EX-13 31 jc_ex13-5.txt EX. 13-5 ANNUAL REPORT - JCP&L EXHIBIT 13.5 JERSEY CENTRAL POWER & LIGHT COMPANY 2002 ANNUAL REPORT TO STOCKHOLDERS Jersey Central Power & Light Company (JCP&L) is a wholly owned electric utility operating subsidiary of FirstEnergy Corp. It engages in the distribution and sale of electric energy in an area of approximately 3,300 square miles in New Jersey. It also engages in the sale, purchase and interchange of electric energy with other electric companies. The area it serves has a population of approximately 2.7 million. In August 2000, FirstEnergy entered into an agreement to merge with GPU, Inc., under which FirstEnergy would acquire all of the outstanding shares of GPU, Inc.'s common stock for approximately $4.5 billion in cash and FirstEnergy common stock. The merger became effective on November 7, 2001 and is being accounted for by the purchase method. Prior to that time, Jersey Central Power & Light Company was a wholly owned subsidiary of GPU, Inc. Contents Page -------- ---- Selected Financial Data........................................... 1 Management's Discussion and Analysis.............................. 2-11 Consolidated Statements of Income................................. 12 Consolidated Balance Sheets....................................... 13 Consolidated Statements of Capitalization......................... 14 Consolidated Statements of Common Stockholder's Equity............ 15 Consolidated Statements of Preferred Stock........................ 15 Consolidated Statements of Cash Flows............................. 16 Consolidated Statements of Taxes.................................. 17 Notes to Consolidated Financial Statements........................ 18-30 Reports of Independent Accountants................................ 31-32 JERSEY CENTRAL POWER & LIGHT COMPANY SELECTED FINANCIAL DATA
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 1999 1998 ---------------------------------------------------------------------------------------------------------------------- (Dollars in thousands) Operating Revenues...................... $2,328,415 $ 282,902 | $1,838,638 $1,979,297 $2,018,209 $2,069,648 ========== ========== | ========== ========== ========== ========== | Operating Income........................ $ 335,209 $ 43,666 | $ 292,847 $ 283,227 $ 277,420 $ 297,614 ========== ========== | ========== ========== ========== ========== | Net Income ............................. $ 251,895 $ 30,041 | $ 34,467 $ 210,812 $ 172,380 $ 222,442 ========== ========== | ========== ========== ========== ========== | Earnings on Common Stock................ $ 253,359 $ 29,343 | $ 29,920 $ 203,908 $ 162,862 $ 212,377 ========== ========== | ========== ========== ========== ========== | Total Assets............................ $8,052,755 $8,039,998 | $6,009,054 $5,587,677 $4,382,073 ========== ========== | ========== ========== ========== | | Capitalization: | Common Stockholder's Equity.......... $3,274,069 $3,163,701 | $1,459,260 $1,385,367 $1,557,073 Preferred Stock- | Not Subject to Mandatory Redemption 12,649 12,649 | 12,649 12,649 37,741 Subject to Mandatory Redemption.... -- 44,868 | 51,500 73,167 86,500 Company-Obligated Mandatorily | Redeemable Preferred Securities.... 125,244 125,250 | 125,000 125,000 125,000 Long-Term Debt....................... 1,210,446 1,224,001 | 1,093,987 1,133,760 1,173,532 ---------- ---------- | ---------- ---------- ---------- Total Capitalization............... $4,622,408 $4,570,469 | $2,742,396 $2,729,943 $2,979,846 ========== ========== | ========== ========== ========== | | Capitalization Ratios: | Common Stockholder's Equity.......... 70.8% 69.2%| 53.2% 50.7% 52.2% Preferred Stock- | Not Subject to Mandatory Redemption 0.3 0.3 | 0.5 0.5 1.3 Subject to Mandatory Redemption.... -- 1.0 | 1.9 2.7 2.9 Company-Obligated Mandatorily | Redeemable Preferred Securities.... 2.7 2.7 | 4.5 4.6 4.2 Long-Term Debt....................... 26.2 26.8 | 39.9 41.5 39.4 ----- ----- | ----- ----- ----- Total Capitalization............... 100.0% 100.0%| 100.0% 100.0% 100.0% ===== ===== | ===== ===== ===== | | Transmission and Distribution | Kilowatt-Hour Deliveries (Millions): | Residential.......................... 8,976 1,428 | 7,042 8,087 7,978 7,551 Commercial........................... 8,509 1,330 | 6,787 7,706 7,624 7,259 Industrial........................... 3,171 474 | 2,670 3,307 3,289 3,474 Other................................ 81 17 | 66 82 81 81 ------ ------- | ------ ------ ------ ------ Total Retail......................... 20,737 3,249 | 16,565 19,182 18,972 18,365 Total Wholesale...................... 5,039 295 | 1,780 2,161 1,622 1,690 ------ ------- | ------ ------ ------ ------ Total................................ 25,776 3,544 | 18,345 21,343 20,594 20,055 ====== ======= | ====== ====== ====== ====== | | Customers Served: | Residential.......................... 921,716 909,494 | 896,629 883,930 872,134 Commercial........................... 112,385 109,985 | 107,479 107,210 105,611 Industrial........................... 2,759 2,785 | 2,835 2,965 3,014 Other................................ 1,393 1,484 | 1,551 1,648 1,635 --------- --------- | --------- ------- ------- Total................................ 1,038,253 1,023,748 | 1,008,494 995,753 982,394 ========= ========= | ========= ======= ======= 1
JERSEY CENTRAL POWER & LIGHT 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 that is subject to certain risks and uncertainties. Such 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 market prices, legislative and regulatory changes (including revised environmental requirements), and the availability and cost of capital. Results of Operations In 2002, earnings on common stock increased to $253.4 million, from $59.3 million in 2001, due to higher operating revenues and the absence of a 2001 after-tax charge of $177.5 million, which reduced deferred costs in accordance with the Stipulation of Settlement related to the merger of FirstEnergy and GPU, Inc. Partially offsetting these favorable results were increased purchased power costs. In 2001, earnings on common stock decreased by 70.9% to $59.3 million, from $203.9 million in 2000. Results in 2001 were negatively impacted by the $177.5 after-tax charge previously discussed, and by higher purchased power costs. Partially offsetting these factors were lower other operating costs, and the absence of nuclear operating costs in 2001, as well as increases in operating revenues. Operating revenues increased $206.9 million in 2002, following a $142.2 million increase in 2001. The sources of the changes in operating revenues during 2002 and 2001, as compared to the prior year, are summarized in the following table. Sources of Revenue Changes 2002 2001 ------------------------------------------------------------------------- Increase (Decrease) (In millions) Increase in kilowatt-hour sales due to level of retail-customers shopping for generation service... $ 34.4 $ 67.3 Increase in other retail kilowatt-hour sales......... 98.2 38.4 Increase in wholesale sales.......................... 74.1 44.1 All other changes.................................... 0.2 (7.6) ------------------------------------------------------------------------- Net Increase in Operating Revenues................... $206.9 $142.2 ========================================================================= Electric Sales In 2002, further reductions in the number of customers who received their power from alternate suppliers, and therefore returned to us as full service customers, continued to have a positive effect on operating revenues. During 2002, only 0.7% of kilowatt-hours delivered were to shopping customers, whereas that percentage was 4.5% in 2001 and 11.7% in 2000. In addition to the higher revenues from returning shopping customers, warmer summer weather in both 2002 and 2001 contributed to significant increases in retail sales. This was partially offset by a decrease in kilowatt-hour sales to industrial customers, due to a decline in economic conditions during 2002. On August 1, 2002, the obligation to provide power to customers not choosing to receive power from an alternative energy supplier, referred to as Basic Generation Service (BGS), was transferred from us to external parties through an auction process authorized by the New Jersey Board of Public Utilities (NJBPU). Therefore, we began selling all of our self-supplied energy (non-utility generation and owned generation) into the wholesale market. This contributed to a significant increase in kilowatt-hour sales to wholesale customers during 2002; however, that increase was partially offset by lower average prices for energy in 2002, compared to 2001. Less kilowatt-hour sales were sold to wholesale customers in 2001; however, revenues increased due to higher average prices for energy sold compared to 2000 prices. 2 Changes in kilowatt-hour sales by customer class in 2002 and 2001 are summarized in the following table: Changes in Kilowatt-hour Sales 2002 2001 -------------------------------------------------- Increase (Decrease) Residential.................. 7.0% 4.7% Commercial................... 3.4% 5.3% Industrial................... (0.7)% (4.9)% -------------------------------------------------- Total Retail................. 4.3% 3.3% Wholesale.................... 142.8% (4.0)% -------------------------------------------------- Total Sales.................. 17.4% 2.6% -------------------------------------------------- Operating Expenses and Taxes Total operating expenses and taxes increased $208.2 million in 2002, after increasing $89.0 million in 2001, compared to the preceding year. In both periods, higher purchased power costs accounted for the majority of the increase. In 2002, the increase was offset in part by lower general taxes, due principally to a reduction in the New Jersey transitional energy facilities assessment during the second quarter of 2002. In 2001, the increase in purchased power costs was partially offset by lower other operating costs, due to reduced bad debt expense and employee benefit costs, and decreased nuclear operating costs. With the sale of the Oyster Creek Nuclear Generating Station in August 2000, we no longer have any nuclear operating costs, which were $78.5 million in 2000. However, as a result of the sale and higher customer demand in 2002 and 2001, we have been required to purchase more power. In 2002, fuel and purchased power costs increased $179.6 million, compared to 2001. The increase was due primarily to more power being purchased through two-party agreements and from associated companies during 2002. The increase was partially offset by a decrease in power purchased through the PJM Power Pool, and the absence of non-utility generation contract buyout costs recognized in 2001. Fuel and purchased power costs increased $177.6 million in 2001, compared to 2000. That increase was primarily attributed to greater quantities of power purchased through both two-party agreements and through the PJM Power Pool. Also contributing to the increase was a higher average cost of two-party power purchases in 2001 than in 2000. These increases were partially offset by lower fuel costs due to the sale of Oyster Creek. Other Income Other income increased $183.3 million in 2002, after decreasing $199.8 million in 2001, compared to the prior year. The change in both periods was due primarily to a 2001 charge of $300 million ($177.5 million net of tax) to reduce deferred costs in accordance with the Stipulation of Settlement related to the merger between FirstEnergy and GPU. Net Interest Charges In 2002, net interest charges decreased $5.3 million, compared to 2001, due primarily to reduced short-term borrowing levels and the amortization of fair value adjustments recognized in connection with the merger. These reductions were partially offset by a decrease in deferred interest costs. In addition, we issued $320 million of transition bonds through a special purpose finance subsidiary in 2002 (see Note 4F) and $150 million of notes in 2001, and redeemed $192 million of notes in 2002 and $40 million of notes in 2001. These transactions collectively had a minimal net effect on interest charges in 2002. In 2001, net interest charges decreased $0.2 million, compared to the prior year, with the slight decrease due to an increase in deferred interest costs, offset by interest expense on the senior notes issued in 2001 and higher average short-term debt levels. Preferred Stock Dividend Requirements In the third quarter of 2002, we realized a $3.6 million non-cash gain on the reacquisition of $29.8 million of preferred stock. Preferred stock dividend requirements decreased $3.1 million in 2002, and $1.7 million in 2001, compared to the prior year, due to the 2002 reacquisition and redemptions of cumulative preferred stock pursuant to mandatory and optional sinking fund provisions during 2002 and 2001. 