of unbilled revenues requires management to make various estimates including: 8 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 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 we make to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also 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. Plan amendments to retirement health care benefits in 2003 and 2002, related to changes in benefits provided and cost-sharing provisions, reduced FirstEnergy's obligation by $123 million and $121 million, respectively. In early 2004, FirstEnergy announced that it would amend the benefit provisions of its health care benefits plan and both employees and retirees would share in more of the benefit 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. 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 recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% and 7.25% used as of December 31, 2002 and 2001, respectively. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by our pension trusts. In 2003, 2002 and 2001, plan assets actually earned 24.0%, (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in 2003 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and FirstEnergy's pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. As a result of GPU Service Inc. merging with FirstEnergy Service Company in the second quarter of 2003, operating company employees of GPU Service were transferred to the former GPU operating companies. Accordingly, FirstEnergy requested an actuarial study to update the pension liabilities for each of its subsidiaries. Based on the actuary's report, our accrued pension costs as of June 30, 2003 increased by $16 million. The corresponding adjustment related to this change decreased other comprehensive income and deferred income taxes and increased the payable to associated companies. Due to the increased market value of our pension plan assets, we reduced our minimum liability as prescribed by SFAS 87 as of December 31, 2003 by $16 million, recording an increase of $2 million in an intangible asset and crediting OCI by $11 million (offsetting previously recorded deferred tax benefits by $7 million). The remaining balance in OCI of $12 million will reverse in future periods to the extent the accumulated benefit obligation exceeds the fair value of trust assets. The accrued pension cost was reduced to $15 million as of December 31, 2003. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. However, health care cost trends have significantly increased and will affect future OPEB costs. FirstEnergy's pension and OPEB expenses in 2004 are expected to decrease by $38 million and $34 million, respectively. These reductions reflect the actual performance of pension plan assets and amendments to the health care benefits plan announced in early 2004 which result in employees and retirees sharing more of the benefit costs. The reduction in OPEB costs for 2004 does not reflect the impact of the new Medicare law signed by President 9 Bush in December 2003 due to uncertainties regarding some of its new provisions (see Note 1(I)). The 2003 and 2002 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining FirstEnergy's 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. The effect on FirstEnergy's pension and OPEB costs and liabilities from changes in key assumptions are as follows:
Increase in Costs from Adverse Changes in Key Assumptions ----------------------------------------------------------------------------------------------- Assumption Adverse Change Pension OPEB Total ----------------------------------------------------------------------------------------------- (In millions) Discount rate................ Decrease by 0.25% $ 10 $ 5 $ 15 Long-term return on assets... Decrease by 0.25% $ 8 $ 1 $ 9 Health care trend rate....... Increase by 1% na $26 $ 26 Increase in Minimum Liability ----------------------------- Discount rate................ Decrease by 0.25% $104 na $104 ----------------------------------------------------------------------------------------------
Long-Lived Assets In accordance with SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might 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 has occurred, we recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgement about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, we recognize an ARO for the future decommissioning of our nuclear power plants. The ARO liability represents an estimate of the fair value of our current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. We used an expected cash flow approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements") to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS ADOPTED SFAS 143, "Accounting for Asset Retirement Obligations" In January 2003, Penn implemented SFAS 143 which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an asset retirement obligation in the period in which it is incurred. See Notes 1(E) and 1(H) for further discussions of SFAS 143. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the beginning of the first interim period beginning after June 15, 2003 for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, we reclassified as debt our preferred stock subject to mandatory redemption with a carrying value of approximately $14 million as of December 31, 2003. Dividends on preferred stock subject to mandatory redemption on our Statements of Income, which were not included in net interest charges prior to the adoption of SFAS 150, are now included in net interest charges for the six months ended December 31, 2003. 10
PENNSYLVANIA POWER COMPANY STATEMENTS OF INCOME For the Years Ended December 31, 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES (Note 1(J))............................................ $526,867 $506,407 $498,401 -------- -------- -------- OPERATING EXPENSES AND TAXES: Fuel and purchased power (Note 1(J))................................... 187,086 181,968 175,257 Nuclear operating costs................................................ 128,896 90,024 114,623 Other operating costs (Note 1(J))...................................... 53,137 50,523 45,133 -------- -------- -------- Total operation and maintenance expenses............................. 369,119 322,515 335,013 Provision for depreciation and amortization............................ 53,806 56,763 57,087 General taxes.......................................................... 22,458 24,474 14,214 Income taxes........................................................... 34,164 41,733 36,909 -------- -------- -------- Total operating expenses and taxes................................... 479,547 445,485 443,223 -------- -------- -------- OPERATING INCOME.......................................................... 47,320 60,922 55,178 OTHER INCOME (Note 1(J)).................................................. 2,850 1,960 3,185 -------- -------- -------- INCOME BEFORE NET INTEREST CHARGES........................................ 50,170 62,882 58,363 -------- -------- -------- NET INTEREST CHARGES: Interest on long-term debt............................................. 14,228 15,521 16,971 Allowance for borrowed funds used during construction.................. (3,189) (1,509) (850) Other interest expense................................................. 1,298 1,153 1,201 -------- -------- -------- Net interest charges................................................. 12,337 15,165 17,322 -------- -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE...................... 37,833 47,717 41,041 Cumulative effect of accounting change (net of income taxes of $7,532,000) (Note 1(H))............................................................ 10,618 -- -- -------- -------- -------- NET INCOME................................................................ 48,451 47,717 41,041 PREFERRED STOCK DIVIDEND REQUIREMENTS..................................... 3,188 3,699 3,703 -------- -------- -------- EARNINGS ON COMMON STOCK.................................................. $ 45,263 $ 44,018 $ 37,338 ======== ======== ======== The accompanying Notes to Financial Statements are an integral part of these statements.