3 Capital Resources and Liquidity Changes in Cash Position As of December 31, 2002, we had $4.8 million of cash and cash equivalents compared with $31.4 million as of December 31, 2001. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from operating activities totaled $309.0 million in 2002 and $289.8 million in 2001. The sources of these changes are as follows: Operating Cash Flows 2002 2001 ---------------------------------------------------------- (in millions) Cash earnings (1).................. $325 $219 Working capital and other.......... (16) 71 ---------------------------------------------------------- Total..................... $309 $290 ========================================================== (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, and and investment tax credits. Cash Flows From Financing Activities In 2002, net cash used for financing activities of $140.4 million reflects redemptions of debt and preferred stock, as well as $190.7 million in common dividend payments to FirstEnergy, offset in part by proceeds from the issuance of transition bonds. The following table provides details regarding new issues and redemptions during 2002: Securities Issued or Redeemed in 2002 ------------------------------------------------------------- (in millions) New Issues Transition Bonds (See Note 4)............... $320 ------------------------------------------------------------- Redemptions First Mortgage Bonds........................ 192 Preferred Stock............................. 52 Other....................................... 4 ------------------------------------------------------------- Total Redemptions....................... 248 Short-term Borrowings, net use of cash........... 18 ------------------------------------------------------------- We had no short-term indebtedness on December 31, 2002, compared to $18.1 million on December 31, 2001. We may borrow from our affiliates on a short-term basis. We will not issue first mortgage bonds (FMBs) other than as collateral for senior notes, since our senior note indentures prohibit (subject to certain exceptions) us from issuing any debt which is senior to the senior notes. As of December 31, 2002, we had the capability to issue $393 million of additional senior notes based upon FMB collateral. At year-end 2002, based upon applicable earnings coverage tests and our charter, we could issue $1.2 billion of preferred stock (assuming no additional debt was issued). At the end of 2002, our common equity as a percentage of capitalization stood at 71%, as compared to 69% and 53% at the end of 2001 and 2000, respectively. In 2001, we experienced a significant increase in this ratio due to the allocation of the purchase price when we were acquired by FirstEnergy. Cash Flows From Investing Activities In 2002, cash used in investing activities totaled $195.2 million, principally for property additions to support the distribution of electricity and loans to associated companies. In 2001, $167.0 million of cash was used in investing activities, principally for property additions. Our cash requirements in 2003 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. Over the next three years, we expect to meet our contractual obligations with cash from operations. Thereafter, we expect to use a combination of cash from operations and funds from the capital markets. 4 Less than 1-3 3-5 More than Contractual Obligations Total 1 Year Years Years 5 Years ------------------------------------------------------------------------------ (in millions) Long-term debt......... $1,374 $174 $ 243 $ 267 $ 690 Preferred stock (1).... 125 -- -- -- 125 Operating leases....... 66 3 3 3 57 Purchases (2).......... 4,159 528 943 953 1,735 --------------------------------------------------------------------------- Total............... $5,724 $705 $1,189 $1,223 $2,607 --------------------------------------------------------------------------- (1) Subject to mandatory redemption (2) Fuel and power purchases under contracts with fixed or minimum quantities and approximate timing Our capital spending for the period 2003 through 2007 is expected to be about $462 million, of which approximately $102 million applies to 2003. Following approval of the merger of FirstEnergy and GPU by the NJBPU on September 26, 2001, Standard and Poor's adjusted our corporate credit rating from A/A1 to BBB/A-2, our senior secured debt rating from A+ to BBB+ and our preferred stock rating from BBB+ to BB+. The credit rating outlook of both Standard & Poor's and Moody's is stable. On February 22, 2002, Moody's Investor Service changed its credit rating outlook for FirstEnergy from stable to negative. The change was based upon a decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania Public Utility Commission (PPUC) for reconsideration of its decision on the mechanism for sharing merger savings and reversed the PPUC decisions regarding rate relief and accounting deferrals rendered in connection with its approval of the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook for FirstEnergy's credit ratings from stable to negative citing recent developments including: damage to the Davis-Besse reactor vessel head (we have no ownership interest in Davis-Besse), the Pennsylvania Commonwealth Court decision, and deteriorating market conditions for some sales of FirstEnergy's remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook for FirstEnergy securities to negative from stable. The revised outlook reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's judgment about NRG's financial ability to consummate the purchase of four power plants from FirstEnergy and Fitch's expectation of subsequent delays in debt reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position added uncertainty to FirstEnergy's sale of power plants to NRG, FirstEnergy's ratings would not be affected. S&P found its cash flows sufficiently stable to support a continued (although delayed) program of debt and preferred stock redemption. S&P noted that it would continue to closely monitor our progress on various initiatives. On January 21, 2003, S&P indicated its concern about FirstEnergy's disclosure of non-cash charges related to deferred costs in Pennsylvania, pension and other post-retirement benefits, and Emdersa (FirstEnergy's Argentina operations), which were higher than anticipated in the third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear plant "...without significant delay beyond April 2003..." as key to maintaining its current debt ratings. S&P also identified other issues it would continue to monitor including: FirstEnergy's deleveraging efforts, free cash generated during 2003, the Jersey Central Power & Light Company rate case, successful hedging of our short power position, and continued capture of projected merger savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse plant in the spring of 2003, the Nuclear Regulatory Commission (NRC) must authorize the unit's restart following a formal inspection process prior to FirstEnergy's returning the unit to service. Significant delays in the planned date of Davis-Besse's return to service or other factors (identified above) affecting the speed with which FirstEnergy reduces debt could put additional pressure on JCP&L's credit ratings. Market Risk Information We use various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. Our Risk Policy Committee, comprised of FirstEnergy executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk We are exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, we use a variety of non-derivative and derivative instruments, including forward contracts, options and futures contracts. The derivatives are used for hedging purposes. Most of our non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under Statement of Financial Accounting Standards (SFAS) 133. The change in the fair value of commodity derivative contracts related to energy production during 2002 is summarized in the following table: 5 Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total --------- ----- ----- (In millions) Change in the Fair Value of Commodity Derivative Contracts Outstanding net asset as of January 1, 2002...................... $ 1.1 $ 0.4 $1.5 New contract value when entered.................................. -- 2.1 2.1 Additions/Change in value of existing contracts.................. 7.6 (2.3) 5.3 Settled contracts................................................ -- (0.3) (0.3) -------------------------- Net Assets - Derivatives Contracts as of December 31, 2002 (1)... $ 8.7 $(0.1) $8.6 ========================== Impact of Changes in Commodity Derivative Contracts (2) Balance Sheet Effects: Other Comprehensive Income (Pre-Tax).......................... $ -- $(2.6) $2.6) Regulatory Liability.......................................... $ 7.6 $ -- $7.6
(1) Includes $8.6 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Represents the increase in value of existing contracts and settled contracts. Non-Hedge Hedge Total --------- ----- ----- (In millions) Current- Other Liabilities............... $ -- $(0.1) $(0.1) Non-Current- Other Deferred Charges.......... 8.7 -- 8.7 ---- ---- ----- Net assets.................... $8.7 $(0.1) $ 8.6 ==== ====== ===== Derivatives included on the Consolidated Balance Sheet as of December 31, 2002: The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, we rely on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. We use these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table: Source of Information - Fair Value by Contract Year --------------------------------------------------- 2003 2004 2005 2006 Thereafter Total ---- ---- ---- ---- ---------- ----- (In millions) Prices based on external sources(1)... $0.2 $0.3 $0.7 $ -- $ -- $1.2 Prices based on models................ -- -- -- 1.1 6.3 7.4 --------------------------------------- Total(2).......................... $0.2 $0.3 $0.7 $1.1 $6.3 $8.6 ======================================= (1) Broker quote sheets. (2) Includes $8.6 million from an embedded option that is offset by a regulatory liability and does not affect earnings. We perform sensitivity analyses to estimate our exposure to the market risk of our commodity position. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on our consolidated financial position or cash flows as of December 31, 2002. Interest Rate Risk ------------------ Our exposure to fluctuations in market interest rates is reduced since our debt has fixed interest rates, as noted in the following table. 6 Comparison of Carrying Value to Fair Value ----------------------------------------------------------------------------------------------------------------
There- Fair 2003 2004 2005 2006 2007 after Total Value ---------------------------------------------------------------------------------------------------------------- (Dollars in millions) Assets ---------------------------------------------------------------------------------------------------------------- Investments other than Cash and Cash Equivalents-Fixed Income.... -- -- -- -- -- $224 $ 224 $ 224 Average interest rate....... 5.0% 5.0% ---------------------------------------------------------------------------------------------------------------- ---------------------------------------------------------------------------------------------------------------- Liabilities ---------------------------------------------------------------------------------------------------------------- Long-term Debt: Fixed rate..................... $174 $176 $67 $231 $36 $690 $1,374 $1,415 Average interest rate ...... 6.1% 6.9% 6.1% 6.5% 6.1% 7.0% 6.7% ---------------------------------------------------------------------------------------------------------------- Preferred Stock................ -- -- -- -- -- $125 $ 125 $ 127 Average dividend rate ...... 8.6% 8.6% ----------------------------------------------------------------------------------------------------------------
We are subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. Changes in the market value of our nuclear decommissioning trust funds are recognized by making corresponding changes to the decommissioning liability, as described in Note 1 to the consolidated financial statements. Equity Price Risk ----------------- Included in nuclear decommissioning trusts are marketable equity securities carried at their market value of approximately $52 million and $65 million at December 31, 2002 and 2001, 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, 2002. (See Note 1 - "Supplemental Cash Flows Information.") Outlook Our industry continues to transition to a more competitive environment. Beginning in late 1999, all of our customers could select alternative energy suppliers. We continue to deliver power to homes and businesses through our existing distribution system, which remains regulated. To support customer choice, rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs (confirmed by a NJBPU Final Decision and Order issued in March 2001). On August 1, 2002, the obligation to provide power to those customers not choosing to receive power from an alternative energy supplier, referred to as BGS, was transferred from us to external parties through an auction process authorized by the NJBPU. Regulatory assets are costs which regulatory agencies have authorized for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of our regulatory assets are expected to continue to be recovered under the provisions of the regulatory plans as discussed below. Our regulatory assets totaled $3.2 billion and $3.3 billion as of December 31, 2002 and 2001, respectively. Regulatory Matters Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. On August 1, 2002, we submitted two rate filings with the NJBPU. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current market transition charge and societal benefits charge rates; one proposed method of recovery of these costs is the securitization of the deferred balance as further discussed below. This securitization methodology is similar to the Oyster Creek securitization discussed below. Hearings began in February 2003. The Administrative Law Judge's recommended decision is due in June 2003 and the NJBPU's subsequent decision is due in July 2003. Our regulatory plan provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. A February 2002 NJBPU order authorized us to issue $320 million of transition bonds to securitize the recovery of these costs and provided for a usage-based non-bypassable transition bond charge and for the transfer of the bondable transition property to another entity. We sold $320 million of transition bonds through a wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 -- that debt is recognized on the Consolidated Balance Sheet (see Note 4). We are permitted to defer for future collection from customers the amounts by which our costs of supplying BGS to non-shopping customers and costs incurred under non-utility generation agreements exceed amounts collected through BGS and market transition charge rates. As of December 31, 2002, the accumulated deferred cost balance totaled approximately $549 million. The NJBPU also allowed securitization of our deferred balance to the extent permitted by law upon our application and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. 7 In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electricity demands of all customers who have not selected an alternative supplier. The results of the February 2002 auction, with the NJBPU's approval, removed our BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February 2003, the auctioning of BGS for the period beginning August 1, 2003 took place. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and an hourly price bid (applicable to all large industrial customers) process. We will sell all self-supplied energy (non-utility generation and owned generation) into the wholesale market, which will offset our deferred energy cost balance. As part of the restructuring orders, we were obligated, through July 31, 2002, to supply electricity to customers who do not choose an alternate supplier. The total forecasted peak of this obligation in 2002 was 5,400 MW. The successful BGS auction in New Jersey removed that BGS obligation for the period from August 1, 2002 to July 31, 2003. FERC Regulatory Matters On December 19, 2002 the Federal Energy Regulatory Commission (FERC) granted unconditional Regional Transmission Organization status to PJM Interconnection, LLC (PJM). We are a transmission owner in PJM. Environmental Matters We have been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of December 31, 2002, based on estimates of the total costs of cleanup, our proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, we have accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered through a non-bypassable societal benefits charge. We have accrued liabilities aggregating approximately $47.1 million as of December 31, 2002. We do not believe environmental remediation costs will have a material adverse effect on our financial condition, cash flows or results of operations. Legal Matters Various lawsuits, claims and proceedings related to our normal business operations are pending against us, the most significant of which are described below. We have a 25% ownership interest in Unit 2 of the Three Mile Island Nuclear Plant (TMI-2), which was damaged during a 1979 accident. As a result of the accident, claims for alleged personal injury against us, Metropolitan Edison Company, Pennsylvania Electric Company and GPU (the defendants) had been filed in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the defendants and dismissed the ten initial "test cases" which had been selected for a test case trial. In January 2002, the District Court granted our motion for summary judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice of appeal of this decision (see Note 6 - Other Legal Proceedings). In December 2002, the Court of Appeals for the Third Circuit refused to hear the appeal which effectively ended further legal action for those claims. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including JCP&L. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, we provided unsafe, inadequate or improper service to our customers. In July 1999, two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court against JCP&L and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in our service territory. In May 2001, the court denied without prejudice our motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that we are bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion to file an appeal of this decision was denied by the New Jersey Appellate Division. We have also filed a motion for partial summary judgment that is currently pending before the Superior Court. We are unable to predict the outcome of these matters. 8 Significant Accounting Policies We prepare our consolidated financial statements in accordance with accounting principles that are generally accepted in the United States. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect 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 these specific factors. Our more significant accounting policies are described below. Purchase Accounting On November 7, 2001, the merger between FirstEnergy and GPU became effective, and we became a wholly owned subsidiary of FirstEnergy. The merger was accounted for by the purchase method of accounting, which requires judgment regarding the allocation of the purchase price based on the fair values of the assets acquired (including intangible assets) and the liabilities assumed. The fair values of the acquired assets and assumed liabilities were based primarily on estimates. The adjustments reflected in our records, which were finalized in the fourth quarter of 2002, primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Based on the guidance provided by SFAS 142, "Goodwill and Other Intangible Assets," we evaluate our goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. The forecasts used in our evaluations of goodwill reflect operations consistent with our general business assumptions. Unanticipated changes in those assumptions could have a significant effect on our future evaluations of goodwill. As of December 31, 2002, we had recorded goodwill of approximately $2.0 billion related to the merger. Regulatory Accounting We are subject to regulation that sets the prices (rates) we are permitted to charge our customers based on 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. As a result of the changing regulatory framework in New Jersey, a significant amount of regulatory assets have been recorded - $3.2 billion as of December 31, 2002. We regularly 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. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. We continually monitor our derivative contracts to determine if our activities, expectations, intentions, assumptions and estimates remain valid. As part of our normal operations, we enter into commodity contracts which increase the impact of derivative accounting judgments. Revenue Recognition We follow the accrual method of accounting for revenues, recognizing revenue for kilowatt-hours that have been delivered but not yet billed through the end of the accounting period. The determination of unbilled revenues requires management to make various estimates including: o Net energy generated or purchased for retail load o Losses of energy over transmission and distribution lines o Mix of kilowatt-hour usage by residential, commercial and industrial customers o Kilowatt-hour usage of customers receiving electricity from alternative suppliers 9 Pension and Other Postretirement Benefits Accounting Our reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions (OPEB) are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plans, and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations and pension and OPEB costs. In accordance with SFAS 87, "Employers' Accounting for Pensions" and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, we consider currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to the significant decline in corporate bond yields and interest rates in general during 2002, we reduced the assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001. Our 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. The market values of our pension assets have been affected by sharp declines in the equity markets since mid-2000. In 2002, plan assets have earned (11.3)%. Our pension costs in 2002 were computed assuming a 10.25% rate of return on plan assets. As of December 31, 2002 the assumed return on plan assets was reduced to 9.00% based upon our projection of future returns and pension trust investment allocation of approximately 60% large cap equities, 10% small cap equities and 30% bonds. Based on pension assumptions and pension plan assets as of December 31, 2002, we will not be required to fund our pension plans in 2003. While OPEB plan assets have also been affected by sharp declines in the equity market, the impact is not as significant due to the relative size of the plan assets. However, health care cost trends have significantly increased and will affect future OPEB costs. The 2003 composite health care trend rate assumption is approximately 10%-12% gradually decreasing to 5% in later years, compared to our 2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in later years. In determining our trend rate assumptions, we included the specific provisions of our health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in our health care plans, and projections of future medical trend rates. Our non-cash, pre-tax pension and OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $29 million and $10 million, respectively - a total of $39 million in 2003 as compared to 2002. Increase in Costs from Adverse Changes in Key Assumptions ----------------------------------------------------------------------------- Assumption Adverse Change Pension OPEB Total ----------------------------------------------------------------------------- (In millions) Discount rate................ Decrease by 0.25% $2.5 $1.3 $3.8 Long-term return on assets... Decrease by 0.25% $1.7 $0.5 $2.2 Health care trend rate....... Increase by 1% na $3.7 $3.7 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 may not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment were to occur, other than of a temporary nature, we would recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). 10 Recently Issued Accounting Standards Not Yet Implemented -------------------------------------------------------- SFAS 143, "Accounting for Asset Retirement Obligations" In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded 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 regulatory assets or liabilities if the criteria for such treatment are met. Upon retirement, a gain or loss would be recorded if the cost to settle the retirement obligation differs from the carrying amount. We have identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $98 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $98 million. The asset retirement liability at the date of adoption was $104 million. As of December 31, 2002, we had recorded decommissioning liabilities of $130 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all of our nuclear decommissioning costs will be recoverable through regulated rates. Therefore, we recognized a regulatory liability of $26 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities" This statement, which was issued by the FASB in July 2002, requires the recognition of costs associated with exit or disposal activities at the time they are incurred rather than when management commits to a plan of exit or disposal. It also requires the use of fair value for the measurement of such liabilities. The new standard supersedes guidance provided by Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This new standard was effective for exit and disposal activities initiated after December 31, 2002. Since it is applied prospectively, there will be no impact upon adoption. However, SFAS 146 could change the timing and amount of costs recognized in connection with future exit or disposal activities. FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. We do not believe that implementation of FIN 45 will be material but we will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This Interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. We currently have transactions with entities in connection with the sale of preferred securities and debt secured by bondable property, and which are reasonably possible of meeting within the scope of this interpretation, and which may meet the definition of a VIE in accordance with FIN 46. We currently consolidate those entities and believe we will continue to consolidate following the adoption of FIN 46. 