11
PENNSYLVANIA POWER COMPANY BALANCE SHEETS As of December 31, 2003 2002 ------------------------------------------------------------------------------------------------------------------- (In thousands) ASSETS UTILITY PLANT: In service...................................................................... $808,637 $680,729 Less-Accumulated provision for depreciation..................................... 324,710 310,423 -------- -------- 483,927 370,306 -------- -------- Construction work in progress- Electric plant............................................................... 68,091 44,696 Nuclear fuel................................................................. 360 8,812 -------- -------- 68,451 53,508 -------- -------- 552,378 423,814 -------- -------- OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts (Note 1(K))................................ 133,867 119,401 Long-term notes receivable from associated companies............................ 39,179 38,921 Other........................................................................... 2,195 2,569 -------- -------- 175,241 160,891 -------- -------- CURRENT ASSETS: Cash and cash equivalents....................................................... 40 1,222 Notes receivable from associated companies...................................... 399 35,317 Receivables- Customers (less accumulated provisions of $769,000 and $702,000, respectively, for uncollectible accounts).................................. 44,861 44,341 Associated companies......................................................... 24,965 42,652 Other........................................................................ 1,047 5,262 Materials and supplies, at average cost......................................... 33,918 30,309 Prepayments..................................................................... 9,383 5,346 -------- -------- 114,613 164,449 -------- -------- NONCURRENT LIABILITIES: Regulatory assets............................................................... 27,513 150,902 Other........................................................................... 9,634 7,692 -------- -------- 37,147 158,594 -------- -------- $879,379 $907,748 ======== ======== CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Statements of Capitalization): Common stockholder's equity..................................................... $230,786 $229,374 Preferred stock- Not subject to mandatory redemption........................................ 39,105 39,105 Subject to mandatory redemption (Note 3(E))................................ -- 13,500 Long-term debt and other long-term obligations- Preferred stock subject to mandatory redemption (Note 3(E))................ 12,750 -- Other...................................................................... 117,608 185,499 -------- -------- 400,249 467,478 -------- -------- CURRENT LIABILITIES: Currently payable long-term debt and preferred stock............................ 93,474 66,556 Accounts payable- Associated companies......................................................... 40,172 52,653 Other........................................................................ 1,294 5,730 Notes payable to associated companies........................................... 11,334 -- Accrued taxes................................................................... 27,091 12,507 Accrued interest................................................................ 4,396 5,558 Other........................................................................... 8,444 10,479 -------- -------- 186,205 153,483 -------- -------- NONCURRENT LIABILITIES: Accumulated deferred income taxes............................................... 97,871 117,385 Accumulated deferred investment tax credits..................................... 3,516 3,810 Asset retirement obligation..................................................... 129,546 -- Nuclear plant decommissioning costs............................................. -- 119,863 Retirement benefits............................................................. 54,057 38,198 Other........................................................................... 7,935 7,531 -------- -------- 292,925 286,787 -------- -------- COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)....................... -------- -------- $879,379 $907,748 ======== ======== The accompanying Notes to Financial Statements are an integral part of these balance sheets.
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PENNSYLVANIA POWER COMPANY STATEMENTS OF CAPITALIZATION As of December 31, 2003 2002 ----------------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, $30 par value, 6,500,000 shares authorized, 6,290,000 shares outstanding $188,700 $188,700 Other paid-in capital................................................................ (310) (310) Accumulated other comprehensive loss (Note 3(F))..................................... (11,783) (9,932) Retained earnings (Note 3(A))........................................................ 54,179 50,916 -------- -------- Total common stockholder's equity.................................................. 230,786 229,374 -------- -------- Number of Shares Optional Outstanding Redemption Price ---------------- ---------------- 2003 2002 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 3(C)): Cumulative, $100 par value- Authorized 1,200,000 shares Not Subject to Mandatory Redemption: 4.24%................................ 40,000 40,000 $103.13 $ 4,125 4,000 4,000 4.25%................................ 41,049 41,049 105.00 4,310 4,105 4,105 4.64%................................ 60,000 60,000 102.98 6,179 6,000 6,000 7.75%................................ 250,000 250,000 100.00 25,000 25,000 25,000 ------- ------- ------- -------- -------- Total not subject to mandatory redemption....................... 391,049 391,049 $39,614 39,105 39,105 ======= ======= ======= -------- -------- Subject to Mandatory Redemption (Note 3(E)): 7.625%**............................. -- 142,500 -- 14,250 Redemption Within One Year**........... -- -- (750) ------- ------- -------- -------- Total subject to mandatory redemption -- 142,500 -- 13,500 ======= ======= -------- -------- LONG-TERM DEBT (Note 3(D)): First mortgage bonds- 9.740% due 2004-2019..................................................................... 15,617 16,591 7.500% due 2003.......................................................................... -- 40,000 6.375% due 2004.......................................................................... 20,500 20,500 6.625% due 2004.......................................................................... 14,000 14,000 8.500% due 2022.......................................................................... 27,250 27,250 7.625% due 2023.......................................................................... 6,500 6,500 -------- -------- Total first mortgage bonds............................................................. 83,867 124,841 -------- -------- Secured notes- 5.400% due 2013.......................................................................... 1,000 1,000 5.400% due 2017.......................................................................... 10,600 10,600 *1.100% due 2017.......................................................................... 17,925 17,925 5.900% due 2018.......................................................................... 16,800 16,800 *1.100% due 2021.......................................................................... 14,482 14,482 6.150% due 2023.......................................................................... 12,700 12,700 *1.200% due 2027.......................................................................... 10,300 10,300 5.375% due 2028.......................................................................... 1,734 1,734 5.450% due 2028.......................................................................... 6,950 6,950 6.000% due 2028.......................................................................... 14,250 14,250 5.950% due 2029.......................................................................... 238 238 -------- -------- Total secured notes.................................................................... 106,979 106,979 -------- -------- Unsecured notes- *2.500% due 2029.......................................................................... 14,500 14,500 *5.900% due 2033.......................................................................... 5,200 5,200 -------- -------- Total unsecured notes.................................................................. 19,700 19,700 -------- -------- Preferred stock subject to mandatory redemption**.......................................... 13,500 -- -------- -------- Capital leases obligations (Note 2)........................................................ -- 32 -------- -------- Net unamortized discount on debt........................................................... (214) (247) -------- -------- Long-term debt due within one year**....................................................... (93,474) (65,806) -------- -------- Total long-term debt**................................................................. 130,358 185,499 -------- -------- TOTAL CAPITALIZATION.......................................................................... $400,249 $467,478 ======== ======== * Denotes variable rate issue with December 31, 2003 interest rate shown. ** The December 31, 2003 balance for preferred stock subject to mandatory redemption is classified as debt under SFAS 150. The accompanying Notes to Financial Statements are an integral part of these statements.
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PENNSYLVANIA POWER COMPANY STATEMENTS OF COMMON STOCKHOLDER'S EQUITY Accumulated Other Other Comprehensive Number Par Paid-In Comprehensive Retained Income of Shares Value Capital Income (Loss) Earnings ------------- --------- ----- ------- ------------- -------- (Dollars in thousands) Balance, January 1, 2001............. 6,290,000 $188,700 $(310) $ -- $ 25,461 Net income........................ $41,041 41,041 ======= Cash dividends on common stock.... (27,400) Cash dividends on preferred stock. (3,704) --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001........... 6,290,000 188,700 (310) -- 35,398 Net income........................ $47,717 47,717 Minimum liability for unfunded retirement benefits, net of $(7,045,000) of income taxes.... (9,932) (9,932) ------- Comprehensive income.............. $37,785 ======= Cash dividends on preferred stock. (3,699) Cash dividends on common stock.... (28,500) --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002........... 6,290,000 188,700 (310) (9,932) 50,916 Net income........................ $48,451 48,451 Minimum liability for unfunded retirement benefits, net of $(1,290,000) of income taxes.... (1,851) (1,851) ------- Comprehensive income.............. $46,600 ======= Cash dividends on preferred stock. (3,188) Cash dividends on common stock.... (42,000) --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2003........... 6,290,000 $188,700 $(310) $(11,783) $ 54,179 =====================================================================================================================
STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- -------------------- Number Par Number Par of Shares Value of Shares Value --------- ----- --------- ----- (Dollars in thousands) Balance, January 1, 2001.......... 391,049 $39,105 150,000 $15,000 ------------------------------------------------------------------------------------------ Balance, December 31, 2001........ 391,049 39,105 150,000 15,000 Redemptions- 7.625% Series.................. (7,500) (750) ------------------------------------------------------------------------------------------ Balance, December 31, 2002........ 391,049 39,105 142,500 14,250 Redemptions- 7.625% Series.................. (7,500) (750) ------------------------------------------------------------------------------------------ Balance, December 31, 2003........ 391,049 $39,105 135,000 $13,500* ========================================================================================== * December 31, 2003 balance for preferred stock subject to mandatory redemption is classified as debt under SFAS 150 (see Note 6). The accompanying Notes to Financial Statements are an integral part of these statements.
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PENNSYLVANIA POWER COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income............................................................ $ 48,451 $ 47,717 $ 41,041 Adjustments to reconcile net income to net cash from operating activities: Provision for depreciation and amortization........................ 53,806 56,763 57,087 Nuclear fuel and lease amortization................................ 15,947 19,204 17,323 Deferred income taxes, net......................................... (2,816) (5,337) (11,055) Amortization of investment tax credits............................. (2,412) (2,595) (2,775) Cumulative effect of accounting change (Note 1(H))................. (18,150) -- -- Receivables........................................................ 16,276 (8,434) 8,345 Materials and supplies............................................. (3,609) (4,711) 3,997 Accounts payable................................................... (11,163) 6,338 (11,413) Accrued taxes...................................................... 14,584 (6,346) (397) Accrued interest................................................... (1,162) 294 (708) Prepayments and other current assets............................... (4,037) 336 (3,638) Asset retirement obligation, net................................... 16,983 -- -- Other.............................................................. 5,814 2,533 (4,522) -------- -------- -------- Net cash provided from operating activities...................... 128,512 105,762 93,285 -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt..................................................... -- 14,500 31,626 Short-term borrowings, net......................................... 11,334 -- -- Redemptions and Repayments- Preferred stock.................................................... (750) (750) -- Long-term debt..................................................... (41,155) (56,837) (51,351) Dividend Payments- Common stock....................................................... (42,000) (28,500) (27,400) Preferred stock.................................................... (3,188) (3,699) (3,704) -------- -------- -------- Net cash used for financing activities........................... (75,759) (75,286) (50,829) -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Property additions.................................................... (70,864) (46,060) (40,529) Contributions to nuclear decommissioning trusts....................... (1,594) (1,594) (1,595) Loans from (to) associated companies, net............................. 34,660 19,463 (18,856) Sale of assets to associated companies................................ -- -- 6,053 Other................................................................. (16,137) (1,130) 9,063 -------- -------- -------- Net cash used for investing activities........................... (53,935) (29,321) (45,864) -------- -------- -------- Net increase (decrease) in cash and cash equivalents.................. (1,182) 1,155 (3,408) Cash and cash equivalents at beginning of year........................ 1,222 67 3,475 -------- -------- -------- Cash and cash equivalents at end of year............................. $ 40 $ 1,222 $ 67 ======== ======== ======== SUPPLEMENTAL CASH FLOWS INFORMATION: Cash paid during the year- Interest (net of amounts capitalized).............................. $ 12,449 $ 13,771 $ 19,286 ======== ======== ======== Income taxes....................................................... $ 33,502 $ 60,078 $ 53,527 ======== ======== ======== The accompanying Notes to Financial Statements are an integral part of these statements.
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PENNSYLVANIA POWER COMPANY STATEMENTS OF TAXES For the Years Ended December 31, 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: State gross receipts*................................................ $ 18,028 $ 18,516 $ 12,776 Real and personal property........................................... 2,262 3,729 59 State capital stock.................................................. 952 1,357 1,081 Social security and unemployment..................................... 878 750 201 Other................................................................ 338 122 97 -------- -------- -------- Total general taxes............................................. $ 22,458 $ 24,474 $ 14,214 ======== ======== ======== PROVISION FOR INCOME TAXES: Currently payable- Federal........................................................... $ 37,351 $ 38,972 $ 40,948 State............................................................. 11,368 12,004 12,803 -------- -------- -------- 48,719 50,976 53,751 -------- -------- -------- Deferred, net- Federal........................................................... (2,424) (4,144) (8,304) State............................................................. (392) (1,193) (2,751) -------- -------- -------- (2,816) (5,337) (11,055) -------- -------- -------- Investment tax credit amortization................................... (2,412) (2,595) (2,775) -------- -------- -------- Total provision for income taxes................................ $ 43,491 $ 43,044 $ 39,921 ======== ======== ======== INCOME STATEMENT CLASSIFICATION OF PROVISION FOR INCOME TAXES: Operating expenses................................................... $ 34,164 $ 41,733 $ 36,909 Other income......................................................... 1,795 1,311 3,012 Cumulative effect of accounting change............................... 7,532 -- -- -------- -------- -------- Total provision for income taxes................................ $ 43,491 $ 43,044 $ 39,921 ======== ======== ======== RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES: Book income before provision for income taxes........................ $ 91,942 $ 90,761 $ 80,962 ======== ======== ======== Federal income tax expense at statutory rate......................... $ 32,180 $ 31,766 $ 28,337 Increases (reductions) in taxes resulting from: State income taxes, net of federal income tax benefit............. 7,134 7,027 6,534 Amortization of investment tax credits............................ (2,412) (2,595) (2,775) Amortization of tax regulatory assets............................. 5,616 5,967 6,315 Other, net........................................................ 973 879 1,510 -------- -------- -------- Total provision for income taxes................................ $ 43,491 $ 43,044 $ 39,921 ======== ======== ======== ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31: Competitive transition charge........................................ $ 37,280 $ 56,172 $ 75,686 Property basis differences........................................... 77,147 72,488 65,534 Allowance for equity funds used during construction.................. -- 1,045 2,608 Customer receivables for future income taxes......................... 2,860 4,249 5,640 Unamortized investment tax credits................................... (1,457) (1,578) (1,702) Deferred gain for asset sale to affiliated company................... 8,106 8,810 9,943 Other comprehensive income........................................... (8,335) (7,045) -- Other................................................................ (17,730) (16,756) (20,901) -------- -------- -------- Net deferred income tax liability............................... $ 97,871 $117,385 $136,808 ======== ======== ======== * Collected from customers through regulated rates and included in revenue on the Statements of Income. The accompanying Notes to Financial Statements are an integral part of these statements.