11 JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 ---------------------------------------------------------------------------------------------------------------------- (In thousands) OPERATING REVENUES........................................ $2,328,415 $282,902 | $1,838,638 $1,979,297 ---------- -------- | ---------- ---------- | OPERATING EXPENSES AND TAXES: | Fuel and purchased power............................... 1,248,012 136,123 | 932,300 890,812 Nuclear operating costs................................ -- -- | -- 78,487 Other operating costs.................................. 272,890 40,670 | 237,513 303,353 ---------- -------- | ---------- ---------- Total operation and maintenance expenses............. 1,520,902 176,793 | 1,169,813 1,272,652 Provision for depreciation and amortization............ 244,759 35,124 | 205,918 235,001 General taxes.......................................... 56,049 8,919 | 56,582 64,398 Income taxes........................................... 171,496 18,400 | 113,478 124,019 ---------- -------- | ---------- ---------- Total operating expenses and taxes................... 1,993,206 239,236 | 1,545,791 1,696,070 ---------- -------- | ---------- ---------- | OPERATING INCOME.......................................... 335,209 43,666 | 292,847 283,227 | OTHER INCOME (EXPENSE).................................... 7,653 1,186 | (176,875) 24,146 ---------- -------- | ---------- ----------- | INCOME BEFORE NET INTEREST CHARGES........................ 342,862 44,852 | 115,972 307,373 ---------- -------- | ---------- ---------- | NET INTEREST CHARGES: | Interest on long-term debt............................. 92,314 14,234 | 77,205 85,220 Allowance for borrowed funds used during | construction......................................... (583) 135 | (1,665) (1,287) Deferred interest ..................................... (8,815) (2,243) | (12,557) (7,951) Other interest expense................................. (2,643) 1,080 | 9,427 9,879 Subsidiary's preferred stock dividend requirements..... 10,694 1,605 | 9,095 10,700 ---------- -------- ---------- ---------- Net interest charges................................. 90,967 14,811 | 81,505 96,561 ---------- -------- | ---------- ---------- | NET INCOME................................................ 251,895 30,041 | 34,467 210,812 | PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,125 698 | 4,547 6,904 | GAIN ON PREFERRED STOCK REACQUISITION..................... (3,589) -- | -- -- ---------- --------- | ---------- ---------- | EARNINGS ON COMMON STOCK.................................. $ 253,359 $ 29,343 | $ 29,920 $ 203,908 ========== ======== | ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 12
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS
As of December 31, 2002 2001 ------------------------------------------------------------------------------------------------------------------ (In thousands) ASSETS UTILITY PLANT: In service..................................................................... $3,478,803 $3,431,823 Less-Accumulated provision for depreciation.................................... 1,343,846 1,313,259 ---------- ---------- 2,134,957 2,118,564 Construction work in progress- Electric plant............................................................... 20,687 60,482 ---------- ---------- 2,155,644 2,179,046 OTHER PROPERTY AND INVESTMENTS: Nuclear plant decommissioning trusts........................................... 106,820 114,899 Nuclear fuel disposal trust.................................................... 149,738 137,098 Long-term notes receivable from associated companies........................... 20,333 20,333 Other.......................................................................... 18,202 6,643 ---------- ---------- 295,093 278,973 ---------- ---------- CURRENT ASSETS: Cash and cash equivalents...................................................... 4,823 31,424 Receivables- Customers (less accumulated provisions of $4,509,000 and $12,923,000 respectively, for uncollectible accounts).................................. 247,624 226,392 Associated companies......................................................... 318 6,412 Other........................................................................ 20,134 20,729 Notes receivable from associated companies..................................... 77,358 -- Materials and supplies, at average cost........................................ 1,341 1,348 Prepayments and other.......................................................... 37,719 16,569 ---------- ---------- 389,317 302,874 ---------- ---------- DEFERRED CHARGES: Regulatory assets.............................................................. 3,199,012 3,324,804 Goodwill....................................................................... 2,000,875 1,926,526 Other.......................................................................... 12,814 27,775 ---------- ---------- 5,212,701 5,279,105 $8,052,755 $8,039,998 CAPITALIZATION AND LIABILITIES CAPITALIZATION (See Consolidated Statements of Capitalization): Common stockholder's equity.................................................... $3,274,069 $3,163,701 Preferred stock- Not subject to mandatory redemption.......................................... 12,649 12,649 Subject to mandatory redemption.............................................. -- 44,868 Company-obligated mandatorily redeemable preferred securities.................. 125,244 125,250 Long-term debt................................................................. 1,210,446 1,224,001 ---------- ---------- 4,622,408 4,570,469 CURRENT LIABILITIES: Currently payable long-term debt and preferred stock........................... 173,815 60,848 Short-term borrowings (Note 5)- Associated companies......................................................... -- 18,149 Accounts payable- Associated companies......................................................... 170,803 171,168 Other........................................................................ 106,504 89,739 Accrued taxes................................................................. 13,844 35,783 Accrued interest............................................................... 27,161 25,536 Other.......................................................................... 112,408 79,589 ---------- ---------- 604,535 480,812 ---------- ---------- DEFERRED CREDITS: Accumulated deferred income taxes.............................................. 691,721 514,216 Accumulated deferred investment tax credits.................................... 9,939 13,490 Power purchase contract loss liability ........................................ 1,710,968 1,968,823 Nuclear fuel disposal costs.................................................... 166,191 163,377 Nuclear plant decommissioning costs............................................ 135,355 137,424 Other.......................................................................... 111,638 191,387 ---------- ---------- 2,825,812 2,988,717 COMMITMENTS AND CONTINGENCIES (Notes 3 and 6)................................................................. ---------- ---------- $8,052,755 $8,039,998 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. 13
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2002 2001 ---------------------------------------------------------------------------------------------------------------- (Dollars in thousands, except per share amounts) COMMON STOCKHOLDER'S EQUITY: Common stock, par value $10 per share, authorized 16,000,000 shares 15,371,270 shares outstanding.................................................... $ 153,713 $ 153,713 Other paid-in capital.............................................................. 3,029,218 2,981,117 Accumulated other comprehensive loss (Note 4E)..................................... (865) (472) Retained earnings (Note 4A)........................................................ 92,003 29,343 ------------ ---------- Total common stockholder's equity................................................ 3,274,069 3,163,701 ------------ ---------- Number of Shares Optional Outstanding Redemption Price ---------------- -------------------- 2002 2001 Per Share Aggregate ---- ---- --------- --------- PREFERRED STOCK (Note 4B): Cumulative, without par value- Authorized 125,000 shares Not Subject to Mandatory Redemption: 4% Series........................ 125,000 125,000 $106.50 $13,313 12,649 12,649 Subject to Mandatory Redemption: 8.65% Series J..................... -- 250,001 101.30 $25,325 -- 26,750 7.52% Series K..................... -- 265,000 103.76 27,496 -- 28,951 Redemption Within One Year......... -- -- -- (10,833) ------- ------- ------ ------- ------ -------- Total Subject to Mandatory Redemption..................... -- 515,001 $52,821 -- 44,868 ======= ======= ======= ------ ------- COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY LIMITED PARTNERSHIP HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES (NOTE 4C): Cumulative, $25 par value - Authorized 5,000,000 shares Subject to Mandatory Redemption: 8.56% due 2044.................................................................. 125,244 125,250 LONG-TERM DEBT (Note 4D): First mortgage bonds: 9.000% due 2002................................................................... -- 50,000 6.375% due 2003................................................................... 150,000 150,000 7.125% due 2004................................................................... 160,000 160,000 6.780% due 2005................................................................... 50,000 50,000 6.850% due 2006................................................................... 40,000 40,000 8.250% due 2006................................................................... 23,053 50,000 7.900% due 2007................................................................... 18,361 40,000 7.125% due 2009................................................................... 6,300 6,300 7.100% due 2015................................................................... 12,200 12,200 9.200% due 2021................................................................... 22,963 50,000 8.320% due 2022................................................................... 40,000 40,000 8.550% due 2022................................................................... 13,623 30,000 8.820% due 2022................................................................... -- 12,000 8.850% due 2022................................................................... -- 38,000 7.980% due 2023................................................................... 40,000 40,000 7.500% due 2023................................................................... 125,000 125,000 8.450% due 2025................................................................... 50,000 50,000 6.750% due 2025................................................................... 150,000 150,000 ---------- ---------- Total first mortgage bonds...................................................... 901,500 1,093,500 ---------- ---------- Secured notes: 6.450% due 2006................................................................... 150,000 150,000 4.190% due 2007................................................................... 91,111 -- 5.390% due 2010................................................................... 52,297 -- 5.810% due 2013................................................................... 77,075 -- 6.160% due 2017................................................................... 99,517 -- ---------- ---------- Total secured notes............................................................. 470,000 150,000 ---------- ---------- Unsecured notes: 7.69% due 2039.................................................................... 2,984 2,998 ---------- ----------- Net unamortized premium on debt..................................................... 9,777 27,518 ---------- ---------- Long-term debt due within one year.................................................. (173,815) (50,015) ---------- ----------- Total long-term debt............................................................ 1,210,446 1,224,001 ---------- ---------- TOTAL CAPITALIZATION................................................................... $4,622,408 $4,570,469 ========== ========== The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 14