16 NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Pennsylvania Power Company (Company), a wholly owned subsidiary of Ohio Edison Company (OE), follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory Commission (FERC). OE is a wholly owned subsidiary of FirstEnergy Corp. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Certain prior year amounts have been reclassified to conform with the current year presentation, as described further in Note 1(E). (A) REVENUES- The Company's principal business is providing electric service to customers in western Pennsylvania. The Company's retail customers are metered on a cycle basis. Revenue is recognized for unbilled electric service provided through the end of the year. Receivables from customers include sales to residential, commercial and industrial customers located in the Company's service area and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2003 or 2002, with respect to any particular segment of the Company's customers. Total customer receivables were $45 million (billed - $29 million and unbilled - $16 million) and $44 million (billed - $25 million and unbilled - $19 million) as of December 31, 2003 and 2002, respectively. (B) REGULATORY MATTERS- Pennsylvania enacted its electric utility competition law in 1996 with the phase in of customer choice for electric generation suppliers completed as of January 1, 2001. The Company continues to deliver power to homes and businesses through its distribution system, which remains regulated by the PPUC. The Company's rates have been restructured to itemize (unbundle) the current price of electricity into its component elements - including generation, transmission, distribution and stranded cost recovery. In the event customers obtain power from an alternative source, the generation portion of the Company's rates is excluded from their bill and the customers receive a generation charge from the alternative supplier. The stranded cost recovery portion of rates provides for recovery of certain amounts not otherwise considered recoverable in a competitive generation market, including regulatory assets. In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and create additional reporting on reliability. Although neither the Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. The comment period for both the Tentative Order and the Proposed Rulemaking Order has closed. The Company is currently awaiting the PPUC to issue a final order in both matters. The order will determine (1) the standards and benchmarks to be utilized, and (2) the details required in the quarterly and annual reports. It is expected that these Orders will be finalized in March 2004. On January 16, 2004, the PPUC initiated a formal investigation of the Company's levels of compliance with the Public Utility Code and the PPUC's regulations and orders with regard to reliable electric service. Hearings will be held in August in this investigation and the Administrative Law Judge has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order before December 16, 2004. The Company is unable to predict the outcome of the investigation or the impact of the PPUC Order. Regulatory Assets- The Company recognizes, as regulatory assets, costs which the FERC and PPUC have authorized for recovery from customers in future periods. Without such authorization, the costs would have been charged to income as incurred. All regulatory assets are expected to continue to be recovered from customers under the Company's rate restructuring plan. Based on the rate restructuring plan, the Company continues to bill and collect cost-based rates relating to the Company's nongeneration operations and continues the application of Statement of Financial Accounting Standards No. (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" to these operations. 17 Net regulatory assets on the Balance Sheets are comprised of the following: 2003 2002 ----------------------------------------------------------------------------- (In millions) Competitive transition charge.................. $ 90 $136 Customer receivables for future income taxes... 7 10 Loss on reacquired debt........................ 6 7 Employee postretirement benefit costs.......... 2 3 Nuclear decommissioning costs.................. (72) -- Component removal costs........................ (6) (6) Other.......................................... 1 1 --------------------------------------------------------------------------- Total..................................... $ 28 $151 =========================================================================== Regulatory Accounting Generation Operations- In 1998, the PPUC authorized the Company's rate restructuring plan, which essentially resulted in the deregulation of the Company's generation business. The Company was required to remove from its balance sheet all regulatory assets and liabilities related to its generation business and assess all other assets for impairment. The SEC issued interpretive guidance regarding asset impairment measurement providing that any supplemental regulated cash flows such as a competitive transition charge (CTC) should be excluded from the cash flows of assets in a portion of the business not subject to regulatory accounting practices. If those assets are impaired, a regulatory asset should be established if the costs are recoverable through regulatory cash flows. Consistent with the SEC guidance, the Company reduced its nuclear generating unit investments by approximately $305 million, of which approximately $227 million was recognized as a regulatory asset to be recovered through the CTC over a seven-year transition period; the remaining net amount of $78 million was written off. The Company is entitled to recover $236 million of stranded costs through the CTC that began in 1999 and ends in 2006. The Company's net assets included in utility plant relating to the operations for which the application of SFAS 71 was discontinued were $92 million as of December 31, 2003. (C) UTILITY PLANT AND DEPRECIATION- Utility plant reflects the original cost of construction (except for nuclear generating units which were adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The Company's accounting policy for planned major maintenance projects is to recognize liabilities as they are incurred. The Company provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The annual composite rate for electric plant was approximately 2.6% in 2003 and 2.9% in 2002 and 2001. Nuclear Fuel- Nuclear fuel is recorded at original cost, which includes material, enrichment, fabrication and interest costs incurred prior to reactor load. The Company amortizes the cost of nuclear fuel based on the rate of consumption. (D) COMMON OWNERSHIP OF GENERATING FACILITIES- The Company, together with OE and other affiliated companies, The Cleveland Electric Illuminating Company (CEI) and The Toledo Edison Company (TE), own, as tenants in common, various power generating facilities. Each of the companies is obligated to pay a share of the costs associated with any jointly owned facility in the same proportion as its interest. The Company's portion of operating expenses associated with jointly owned facilities is included in the corresponding operating expenses on the Statements of Income. The amounts reflected on the Balance Sheet under utility plant as of December 31, 2003 include the following:
Utility Accumulated Construction Company's Plant in Provision for Work in Ownership Generating Units Service Depreciation Progress Interest ------------------------------------------------------------------------------------------------------- (In millions) W. H. Sammis #7....................... $ 64 $ 22 $-- 20.80% Bruce Mansfield #1, #2 and #3....................... 187 100 -- 16.38% Beaver Valley #1 and #2............... 139 24 59 39.37% Perry #1.............................. 8 2 1 5.24% ------------------------------------------------------------------------------------------------------- Total............................. $398 $148 $60 =======================================================================================================
18 (E) ASSET RETIREMENT OBLIGATION- In January 2003, the Company implemented SFAS 143, "Accounting for Asset Retirement Obligations," which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Over time the capitalized costs are depreciated and the present value of the asset retirement liability increases, resulting in a period expense. However, rate-regulated entities may recognize a regulatory asset or liability instead if the criteria for such treatment are met. Upon retirement, a gain or loss would be recognized if the cost to settle the retirement obligation differs from the carrying amount. The Company identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond related to the Bruce Mansfield Plant. The ARO liability as of the date of adoption of SFAS 143 was $121.3 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. Accretion during 2003 was $8.2 million, bringing the ARO liability as of December 31, 2003 to $129.5 million. The ARO includes the Company's obligation for nuclear decommissioning of the Beaver Valley and Perry generating facilities. The Company's share of the obligation to decommission these units was developed based on site-specific studies performed by an independent engineer. The Company utilized an expected cash flow approach (as discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements") to measure the fair value of the nuclear decommissioning ARO. The Company maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of December 31, 2003, the fair value of the decommissioning trust assets was $133.9 million. In accordance with SFAS 143, the Company ceased the accounting practice of depreciating non-regulated generation assets using a cost of removal component in the depreciation rates. That practice recognized accumulated depreciation in excess of the historical cost of an asset because the removal cost would exceed the estimated salvage value. Beginning in 2003, the cost of removal related to non-regulated generation