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated Common Stock Other Other Comprehensive Number Par Paid-In Comprehensive Retained Income of Shares Value Capital Income (Loss) Earnings ------------- --------- ----- ------- ------------- -------- (Dollars in thousands) Balance, January 1, 2000....................... 15,371,270 $153,713 $ 510,769 $ 7 $ 720,878 Net income.................................. $210,812 210,812 Minimum pension liability................... (15) (15) -------- Comprehensive income........................ 210,797 -------- Cash dividends on preferred stock........... (6,904) Cash dividends on common stock.............. (130,000) -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2000..................... 15,371,270 153,713 510,769 (8) 794,786 Net income.................................. 34,467 34,467 Net unrealized gain on investments.......... 2 2 Net unrealized gain on derivative instruments............................... 768 768 -------- Comprehensive income........................ 35,237 -------- Cash dividends on preferred stock........... (4,547) Cash dividends on common stock ............ (175,000) -------------------------------------------------------------------------------------------------------------------- Balance, November 6, 2001...................... 15,371,270 153,713 510,769 762 649,706 Purchase accounting fair value adjustment... 2,470,348 (762) (649,706) -------------------------------------------------------------------------------------------------------------------- Balance, November 7, 2001...................... 15,371,270 153,713 2,981,117 -- -- Net income.................................. 30,041 30,041 Net unrealized gain (loss) on derivative instruments............................... (472) (472) -------- Comprehensive income........................ 29,569 -------- Cash dividends on preferred stock........... (698) --------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001..................... 15,371,270 153,713 2,981,117 (472) 29,343 Net income.................................. 251,895 251,895 Net unrealized gain (loss) on derivative instruments............................... (393) (393) -------- Comprehensive income........................ $251,502 -------- Cash dividends on preferred stock........... 1,465 Cash dividends on common stock.............. (190,700) Purchase accounting fair value adjustment . 48,101 -------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002..................... 15,371,270 $153,713 $3,029,218 $ (865) $ 92,003 ==================================================================================================================== CONSOLIDATED STATEMENTS OF PREFERRED STOCK Not Subject to Subject to Mandatory Redemption Mandatory Redemption -------------------- --------------------- Number Carrying Number Carrying of Shares Value of Shares Value --------- -------- --------- -------- (Dollars in thousands) Balance, January 1, 2000............ 125,000 $12,649 5,840,000 $209,000 Redemptions- 7.52% Series.................... (50,000) (5,000) 8.65% Series.................... ( 166,666) (16,667) ----------------------------------------------------------------------------------------- Balance, December 31, 2000.......... 125,000 12,649 5,623,334 187,333 Redemptions- 7.52% Series.................... (25,000) (2,500) 8.65% Series.................... (83,333) (8,333) Purchase accounting fair value adjustment............. 4,451 ----------------------------------------------------------------------------------------- Balance, December 31, 2001.......... 125,000 12,649 5,515,001 180,951 Redemptions- 7.52% Series.................... (265,000) (28,951) 8.65% Series.................... (250,001) (26,750) Purchase accounting fair value adjustment............. (6) ----------------------------------------------------------------------------------------- Balance, December 31, 2002.......... 125,000 $12,649 5,000,000 $125,244 ========================================================================================= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
15 JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 ----------------------------------------------------------------------------------------------------------------------- (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income........................................................ $ 251,895 $ 30,041 | $ 34,467 $ 210,812 Adjustments to reconcile net income to net | cash from operating activities: | Provision for depreciation and amortization.................. 244,759 35,124 | 205,918 235,001 Nuclear fuel and lease amortization.......................... -- -- | -- 11,472 Other amortization........................................... 849 1,360 | 23,025 34,563 Deferred costs recoverable as regulatory assets.............. (285,065) (25,471) | (29,312) (229,321) Deferred income taxes, net................................... 115,866 5,609 | (58,132) 270,479 Investment tax credits, net.................................. (3,551) (540) | (3,057) (15,027) Receivables.................................................. (14,542) 7,050 | 27,177 11,766 Materials and supplies....................................... 7 2 | (842) (268) Accounts payable............................................. 16,399 (5,060) | (44,498) 51,633 Other (Note 7)............................................... (17,642) 20,563 | 66,328 (230,100) --------- -------- | --------- --------- Net cash provided from operating activities................ 308,975 68,678 | 221,074 351,010 --------- -------- | --------- --------- | CASH FLOWS FROM FINANCING ACTIVITIES: | New Financing- | Long-term debt............................................... 318,106 -- | 148,796 -- Short-term borrowings, net................................... -- -- | -- 29,200 Redemptions and Repayments- | Preferred stock.............................................. (51,500) -- | (10,833) (21,667) Long-term debt............................................... (196,033) (40,000) | -- (40,000) Short-term borrowings, net................................... (18,149) (1,851) | (9,200) -- Capital lease payments....................................... -- -- | -- (48,516) Dividend Payments- | Common stock................................................. (190,700) -- | (175,000) (130,000) Preferred stock.............................................. (2,125) (698) | (4,547) (7,065) --------- -------- | --------- ---------- Net cash used for financing activities..................... (140,401) (42,549) | (50,784) (218,048) --------- -------- | ---------- ---------- | CASH FLOWS FROM INVESTING ACTIVITIES: | Property additions............................................. (97,346) (21,487) | (141,030) (144,389) Contributions to decommissioning trusts........................ -- (202) | (1,004) (130,444) Sale of investments............................................ -- -- | -- 74,797 Loans to associated companies.................................. (77,358) -- | -- -- Other.......................................................... (20,471) (1,078) | (2,215) (624) --------- -------- | ----------- --------- Net cash used for investing activities..................... (195,175) (22,767) | (144,249) (200,660) --------- -------- | --------- ---------- | | Net increase (decrease) in cash and cash equivalents.............. (26,601) 3,362 | 26,041 (67,698 Cash and cash equivalents at beginning of period.................. 31,424 28,062 | 2,021 69,719 --------- -------- | --------- --------- Cash and cash equivalents at end of period........................ $ 4,823 $ 31,424 | $ 28,062 $ 2,021 ========= ======== | ========= ========= | SUPPLEMENTAL CASH FLOWS INFORMATION: | Cash Paid During the Year- | Interest (net of amounts capitalized)........................ $ 92,152 $ 4,787 | $ 95,509 $ 99,961 ========= ======== | ========= ========= Income taxes (refund)........................................ $ 83,776 $ 20,586 | $ 19,365 $ (50,105) ========= ======== | ========= ========= The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 16
JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 - 2002 Dec. 31, 2001 Nov. 6, 2001 2000 --------------------------------------------------------------------------------------------------------------------- (In thousands) GENERAL TAXES: Real and personal property....................................... $ 4,362 $ 283 | $ 3,589 $ 4,093 State gross receipts............................................. -- 1,269 | -- -- Social security and unemployment................................. -- (1) | 7 -- New Jersey Transitional Energy Facilities Assessment*............ 39,387 6,765 | 42,418 47,521 Other............................................................ 12,300 603 | 10,568 12,784 -------- --------- | --------- --------- Total general taxes....................................... $ 56,049 $ 8,919 | $ 56,582 $ 64,398 ======== ========= | ========= ========= | PROVISION FOR INCOME TAXES: | Currently payable- | Federal....................................................... $ 55,731 $ 11,827 | $ 41,826 $(109,572) State......................................................... 13,809 3,205 | 19,415 (26,005) -------- --------- | --------- --------- `69,540 15,032 | 61,241 (135,577) -------- --------- | --------- --------- Deferred, net- | Federal....................................................... 88,758 4,268 | (36,210) 209,127 State......................................................... 27,108 1,341 | (21,922) 61,352 -------- --------- | --------- ---------- 115,866 5,609 | (58,132) 270,479 -------- --------- | --------- --------- Investment tax credit amortization............................... (3,551) (540) | (3,057) (15,027) -------- --------- | --------- --------- Total provision for income taxes.......................... $181,855 $ 20,101$ | $ 52 $ 119,875 ======== ========== | ========= ========= | INCOME STATEMENT CLASSIFICATION | OF PROVISION FOR INCOME TAXES: | Operating income................................................. $171,496 $ 18,400 | $ 113,478 $ 124,019 Other income..................................................... 10,359 1,701 | (113,426) (4,144) -------- --------- | --------- --------- Total provision for income taxes.......................... $181,855 $ 20,101 | 52 $ 119,875 ======== ========= | ========= ========= | RECONCILIATION OF FEDERAL INCOME TAX | EXPENSE AT STATUTORY RATE TO TOTAL | PROVISION FOR INCOME TAXES: | Book income before provision for income taxes.................... $433,749 $ 50,142 | $ 34,519 $ 330,688 ======== ========= | ========= ========= Federal income tax expense at statutory rate..................... $151,812 $ 17,550 | $ 12,082 $ 115,741 Increases (reductions) in taxes resulting from- | Amortization of investment tax credits........................ (3,550) (540) | (3,057) (15,027) Depreciation.................................................. 7,154 226 | 3,563 3,230 State income tax, net of federal benefit...................... 27,111 3,077 | 4,355 21,987 Allocated share of consolidated tax savings................... -- -- | (8,509) -- Sale of generation assets..................................... -- -- | -- (6,239) Other, net.................................................... (672) (212) | (8,382) 183 -------- --------- | ---------- --------- Total provision for income taxes.......................... $181,855 $ 20,101 | $ 52 $ 119,875 ======== ========= | ========== ========= | ACCUMULATED DEFERRED INCOME TAXES AT | DECEMBER 31: | Property basis differences....................................... $297,983 $ 288,255 | $ 302,476 Nuclear decommissioning.......................................... 44,775 59,716 | 97,817 Deferred sale and leaseback costs................................ (16,451) (16,240) | (15,605) Purchase accounting basis difference............................. (1,253) (71,900) | -- Sale of generation assets........................................ (17,861) 184,625 | 235,923 Regulatory transition charge..................................... 224,117 123,042 | 99,930 Provision for rate refund........................................ (29,370) (46,942) | (46,942) Customer receivables for future income taxes..................... (5,336) 16,749 | 33,234 Oyster Creek securitization...................................... 202,448 -- | -- Other............................................................ (7,331) (23,089) | (40,786) -------- --------- | --------- Net deferred income tax liability......................... $691,721 $ 514,216 | $ 666,047 ======== ========= | ========= * Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The consolidated financial statements include Jersey Central Power & Light Company (Company) and its wholly owned subsidiaries. All significant intercompany transactions have been eliminated. The Company is a wholly owned subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the issued and outstanding common shares of Ohio Edison Company (OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison Company (TE), American Transmission Systems, Inc. (ATSI), Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec were formerly wholly owned subsidiaries of GPU, Inc., which merged with FirstEnergy on November 7, 2001. Pre-merger and post-merger period financial results are separated by a heavy black line. The Company follows the accounting policies and practices prescribed by the Securities and Exchange Commission (SEC), the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). 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. (A) CONSOLIDATION- The Company consolidates all majority-owned subsidiaries, after eliminating the effects of intercompany transactions. Non-majority owned investments, including investments in limited liability companies, partnerships and joint ventures, are accounted for under the equity method when the Company is able to influence their financial or operating policies. Investments in corporations resulting in voting control of 20% or more are presumed to be equity method investments. Limited partnerships are evaluated in accordance with SEC Staff D-46, "Accounting for Limited Partnership Investments" and American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to 5 percent threshold for the presumption of influence. For all remaining investments (excluding those within the scope of Statement of Financial Accounting Standards (SFAS) 115, the Company applies the cost method. (B) REVENUES- The Company's principal business is providing electric service to customers in New Jersey. 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. See Note 7 - Other Information for discussion of reporting of independent system operator transactions. Receivables from customers include sales to residential, commercial and industrial customers and sales to wholesale customers. There was no material concentration of receivables as of December 31, 2002 or 2001, with respect to any particular segment of the Company's customers. (C) REGULATORY PLAN- New Jersey continues to evolve to a competitive electric utility marketplace. In 2001, the NJBPU issued a Final Decision and Order (Final Order) with respect to the Company's rate unbundling, stranded cost and restructuring filings, which superseded its 1999 Summary Order. The Final Order confirmed rate reductions set forth in the 1999 Summary Order, which remain in effect at increasing levels through July 2003, confirmed the right of customers to select their generation supplier and deregulated electric generation service costs. The Final Order also confirmed the establishment of a non-bypassable societal benefits charge to recover costs including nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable market transition charge primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and stranded costs related to prior generating asset divestitures until the Company's request for an Internal Revenue Service (IRS) ruling regarding the treatment of associated federal income tax benefits is acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to the Company's net income since the contingency existed prior to the Company being acquired by FirstEnergy. In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. In February 2002, the Company received NJBPU authorization to issue $320 million of transition bonds to securitize the recovery of these costs. The NJBPU order also provided for a usage-based non-bypassable transition bond charge and for the transfer of the bondable transition property to another entity. JCP&L sold $320 million of transition bonds through its wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 - those bonds are recognized on the Consolidated Balance Sheet (see Note 4F). 18 The Company obtains its supply of electricity almost entirely from contracted and open market purchases. The Company is permitted to defer for future collection from customers the amounts by which its costs for supplying non-shopping customers and costs incurred under non-utility generation agreements exceed amounts collected through its Basic Generation Service (BGS) and market transition charge rates. As of December 31, 2002, the accumulated deferred cost balance totaled approximately $549 million. The NJBPU also allowed securitization of the Company's deferred balance to the extent permitted by law upon application by the Company and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization. Under New Jersey transition legislation, all electric distribution companies, including the Company, were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. On August 1, 2002, the Company submitted two rate filings with the NJBPU. The first filing requested increases in base electric rates of approximately $98 million annually. The second filing was a request to recover deferred costs that exceeded amounts being recovered under the current market transition charge and societal benefits charge rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization discussed above. Hearings began in February 2003. The Administrative Law Judge's recommended decision is due in June 2003 and the NJBPU's subsequent decision is due in July 2003. In December 2001, the NJBPU authorized the auctioning of BGS for the period from August 1, 2002 through July 31, 2003 to meet the electricity demands of all customers who have not selected an alternative supplier. The auction results were approved by the NJBPU in February 2002, removing the Company's BGS obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February 2003, the NJBPU approved the BGS auction results for the period beginning August 1, 2003. The auction covered a fixed price bid (applicable to all residential and smaller commercial and industrial customers) and a hourly price bid (applicable to all large industrial customers) process. The Company will sell all self-supplied energy (non-utility generation and owned generation) to the wholesale market with offsets to its deferred energy cost balances. The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," was discontinued in 1999 with respect to the Company's generation operations. The Company subsequently divested substantially all of its generating assets. The SEC issued interpretive guidance regarding asset impairment measurement, concluding that any supplemental regulated cash flows such as a Competitive Transition Charge 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. Net assets included in utility plant relating to operations for which the application of SFAS 71 was discontinued were $44 million as of December 31, 2002. (D) PROPERTY, PLANT AND EQUIPMENT- As a result of the merger, a portion of the Company's property, plant and equipment was adjusted to reflect fair value. The majority of the Company's property, plant and equipment is reflected at original cost since such assets remain subject to rate regulation on a historical cost basis. In addition to its wholly owned facilities, the Company holds a 50% ownership interest in Yards Creek Pumped Storage Facility, and its net book value was approximately $21.3 million as of December 31, 2002. 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 annualized composite rate was approximately 3.5% in 2002, 3.4% in 2001 and 3.3% in 2000. Annual depreciation expense in 2002 included approximately $26.2 million for future decommissioning costs applicable to the Company's ownership in Unit 2 of the Three Mile Island Nuclear Plant (TMI-2), a demonstration nuclear reactor (Saxton Nuclear Experimental Facility) owned by a wholly owned subsidiary of the Company (in conjunction with Met-Ed and Penelec) and decommissioning liabilities for its previously divested nuclear generating units. The Company's share of the future obligation to decommission these units is approximately $132.0 million in current dollars and (using a 4.0% escalation rate) approximately $210.1 million in future dollars. The estimated obligation and the escalation rate were developed based on site specific studies. Decommissioning of the demonstration nuclear reactor is expected to be completed in 2003; payments for decommissioning of the nuclear generating units are expected to begin in 2014, when actual decommissioning work is expected to begin. The Company has recovered approximately $34.0 million for future decommissioning through its electric rates from customers through December 31, 2002. The Company has also recognized an estimated liability of approximately $9.9 million related to decontamination and decommissioning of nuclear enrichment facilities operated by the United States Department of Energy (DOE), as required by the Energy Policy Act of 1992. 19 In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations". The new statement provides accounting standards for retirement obligations associated with tangible long-lived assets, with adoption required by January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded 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 recorded if the cost to settle the retirement obligation differs from the carrying amount. The Company has identified applicable legal obligations as defined under the new standard, principally for nuclear power plant decommissioning. Upon adoption of SFAS 143 in January 2003, asset retirement costs of $98 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $98 million. The asset retirement liability at the date of adoption was $104 million. As of December 31, 2002, the Company had recorded decommissioning liabilities of $130 million. The change in the estimated liabilities resulted from changes in methodology and various assumptions, including changes in the projected dates for decommissioning. Management expects that substantially all of the nuclear decommissioning costs will be recoverable through regulated rates. Therefore, the Company recognized a regulatory liability of $26 million upon adoption of SFAS 143 for the transition amounts related to establishing the asset retirement obligations for nuclear decommissioning. The FASB approved SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all business combinations initiated after June 30, 2001, to be accounted for using purchase accounting. The provisions of the new standard relating to the determination of goodwill and other intangible assets have been applied to the FirstEnergy/GPU merger, which was accounted for as a purchase transaction, and have not materially affected the accounting for this transaction. Under SFAS 142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill is tested for impairment at least on an annual basis - based on the results of the transition analysis and the 2002 annual analysis, no impairment of the Company's goodwill is required. (E) 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 4B). 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, 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: 2002 2001 2000 ---------------------------------------------------------------------------- Valuation assumptions: Expected option term (years). 8.1 8.3 7.6 Expected volatility.......... 23.31% 23.45% 21.77% Expected dividend yield...... 4.36% 5.00% 6.68% Risk-free interest rate...... 4.60% 4.67% 5.28% Fair value per option.......... $6.45 $4.97 $2.86 ---------------------------------------------------------------------------- The effects of applying fair value accounting to the FirstEnergy's stock options would not materially affect the Company's net income. 20 (F) INCOME TAXES- Details of the total provision for income taxes are shown on the Consolidated Statements of Taxes. Deferred income taxes result from timing differences in the recognition of revenues and expenses for tax and accounting purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. The liability method is used to account for deferred income taxes. Deferred income tax liabilities related to tax and accounting basis differences are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Results for the period January 1, 2001 through November 6, 2001 were included in the final consolidated federal income tax return of GPU, and results for the period November 7, 2001 through December 31, 2001 were included in FirstEnergy's 2001 consolidated federal income tax return. The consolidated tax liability is allocated on a "stand-alone" company basis, with the Company recognizing the tax benefit for any tax losses or credits it contributed to the consolidated return. (G) RETIREMENT BENEFITS- Effective December 31, 2001, the Company's defined benefit pension plan was merged into FirstEnergy's defined benefit pension plan. FirstEnergy's trusteed, noncontributory defined benefit pension plan covers almost all of the Company's full-time employees. Upon retirement, employees receive a monthly pension based on length of service and compensation. FirstEnergy uses the projected unit credit method for funding purposes. The assets of the pension plan consist primarily of common stocks, United States government bonds and corporate bonds. Costs for the year 2001 include the former GPU companies' pension and other postretirement benefit costs for the period November 7, 2001 through December 31, 2001. The Company 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 pays insurance premiums to cover a portion of these benefits in excess of set limits; all amounts up to the limits are paid by the Company. 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. The following sets forth the funded status of the plans and amounts recognized on FirstEnergy's Consolidated Balance Sheet as of December 31: 21