assets is charged to expense rather than to the accumulated provision for depreciation. In accordance with SFAS 71, the cost of removal on regulated plant assets continues to be accounted for as a component of depreciation rates and is recognized as a regulatory liability. The following table provides the year-end balance of the ARO for 2002, as if SFAS 143 had been adopted on January 1, 2002. Adjusted ARO Reconciliation 2002 ------------------------------------------------------- (In millions) Beginning balance as of January 1, 2002 $113.7 Accretion in 2002 7.6 ------------------------------------------------------ Ending balance as of December 31, 2002 $121.3 ------------------------------------------------------ (F) STOCK-BASED COMPENSATION- FirstEnergy applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its stock-based compensation plans (see Note 3(B)). No material stock-based employee compensation expense is reflected in net income as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the grant date resulting in substantially no intrinsic value. If FirstEnergy had accounted for employee stock options under the fair value method of SFAS 123, "Accounting for Stock Compensation," a higher value would have been assigned to the options granted. The weighted average assumptions used in valuing the options and their resulting estimated fair values would be as follows: 2003 2002 2001 ---------------------------------------------------------------------------- Valuation assumptions: Expected option term (years). 7.9 8.1 8.3 Expected volatility.......... 26.91% 23.31% 23.45% Expected dividend yield...... 5.09% 4.36% 5.00% Risk-free interest rate...... 3.67% 4.60% 4.67% Fair value per option.......... $5.09 $6.45 $4.97 ---------------------------------------------------------------------------- The effects of applying fair value accounting to FirstEnergy's stock options would not materially affect the Company's net income. 19 (G) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. The Company records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. The Company is included in FirstEnergy's consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing any tax losses or credits it contributed to the consolidated return. (H) CUMULATIVE EFFECT OF ACCOUNTING CHANGE Results for 2003 include an after-tax credit to net income of $10.6 million recorded upon the adoption of SFAS 143 in January 2003. The Company identified applicable legal obligations as defined under the new 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 $78 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $9 million. The ARO liability at the date of adoption was $121 million, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, the Company had recorded decommissioning liabilities of $120 million. The Company expects substantially all of its nuclear decommissioning costs to be recoverable in rates over time. Therefore, it recognized a regulatory liability of $69 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was an $18.2 million increase to income, or $10.6 million net of income taxes. If SFAS 143 had been applied during 2002 and 2001, the impact would not have been material to the Company's Statements of Income. (I) PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of the Company's employees. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. No pension contributions were required during the three years ended December 31, 2003. FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and copayments, are also available to retired employees, their dependents and, under certain circumstances, their survivors. The Company recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU, Inc. in November 2001), which impacts employee demographics, plan experience and other factors. 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 and pension and OPEB costs. FirstEnergy uses a December 31 measurement date for the majority of its plans. Plan amendments to retirement health care benefits in 2003 and 2002, relate to changes in benefits provided and cost-sharing provisions, which reduced FirstEnergy's obligation by $123 million and $121 million, respectively. In early 2004, FirstEnergy announced that it would amend the benefit provisions of its health care benefits plan and both employees and retirees would share in more of the benefit costs. On December 8, 2003, President Bush signed into law a bill that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. FirstEnergy anticipates that the benefits it pays after 2006 will be lower as a result of the new Medicare provisions. Due to uncertainties surrounding some of the new Medicare provisions and a lack of authoritative accounting guidance about these issues, FirstEnergy deferred the recognition of the impact of the new Medicare provisions as provided by FASB Staff Position 106-1. The final accounting guidance could require changes to previously reported information. 20 The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheets as of December 31:
Obligations and Funded Status Pension Benefits Other Benefits ------------------- ------------------ As of December 31 2003 2002 2003 2002 ------------------------------------------------------------------------------------------ (In millions) Change in benefit obligation Benefit obligation at beginning of year.. $3,866 $3,548 $ 2,077 $ 1,582 Service cost............................. 66 59 43 28 Interest cost............................ 253 249 136 114 Plan participants' contributions......... -- -- 6 -- Plan amendments.......................... -- -- (123) (121) Actuarial loss........................... 222 268 323 440 GPU acquisition.......................... -- (12) -- 110 Benefits paid............................ (245) (246) (94) (76) ------ ------ ------- ------- Benefit obligation at end of year........ $4,162 $3,866 $ 2,368 $ 2,077 ====== ====== ======= ======= Change in fair value of plan assets Fair value of plan assets at beginning of year...................... $2,889 $3,484 $ 473 $ 535 Actual return on plan assets............. 671 (349) 88 (57) Company contribution..................... -- -- 68 31 Plan participants' contribution.......... -- -- 2 -- Benefits paid............................ (245) (246) (94) (36) ------ ------ ------- ------- Fair value of plan assets at end of year. $3,315 $2,889 $ 537 $ 473 ====== ====== ======= ======= Funded status............................ $ (847) $ (977) $(1,831) $(1,604) Unrecognized net actuarial loss.......... 919 1,186 994 752 Unrecognized prior service cost (benefit)............................... 72 78 (221) (107) Unrecognized net transition obligation... -- -- 83 92 ------ ------ ------- ------- Net asset (liability) recognized......... $ 144 $ 287 $ (975) $ (867) ====== ====== ======= ======= Amounts Recognized in the Consolidated Balance Sheets Pension Benefits Other Benefits ----------------- ------------------ As of December 31 2003 2002 2003 2002 ------------------------------------------------------------------------------------------ Accrued benefit cost..................... $ (438) $ (548) $ (975) $ (867) Intangible assets........................ 72 78 -- -- Accumulated other comprehensive loss..... 510 757 -- -- ------ ------ ------- ------- Net amount recognized.................... $ 144 $ 287 $ (975) $ (867) ====== ====== ======= ======= Company's share of net amount recognized. $ 10 $ 9 $ (39) $ (26) ====== ====== ======= ======= Increase (decrease) in minimum liability included in other comprehensive income (net of tax)........................... $ (145) $ 444 $ -- $ -- Weighted-Average Assumptions Used to Determine Benefit Obligations As of December 31 ---------------------------------------- Discount rate........................... 6.25% 6.75% 6.25% 6.75% Rate of compensation increase........... 3.50% 3.50% Allocation of Plan Assets As of December 31 ------------------------- Asset Category Equity securities..................... 70% 61% 71% 58% Debt securities....................... 27 35 22 29 Real estate........................... 2 2 -- -- Other................................. 1 2 7 13 --- ---- --- --- Total................................. 100% 100% 100% 100% === === === === Information for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets 2003 2002 ----------------------------------------- ---- ---- (In millions) Projected benefit obligation............. $4,162 $3,866 Accumulated benefit obligation........... 3,753 3,438 Fair value of plan assets................ 3,315 2,889
FirstEnergy's net pension and other postretirement benefit costs for the three years ended December 31, 2003 were computed as follows: 21
Pension Benefits Other Benefits ---------------------- -------------------- Components of Net Periodic Benefit Costs 2003 2002 2001 2003 2002 2001 --------------------------------------------------------------------------------------------- (In millions) Service cost............................ $ 66 $ 59 $ 35 $ 43 $ 29 $ 18 Interest cost........................... 253 249 133 137 114 65 Expected return on plan assets.......... (248) (346) (205) (43) (52) (10) Amortization of prior service cost...... 9 9 9 (9) 3 3 Amortization of transition obligation (asset)................................ -- -- (2) 9 9 9 Recognized net actuarial loss........... 62 -- -- 40 11 5 Voluntary early retirement program...... -- -- 6 -- -- 2 ----- ----- ----- ---- ---- ---- Net periodic cost (income).............. $ 142 $ (29) $ (24) $177 $114 $ 92 ===== ===== ===== ==== ==== ==== Company's share of net benefit costs.... $ 4 $ 1 $ (1) $ 7 $ 2 $ 4 ===== ===== ===== ==== ==== ==== Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 --------------------------------------- Discount rate.......................... 6.75% 7.25% 7.75% 6.75% 7.25% 7.75% Expected long-term return on plan assets............................... 9.00% 10.25% 10.25% 9.00% 10.25% 10.25% Rate of compensation increase.......... 3.50% 4.00% 4.00%
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. The assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the Company's pension trusts. The long-term rate of return is developed considering the portfolio's asset allocation strategy. Assumed health care cost trend rates As of December 31 2003 2002 ------------------------------------------------------------------------------- Health care cost trend rate assumed for next year (pre/post-Medicare).......................... 10%-12% 10%-12% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)................. 5% 5% Year that the rate reaches the ultimate trend rate (pre/post-Medicare).......................... 2009-2011 2008-2010 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects: 1-Percentage- 1-Percentage- Point Increase Point Decrease ------------------------------------------------------------------------------- (In millions) Effect on total of service and interest cost.. $ 26 $ (19) Effect on postretirement benefit obligation... $233 $(212) FirstEnergy employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalizations. Other assets such as real estate are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies. As a result of GPU Service Inc. merging with FirstEnergy Service Company in the second quarter of 2003, operating company employees of GPU Service were transferred to the former GPU operating companies. Accordingly, FirstEnergy requested an actuarial study to update the pension liabilities for each of its subsidiaries. Based on the actuary's report, the accrued pension costs for the Company as of June 30, 2003 increased by $16 million. The corresponding adjustment related to this change decreased other comprehensive income and deferred income taxes and increased the payable to associated companies. Due to the increased market value of its pension plan assets, the Company reduced its minimum liability as prescribed by SFAS 87 as of December 31, 2003 by $16 million, recording an increase of $2 million in an intangible 22 asset and crediting OCI by $11 million (offsetting previously recorded deferred tax benefits by $7 million). The remaining balance in OCI of $12 million will reverse in future periods to the extent the accumulated benefit obligation exceeds the fair value of trust assets. The accrued pension cost was reduced to $15 million as of December 31, 2003. FirstEnergy does not expect to contribute to its pension plans in 2004 and expects to contribute $16 million to its other postretirement benefit plans in 2004. (J) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily American Transmission Systems, Inc. (ATSI), FirstEnergy Solutions Corp. (FES) and FirstEnergy Service Company (FESC). The Ohio transition plan resulted in the corporate separation of FirstEnergy's regulated and unregulated operations in 2001. FES operates the generation businesses of the Company, OE, CEI and TE. As a result, the Company entered into power supply agreements (PSA) whereby FES purchases all of the Company's nuclear generation and the Company purchases its power from FES to meet its "provider of last resort" obligations. In 2002, the Company terminated its nuclear fuel leasing arrangement with OES Fuel and now owns its nuclear fuel. The primary affiliated companies transactions are as follows: 2003 2002 2001 ----------------------------------------------------------------------------- (In millions) Operating Revenues: PSA revenues from FES............... $162 $138 $152 Generating units rent from FES...... 20 20 20 Ground lease with ATSI.............. 1 1 1 Operating Expenses: Nuclear fuel leased from OES Fuel... -- 5 19 Purchased power under PSA........... 166 157 153 Transmission facilities rentals..... 10 13 10 FESC support services............... 13 9 10 Other Income: Interest income from ATSI........... 3 3 3 Interest income from FES............ 1 1 1 ------------------------------------------------------------------------------ FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from FESC, a subsidiary of FirstEnergy Corp. and a "mutual service company" as defined in Rule 93 of the Public Utility Holding Company Act of 1935 (PUHCA). The majority of costs are directly billed or assigned at no more than cost as determined by PUHCA Rule 91. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas that are filed annually with the SEC on Form U-13-60. The current allocation or assignment formulas used and their bases include multiple factor formulas; each company's proportionate amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with OE, FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days, except for a net $2.3 million receivable from affiliates for pension and OPEB obligations. (K) CASH AND FINANCIAL INSTRUMENTS- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Balance Sheets at cost, which approximates their fair market value. Noncash financing and investing activities included capital lease transactions amounting to $1.5 million and $21.6 million for the years 2002 and 2001, respectively. There were no capital lease transactions in 2003. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Balance Sheets at cost, which approximates their fair market value. The following sets forth the approximate fair value and related carrying amounts of all other long-term debt, preferred stock subject to mandatory redemption and investments other than cash and cash equivalents as of December 31: 23
2003 2002 ------------------------------------------------------------------------------------------------------ Carrying Fair Carrying Fair Value Value Value Value ------------------------------------------------------------------------------------------------------ (In millions) Long-term debt...................................... $211 $228 $252 $260 Preferred stock*.................................... 14 14 14 14 Investments other than cash and cash equivalents.... 175 180 161 165 ----------------------------------------------------------------------------------------------------- * The December 31, 2003 amount is classified as debt under SFAS 150.
The fair values of long-term debt and preferred stock reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective year. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to the Company's ratings. The fair value of investments other than cash and cash equivalents represent cost (which approximates fair value) or the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. Investments other than cash and cash equivalents consist primarily of decommissioning trust investments. The Company has no securities held for trading purposes. The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries. The investments that are held in the decommissioning trusts (included as "Investments other than cash and cash equivalents" in the table above) consist of equity securities ($50 million) and fixed income securities ($84 million) as of December 31, 2003. Realized and unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to regulatory assets. For 2003 and 2002, net realized gains (losses) were approximately $1.2 million and $(0.3) million and interest and dividend income totaled approximately $4.8 million and $5.2 million, respectively. 2. LEASES The Company leases office space and other property and equipment under cancelable and noncancelable leases. Consistent with the regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Statements of Income. Such costs for the three years ended December 31, 2003, are summarized as follows: 2003 2002 2001 ---------------------------------------------------------------------------- (In millions) Operating leases Interest element................... $0.2 $0.1 $ -- Other.............................. 0.3 0.2 0.1 Capital leases Interest element................... -- -- -- Other.............................. -- 0.1 0.1 ---------------------------------------------------------------------------- Total rentals......................... $0.5 $0.4 $0.2 ============================================================================ The future minimum lease payments as of December 31, 2003, are: Operating Leases --------------------------------------------------------------------- (In millions) 2004................................................... $0.1 2005................................................... 0.1 2006................................................... 0.1 2007................................................... 0.1 2008................................................... 0.1 Years thereafter....................................... 0.6 ---------------------------------------------------------------- Total minimum lease payments........................... $1.1 ================================================================ 24 3. CAPITALIZATION (A) RETAINED EARNINGS- Under the Company's Charter, the Company's retained earnings unrestricted for payment of cash dividends on the Company's common stock were $44.4 million as of December 31, 2003. (B) STOCK COMPENSATION PLANS- FirstEnergy administers the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). Under the FE Plan, total awards cannot exceed 22.5 million shares of common stock or their equivalent. Only stock options and restricted stock have been granted, with vesting periods ranging from six months to seven years. Several other stock compensation plans have been acquired through the mergers with GPU and Centerior - GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan), 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan) and Centerior Equity Plan. No further stock-based compensation can be awarded under these plans. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2003 2002 2001 --------------------------------------------------------------------------- Restricted common shares granted...... -- 36,922 133,162 Weighted average market price ........ n/a (1) $36.04 $35.68 Weighted average vesting period (years)............................. n/a (1) 3.2 3.7 Dividends restricted.................. n/a (1) Yes -- (2) --------------------------------------------------------------------------- (1) Not applicable since no restricted stock was granted. (2) FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan dividends are paid as unrestricted cash on 128,662 shares Under the Executive Deferred Compensation Plan (EDCP), covered employees can direct a portion of their Annual Incentive Award and/or Long-Term Incentive Award into an unfunded FirstEnergy Stock Account to receive vested stock units. An additional 20% premium is received in the form of stock units based on the amount allocated to the FirstEnergy Stock Account. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. As of December 31, 2003, there were 410,399 stock units outstanding. Stock option activities under the FE Programs for the past three years were as follows: Number of Weighted Average Stock Option Activities Options Exercise Price -------------------------------------------------------------------- Balance, January 1, 2001....... 5,021,862 24.09 (473,314 options exercisable).. 24.11 Options granted.............. 4,240,273 28.11 Options exercised............ 694,403 24.24 Options forfeited............ 120,044 28.07 Balance, December 31, 2001..... 8,447,688 26.04 (1,828,341 options exercisable) 24.83 Options granted.............. 3,399,579 34.48 Options exercised............ 1,018,852 23.56 Options forfeited............ 392,929 28.19 Balance, December 31, 2002..... 10,435,486 28.95 (1,400,206 options exercisable) 26.07 Options granted.............. 3,981,100 29.71 Options exercised............ 455,986 25.94 Options forfeited............ 311,731 29.09 Balance, December 31, 2003..... 13,648,869 29.27 (1,919,662 options exercisable) 29.67 As of December 31, 2003, the weighted average remaining contractual life of outstanding stock options was 7.6 years. 25 Options outstanding by plan and range of exercise price as of December 31, 2003 were as follows: Range of Options FirstEnergy Program Exercise Prices Outstanding --------------------------------------------------------------------- FE Plan $19.31 - $29.87 9,904,861 $30.17 - $35.15 3,214,601 Plans acquired through merger: GPU Plan $23.75 - $35.92 501,734 Other plans 27,673 -------------------------------------------------------------------- Total 13,648,869 ==================================================================== No material stock-based employee compensation expense is reflected in net income for stock options granted under the above plans since the exercise price was equal to the market value of the underlying common stock on the grant date. The effect of applying fair value accounting to FirstEnergy's stock options is summarized in Note 1(F) - "Stock-Based Compensation." (C) PREFERRED STOCK- All preferred stock may be redeemed by the Company in whole, or in part, with 30-60 days' notice. (D) LONG-TERM DEBT- The Company has a first mortgage indenture under which it issues first mortgage bonds secured by a direct first mortgage lien on substantially all of its property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt which could trigger a default and the maintenance of minimum fixed charge ratios and debt to capitalization ratios. There also exists cross-default provisions among financing arrangements of FirstEnergy and the Company. Based on the amount of bonds authenticated by the mortgage bond trustee through December 31, 2003, the Company's annual sinking fund requirements for all bonds issued under its first mortgage indenture amounts to $9.2 million. The Company expects to deposit funds with its mortgage bond trustee in 2004 that will then be withdrawn upon the surrender for cancellation of a like principal amount of bonds, which are specifically authenticated for such purposes against unfunded property additions or against previously retired bonds. This method can result in minor increases in the amount of the annual sinking fund requirement. Sinking fund requirements for first mortgage bonds and maturing long-term debt (excluding capital leases) during the next five years are $92.7 million in 2004 and $1.0 million in each year 2005 through 2008. Included in these amounts are various variable interest rate long-term debt which have provisions by which individual debt holders have the option to "put back" or require the respective debt issuer to redeem their debt at those times when the interest rate may change prior to its maturity date. Those amounts are $30 million in 2004, which is the next time debt holders may exercise this provision. The Company's obligations to repay certain pollution control revenue bonds are secured by several series of first mortgage bonds. Certain pollution control revenue bonds are entitled to the benefit of irrevocable bank letters of credit of $10.4 million and noncancelable municipal bond insurance policies of $32.9 million to pay principal of, or interest on, the pollution control revenue bonds. To the extent that drawings are made under the letters of credit or policies, the Company is entitled to a credit against its obligation to repay the related bond. The Company pays an annual fee of 1.375% of the amount of the letters of credit to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. (E) LONG-TERM DEBT: PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION- Effective July 1, 2003, upon adoption of SFAS 150 (see Note 6), the Company reclassified as debt its preferred stock subject to mandatory redemption. Prior year amounts were not reclassified. The Company's 7.625% series has an annual sinking fund requirement for 7,500 shares. (F) COMPREHENSIVE INCOME- Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholder's equity except those resulting from transactions with the parent. As of 26 December 31, 2003, accumulated other comprehensive loss consisted of a minimum liability for unfunded retirement benefits of $11.8 million. 4. SHORT-TERM BORROWINGS: The Company may borrow from affiliates on a short-term basis. As of December 31, 2003, the Company had borrowed $11.3 million from its affiliates at an average interest rate of 1.7%. 5. COMMITMENTS AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $143 million for property additions and improvements from 2004-2006, of which approximately $64 million is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $34 million, of which approximately $20 million applies to 2004. During the same periods, the Company's nuclear fuel investments are expected to be reduced by approximately $35 million and $17 million, respectively, as the nuclear fuel is consumed. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $10.9 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on its ownership interests in the Beaver Valley Station and the Perry Plant, the Company's maximum potential assessment under the industry retrospective rating plan (assuming the other affiliate co-owners contribute their proportionate shares of any assessments under the retrospective rating plan) would be $84.5 million per incident but not more than $8.4 million in any one year for each incident. The Company is also insured as to its interest in Beaver Valley and Perry under policies issued to the operating company for each plant. Under these policies, up to $2.75 billion is provided for property damage and decontamination and decommissioning costs. The Company has also obtained approximately $222.1 million of insurance coverage for replacement power costs for its interests in Beaver Valley and Perry. Under these policies, the Company can be assessed a maximum of approximately $11.9 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. The Company intends 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 Company's 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 Company's insurance policies, or to the extent such insurance becomes unavailable in the future, the Company would remain at risk for such costs. (C) ENVIRONMENTAL MATTERS- Various federal, state and local authorities regulate the Company with regard to air and water quality and other environmental matters. The effects of compliance on the Company with regard to environmental matters could have a material adverse effect on the Company's earnings and competitive position. These environmental regulations affect the Company'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, the Company believes it is in material 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. Generation operations and any related additional capital expenditures for environmental compliance are the responsibility of FirstEnergy's competitive services business unit. Clean Air Act Compliance The Company is required to meet federally approved sulfur dioxide (SO2) regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The Environmental Protection Agency (EPA) has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. The Company cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. The Company is 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 27 more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the Company's 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 (including Ohio and Pennsylvania) and the District of Columbia 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 required compliance with the NOx budgets at the Company's Pennsylvania facilities by May 1, 2003. The Company's Pennsylvania facilities complied with the NOx budgets in 2003 and all facilities will comply with the NOx budgets in 2004 and thereafter. Ohio submitted a SIP that requires compliance with the NOx budgets at the Company's Ohio facilities by May 31, 2004. National Ambient Air Quality Standards In July 1997, the EPA promulgated changes in the National Ambient Air Quality Standard (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 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, power plant SO2 emissions would be reduced by approximately 3.6 million tons in 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 if and how they are ultimately implemented by the states in which the Company operates 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 "maximum achievable control technologies" (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 fourteen tons to approximately thirty-four 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 fifteen tons per year. The EPA has agreed to choose between these two options and issue a final rule by December 15, 2004. The future cost of compliance with these regulations may be substantial. W. H. Sammis Plant In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against the Company and OE in the U.S. District Court for the Southern District of Ohio. 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, which is currently scheduled to be ready for trial beginning July 19, 2004, will address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant. In the ruling, the Court indicated 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 the Company's financial condition and results of operations. Management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of December 31, 2003. 28 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. 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 U.S. 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% through 2012. The Company cannot currently estimate the financial impact of climate change policies although the potential restrictions on carbon dioxide (CO2) emissions could require significant capital and other expenditures. However, the CO2 emissions per kilowatt-hour of electricity generated by the Company is lower than many regional competitors due to the Company's diversified generation sources which includes 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 Company's plants. In addition, Ohio and Pennsylvania have water quality standards applicable to the Company's 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 and Pennsylvania have assumed such authority. (D) LEGAL MATTERS- Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against FirstEnergy and its subsidiaries. The most significant applicable to the Company are described above. Power Outage On August 14, 2003, various states in the northeast United States and part of southern Canada experienced a widespread power outage. That outage affected approximately 1.4 million customers in FirstEnergy's service area. FirstEnergy continues to accumulate data and evaluate the status of its electrical system prior to and during the outage event, and continues to cooperate with the U.S.-Canada Power System Outage Task Force (Task Force) investigating the August 14th outage. The interim report issued by the Task Force on November 18, 2003 concluded that the problems leading up to the outage began in FirstEnergy's service area. Specifically, the interim report concludes, among other things, that the initiation of the August 14th outage resulted from the coincidence on that afternoon of the following events: (1) inadequate situational awareness at FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its transmission rights of way; and (3) failure of the interconnected grid's reliability organizations (Midwest ISO and PJM Interconnection) to provide effective diagnostic support. FirstEnergy believes that the interim report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14th outage and that it does not adequately address the underlying causes of the outage. On November 25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will correct problems identified by the Task Force as events contributing to the August 14th outage and addressing how FirstEnergy proposes to upgrade its control room computer hardware and software and improve the training of control room operators to ensure that similar problems do not occur in the future. The PUCO, in consultation with the North American Electric Reliability Council, will review the plan before determining the next steps in the proceeding. On December 24, 2003, the FERC ordered FirstEnergy to pay for an independent study of part of Ohio's power grid. The study has commenced and will examine the stability of the grid in critical points in the Cleveland and Akron areas; the status of projected power reserves during summer 2004 through 2008; and the need for new transmission lines or other grid projects. The FERC ordered the study to be completed within 120 days. At this time, we do not know how the results of the study will impact FirstEnergy. 29 6. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS: SFAS 143, "Accounting for Asset Retirement Obligations" In January 2003, the Company implemented SFAS 143 which provides accounting standards for retirement obligations associated with tangible long-lived assets. This statement requires recognition of the fair value of a liability for an asset retirement obligation in the period in which it is incurred. See Notes 1(E) and 1(H) for further discussions of SFAS 143. SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" In May 2003, the FASB issued SFAS 150, which establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. In accordance with the standard, financial instruments that embody obligations for the issuer are required to be classified as liabilities. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003 and effective at the beginning of the first interim period beginning after June 15, 2003 for all other financial instruments. Upon adoption of SFAS 150, effective July 1, 2003, the Company reclassified as debt its preferred stock subject to mandatory redemption with a carrying value of approximately $14 million as of December 31, 2003. Dividends on preferred stock subject to mandatory redemption on the Company's Statements of Income, which were not included in net interest charges prior to the adoption of SFAS 150, are now included in net interest charges for the six months ended December 31, 2003. 7. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain operating results by quarter for 2003 and 2002.
March 31, June 30, September 30, December 31, Three Months Ended 2003 2003 2003 2003 (a) --------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues........................ $128.3 $116.6 $145.9 $136.1 Operating Expenses and Taxes.............. 130.2 110.3 126.0 113.1 --------------------------------------------------------------------------------------------------------------- Operating Income (Loss)................... (1.9) 6.3 19.9 23.0 Other Income.............................. 0.6 0.5 0.5 1.3 Net Interest Charges...................... 3.4 3.4 3.0 2.5 --------------------------------------------------------------------------------------------------------------- Income (Loss) Before Cumulative Effect of Accounting Change...................... (4.7) 3.4 17.4 21.8 Cumulative Effect of Accounting Change (Net of Income Taxes).................. 10.6 -- -- -- --------------------------------------------------------------------------------------------------------------- Net Income................................ $ 5.9 $ 3.4 $ 17.4 $ 21.8 =============================================================================================================== Earnings on Common Stock.................. $ 5.0 $ 2.5 $ 16.7 $ 21.1 =============================================================================================================== March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 --------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues........................ $124.3 $127.8 $131.9 $122.4 Operating Expenses and Taxes.............. 109.2 106.3 113.1 116.9 --------------------------------------------------------------------------------------------------------------- Operating Income.......................... 15.1 21.5 18.8 5.5 Other Income.............................. 0.7 0.5 0.7 0.1 Net Interest Charges...................... 3.8 4.0 3.7 3.6 --------------------------------------------------------------------------------------------------------------- Net Income................................ $ 12.0 $ 18.0 $ 15.8 $ 2.0 =============================================================================================================== Earnings on Common Stock.................. $ 11.0 $ 17.1 $ 14.9 $ 1.0 =============================================================================================================== (a) Net income for the three months ended December 31, 2003, was increased by $1.1 million due to adjustments that were subsequently capitalized to construction projects in the fourth quarter. The adjustments included $0.2 million, $0.3 million and $0.6 million of costs charged to expense in the first, second and third quarters, respectively. Management concluded that these adjustments were not material to the consolidated financial statements for any quarter of 2003.
30 Report of Independent Auditors To the Stockholders and Board of Directors of Pennsylvania Power Company: In our opinion, the accompanying balance sheets and statements of capitalization and the related statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Pennsylvania Power Company (a wholly owned subsidiary of Ohio Edison Company) as of December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The financial statements of Pennsylvania Power Company for the year ended December 31, 2001, were audited by other independent auditors who have ceased operations. Those independent auditors expressed an unqualified opinion on those financial statements in their report dated March 18, 2002. As discussed in Note 1(E) to the financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003. PricewaterhouseCoopers LLP Cleveland, Ohio February 25, 2004 31 The following report is a copy of a report previously issued by Arthur Andersen LLP (Andersen). This report has not been reissued by Andersen and Andersen did not consent to the incorporation by reference of this report into any of the Company's registration statements. Report of Independent Public Accountants To the Stockholders and Board of Directors of Pennsylvania Power Company: We have audited the accompanying balance sheets and statements of capitalization of Pennsylvania Power Company (a Pennsylvania corporation and wholly owned subsidiary of Ohio Edison Company) as of December 31, 2001 and 2000, and the related statements of income, common stockholder's equity, preferred stock, cash flows and taxes for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pennsylvania Power Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. 32