Other Pension Benefits Postretirement Benefits ---------------- ----------------------- 2002 2001 2002 2001 ------------------------------------------------------------------------------------------------ (In millions) Change in benefit obligation: Benefit obligation as of January 1........ $3,547.9 $1,506.1 $ 1,581.6 $ 752.0 Service cost.............................. 58.8 34.9 28.5 18.3 Interest cost............................. 249.3 133.3 113.6 64.4 Plan amendments........................... -- 3.6 (121.1) -- Actuarial loss............................ 268.0 123.1 440.4 73.3 Voluntary early retirement program........ -- -- -- 2.3 GPU acquisition........................... (11.8) 1,878.3 110.0 716.9 Benefits paid............................. (245.8) (131.4) (83.0) (45.6) ------------------------------------------------------------------------------------------- Benefit obligation as of December 31...... 3,866.4 3,547.9 2,070.0 1,581.6 ------------------------------------------------------------------------------------------- Change in fair value of plan assets: Fair value of plan assets as of January 1. 3,483.7 1,706.0 535.0 23.0 Actual return on plan assets.............. (348.9) 8.1 (57.1) 12.7 Company contribution...................... -- -- 37.9 43.3 GPU acquisition........................... -- 1,901.0 -- 462.0 Benefits paid............................. (245.8) (131.4) (42.5) (6.0) ------------------------------------------------------------------------------------------- Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0 -------------------------------------------------------------------------------------------- Funded status of plan..................... (977.4) (64.2) (1,596.7) (1,046.6) Unrecognized actuarial loss............... 1,185.8 222.8 751.6 212.8 Unrecognized prior service cost........... 78.5 87.9 (106.8) 17.7 Unrecognized net transition obligation.... -- -- 92.4 101.6 ------------------------------------------------------------------------------------------- Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) =========================================================================================== Consolidated Balance Sheets classifications: Prepaid (accrued) benefit cost............ $(548.6) $ 246.5 $ (859.5) $ (714.5) Intangible asset.......................... 78.5 -- -- -- Accumulated other comprehensive loss...... 757.0 -- -- -- ------------------------------------------------------------------------------------------- Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5) ============================================================================================ Assumptions used as of December 31: Discount rate............................. 6.75% 7.25% 6.75% 7.25% Expected long-term return on plan assets.. 9.00% 10.25% 9.00% 10.25% Rate of compensation increase............. 3.50% 4.00% 3.50% 4.00% Net pension and other postretirement benefit costs for the two years ended December 31, 2002 were computed as follows: Other Pension Benefits Postretirement Benefits -------------------- ----------------------- 2002 2001 2002 2001 -------------------------------------------------------------------------------------------------- (In millions) Service cost........................... $ 58.8 $ 34.9 $ 28.5 $18.3 Interest cost.......................... 249.3 133.3 113.6 64.4 Expected return on plan assets......... (346.1) (204.8) (51.7) (9.9) Amortization of transition obligation (asset).............................. -- (2.1) 9.2 9.2 Amortization of prior service cost..... 9.3 8.8 3.2 3.2 Recognized net actuarial loss (gain)... -- -- 11.2 4.9 Voluntary early retirement program..... -- 6.1 -- 2.3 -------------------------------------------------------------------------------------------------- Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $114.0 $92.4 ==================================================================================================
The composite health care cost trend rate assumption is approximately 10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. An increase in the health care cost trend rate assumption by one percentage point would increase the total service and interest cost components by $20.7 million and the postretirement benefit obligation by $232.2 million. A decrease in the same assumption by one percentage point would decrease the total service and interest cost components by $16.7 million and the postretirement benefit obligation by $204.3 million. A significant portion of the services provided to the Company are from affiliates, GPU Service, Inc. (GPUS) and FirstEnergy Service Company (FECO) (see Note 1H). Therefore, substantially all of the employees are with GPUS which bills the Company for services rendered. See Note 7D for the Company's amount of net pension and other postretirement benefit costs reflected in its Consolidated Statements of Income. 22 (H) TRANSACTIONS WITH AFFILIATED COMPANIES- Operating revenues, operating expenses and other income include transactions with affiliated companies, primarily GPUS and FirstEnergy Solutions (FES). During the three years ended December 31, 2002, GPUS provided legal, accounting, financial and other services to the Company. The Company also entered into sale and purchase transactions with affiliates (Met-Ed and Penelec) during the period. Through the BGS auction process, FES is an alternate supplier of power to the Company. FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to the Company from its affiliates, GPUS and FECO, both subsidiaries of FirstEnergy Corp. and both "mutual service companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act (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: the ratio of each company's amount of FirstEnergy's aggregate direct payroll, number of employees, asset balances, revenues, number of customers and other factors; and specific departmental charge ratios. Management believes that these allocation methods are reasonable. (I) SUPPLEMENTAL CASH FLOWS INFORMATION- All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. All borrowings with initial maturities of less than one year are defined as financial instruments under GAAP and are reported on the Consolidated 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: 2002 2001 ------------------------------------------------------------------------------- Carrying Fair Carrying Fair Value Value Value Value ------------------------------------------------------------------------------- (In millions) Long-term debt..................... $1,374 $ 1,415 $1,246 $1,250 Preferred stock.................... $ 125 $ 127 $ 176 $ 180 Investments other than cash and cash equivalents............. $ 258 $ 258 $ 253 $ 252 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. In 2001, long-term debt and preferred stock subject to mandatory redemption were recognized at fair value in connection with the merger. The fair value of investments other than cash and cash equivalents represents 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 include 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, government bonds and corporate bonds. Unrealized gains and losses applicable to the decommissioning trusts have been recognized in the trust investment with a corresponding change to the decommissioning liability. Realized gains (losses) are recognized as additions (reductions) to trust asset balances. For the year 2002, net realized losses were approximately $0.06 million and interest and dividend income totaled approximately $3.6 million. On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an amendment of FASB Statement No. 133." The adoption resulted in the recognition of derivative assets on the Consolidated Balance Sheet as of January 1, 2001 in the amount of $21.8 million with offsetting amounts, net of tax, recorded in Accumulated Other Comprehensive Income, of $5.1 million, and in Regulatory Assets, of $13 million. The Company is exposed to financial risks resulting from the fluctuation of commodity prices, including electricity and natural gas. To manage the volatility relating to these exposures, the Company uses a variety of non-derivative and derivative instruments, including forward contracts, options and futures contracts. These derivatives are used principally for hedging purposes. The Company has a Risk Policy Committee, comprised of FirstEnergy executive officers, which exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. The Company uses derivatives to hedge the risk of price fluctuations. The Company's primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The majority of the Company's forward commodity contracts are considered "normal purchases and sales," as defined by SFAS 133, and are therefore excluded from the scope of SFAS 138. The forward contracts, options and futures contracts determined to be within the scope of SFAS 133 are accounted for as cash flow hedges and expire on various dates through 2003. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. There is currently a net deferred loss of $0.4 million included in Accumulated Other Comprehensive Loss as of December 31, 2002 related to derivative hedging activity, which will be reclassified to earnings during the next twelve months as hedged transactions occur. (J) REGULATORY ASSETS- The Company recognizes, as regulatory assets, costs which the FERC and NJBPU 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 regulatory plan. The Company continues to bill and collect cost-based rates for its transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Company continues the application of SFAS 71 to those operations. Net regulatory assets on the Consolidated Balance Sheets are comprised of the following: 2002 2001 ----------------------------------------------------------------------------- (In millions) Regulatory transition charge................... $2,801.7 $2,844.7 Societal benefits charge....................... 143.8 166.6 Property losses and unrecovered plant costs.... 87.8 104.1 Customer receivables for future income taxes... 34.5 52.4 Employee postretirement benefit costs.......... 33.2 36.5 Loss on reacquired debt........................ 17.4 19.3 Spent fuel disposal costs...................... 8.8 20.2 Other.......................................... 71.8 81.0 ----------------------------------------------------------------------------- Total....................................... $3,199.0 $3,324.8 ============================================================================= 2. MERGER: On November 7, 2001, the merger of FirstEnergy and GPU became effective pursuant to the Agreement and Plan of Merger, dated August 8, 2000. As a result of the merger, GPU's former wholly owned subsidiaries, including the Company, became wholly owned subsidiaries of FirstEnergy. The merger was accounted for by the purchase method of accounting. The assets acquired and liabilities assumed were recorded at estimated fair values as determined by FirstEnergy's management based on information currently available and on current assumptions as to future operations. Merger purchase accounting adjustments recorded in the records of the Company primarily consist of: (1) revaluation of certain property, plant and equipment; (2) adjusting preferred stock subject to mandatory redemption and long-term debt to estimated fair value; (3) recognizing additional obligations related to retirement benefits; and (4) recognizing estimated severance and other compensation liabilities. Other assets and liabilities were not adjusted since they remain subject to rate regulation on a historical cost basis. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. During 2002, certain pre-acquisition contingencies and other final adjustments to the fair values of the assets acquired and liabilities assumed were reflected in the final allocation of the purchase price. These adjustments primarily related to: (1) final actuarial calculations related to pension and postretirement benefit obligations and (2) return to accrual adjustments for income taxes. As a result of these adjustments, goodwill increased by approximately $74.3 million. As of December 31, 2002, the Company had recorded goodwill of approximately $2.0 billion related to the merger. 24 3. LEASES: Consistent with regulatory treatment, the rentals for capital and operating leases are charged to operating expenses on the Consolidated Statements of Income. Prior to the sale of its nuclear generating facilities (completed in 2000), the Company's capital lease obligations related primarily to nuclear fuel lease agreements with nonaffiliated fuel trusts for the plants. In 2000, total rentals related to these capital leases were $13.0 million, comprised of an interest element of $1.5 million and other costs of $11.5 million. The Company's most significant operating lease relates to the sale and leaseback of a portion of its ownership interest in the Merrill Creek Reservoir project. The interest element related to this lease was $1.2 million, $1.2 million and $0.4 million for the years 2002, 2001 and 2000, respectively. As of December 31, 2002, the future minimum lease payments on the Company's Merrill Creek operating lease, net of reimbursements from sublessees, are: $3.2 million, $1.2 million, $1.7 million, $1.6 million and $1.6 million for the years 2003 through 2007, respectively, and $56.7 million for the years thereafter. The Company is recovering its Merrill Creek lease payments, net of reimbursements, through its distribution rates. 4. CAPITALIZATION: (A) RETAINED EARNINGS- The merger purchase accounting adjustments included resetting the retained earnings balance to zero as of the November 7, 2001 merger date. In general, the Company's first mortgage bond (FMB) indentures restrict the payment of dividends or distributions on or with respect to the Company's common stock to amounts credited to earned surplus since approximately the date of its indenture. At such date, the Company had a balance of $1.7 million in its earned surplus account, which would not be available for dividends or other distributions. As of December 31, 2002, the Company had retained earnings available to pay common stock dividends of $90.3 million, net of amounts restricted under the Company's FMB indentures. (B) STOCK COMPENSATION PLANS- In 2001, FirstEnergy assumed responsibility for two new stock-based plans as a result of its acquisition of GPU. No further stock-based compensation can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both Plans have been converted into FirstEnergy options and restricted stock. Options under the GPU Plan became fully vested on November 7, 2001, and will expire on or before June 1, 2010. Under the MYR Plan, all options and restricted stock maintained their original vesting periods, which range from one to four years, and will expire on or before December 17, 2006. Additional stock based plans administered by FirstEnergy include the Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director Incentive Compensation Plan (FE Plan). All options are fully vested under the CE Plan, and no further awards are permitted. Outstanding options will expire on or before February 25, 2007. 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. Collectively, the above plans are referred to as the FE Programs. Restricted common stock grants under the FE Programs were as follows: 2002 2001 2000 ------------------------------------------------------------------------------ Restricted common shares granted......... 36,922 133,162 208,400 Weighted average market price ........... $36.04 $35.68 $26.63 Weighted average vesting period (years).. 3.2 3.7 3.8 Dividends restricted..................... Yes * Yes ---------------------------------------------------------------------------- * 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, 2002, there were 296,008 stock units outstanding. 25 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, 2000............... 2,153,369 $25.32 (159,755 options exercisable).......... 24.87 Options granted...................... 3,011,584 23.24 Options exercised.................... 90,491 26.00 Options forfeited.................... 52,600 22.20 Balance, December 31, 2000............ 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 As of December 31, 2002, the weighted average remaining contractual life of outstanding stock options was 7.6 years. 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 1E - Stock-Based Compensation. (C) PREFERRED AND PREFERENCE STOCK- Preferred stock may be redeemed by the Company, in whole or in part, with 30-90 days' notice. (D) COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF LIMITED PARTNERSHIP HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES- JCP&L Capital, L.P. is a special-purpose limited partnership in which a subsidiary of the Company is the sole general partner. The limited partnership invested the gross proceeds from the sale of $125.0 million at 8.56% of monthly income preferred securities (MIPS) in $128.9 million of the Company's 8.56% subordinated debentures. The sole assets of the limited partnership are these subordinated debentures, which have the same rate and maturity date as the preferred securities. The Company has effectively provided a full and unconditional guarantee of its obligations under its limited partnership's MIPS, to the extent that there is sufficient cash on hand to permit such payments and funds legally available therefor, and payments on liquidation or redemption with respect to the MIPS. Distributions on the limited partnership's MIPS (and interest on the subordinated debentures) may be deferred for up to 60 months, but the Company may not pay dividends on, or redeem or acquire, any of its cumulative preferred or common stock until deferred payments on its subordinated debentures are paid in full. The limited partnership's MIPS, which mature in 2044 and have a liquidation value of $25.00 per security, are redeemable at the option of the Company at 100% of their principal amount. 26 (E) LONG-TERM DEBT- The Company's first mortgage bond indenture, which secures all of the Company's FMBs, serve as a direct first mortgage lien on substantially all of the Company's property and franchises, other than specifically excepted property. The Company has various debt covenants under its financing arrangements. The most restrictive of these relate to the nonpayment of interest and/or principal on debt, which could trigger a default. Cross-default provisions also exist between FirstEnergy and the Company. Based on the amount of bonds authenticated by the Trustee through December 31, 2002 the Company's annual improvement fund requirements for all bonds issued under the mortgage amount to $15.7 million. The Company expects to fulfill its improvement fund obligation by providing refundable bonds to the Trustee. Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases) for the next five years are: (In millions) ------------------------ 2003........ $173.8 2004........ 175.9 2005........ 66.9 2006........ 230.6 2007........ 36.7 ------------------------- (F) SECURITIZED TRANSITION BONDS- On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited liability company of the Company, sold $320 million of transition bonds to securitize the recovery of the Company's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. The Company does not own nor did it purchase any of the transition bonds, which are included in long-term debt on and the Company's Consolidated Balance Sheet. The transition bonds represent obligations only of the Issuer and are collateralized solely by the equity and assets of the Issuer, which consist primarily of bondable transition property. The bondable transition property is solely the property of the Issuer. Bondable transition property represents the irrevocable right of a utility company to charge, collect and receive from its customers, through a non-bypassable transition bond charge, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. The Company, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the transition bond charge, pursuant to a servicing agreement with the Issuer. The Company is entitled to a quarterly servicing fee of $100,000 that is payable from transition bond charge collections. (G) 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 Company's parent. As of December 31, 2002, accumulated other comprehensive loss consisted of unrealized losses on derivative instrument hedges of $0.9 million. 5. SHORT-TERM BORROWINGS: The Company may borrow from its affiliates on a short-term basis. As of December 31, 2002, the Company had no short-term borrowings outstanding. 6. COMMITMENTS, GUARANTEES AND CONTINGENCIES: (A) CAPITAL EXPENDITURES- The Company's current forecast reflects expenditures of approximately $462 million for property additions and improvements from 2003 through 2007, of which approximately $102 million is applicable to 2003. (B) NUCLEAR INSURANCE- The Price-Anderson Act limits the public liability relative to a single incident at a nuclear power plant to $9.5 billion. The amount is covered by a combination of private insurance and an industry retrospective rating plan. Based on 27 its present ownership interest in TMI-2, the Company is exempt from any potential assessment under the industry retrospective rating plan. The Company is also insured as to its interest in TMI-2 under a policy issued to the operating company for the plant. Under this policy, $150 million is provided for property damage and decontamination and decommissioning costs. Under this policy, the Company can be assessed a maximum of approximately $0.2 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 property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at TMI-2 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- The Company has been named as a "potentially responsible party" (PRP) at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, potential environmental liabilities have been recognized on the Consolidated Balance Sheet as of December 31, 2002, based on estimates of the total costs of cleanup, the Company's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, the Company has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered through a non-bypassable societal benefits charge. The Company has total accrued liabilities aggregating approximately $47.1 million as of December 31, 2002. The Company does not believe environmental remediation costs will have a material adverse effect on its financial condition, cash flows or results of operations. (D) OTHER LEGAL PROCEEDINGS- Various lawsuits, claims and proceedings related to the Company's normal business operations are pending against the Company, the most significant of which are described below. The Company has a 25% ownership interest in TMI-2, which was damaged during a 1979 accident. As a result of the accident, claims for alleged personal injury were filed against the Company, Met-Ed, Penelec and GPU (the defendants) in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the District Court granted a motion for summary judgment filed by the defendants and dismissed the ten initial "test cases" which had been selected for a test case trial. In January 2002, the District Court granted the defendants' July 2001 motion for summary judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs filed a notice of appeal to the United States Court of Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to hear the appeal, which effectively ended further legal action for those claims. In July 1999, the Mid-Atlantic states experienced a severe heat storm which resulted in power outages throughout the service territories of many electric utilities, including the service territory of the Company. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four New Jersey electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, the Company provided unsafe, inadequate or improper service to its customers. In July 1999, two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court against the Company and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the Company's service territory. In May 2001, the court denied without prejudice the Company's motion seeking decertification of the class. Discovery continues in the class action, but no trial date has been set. In October 2001, the court held argument on the plaintiffs' motion for partial summary judgment, which contends that the Company is bound to several findings of the NJBPU investigation. The plaintiffs' motion was denied by the Court in November 2001 and the plaintiffs' motion to file an appeal of this decision was denied by the New Jersey Appellate Division. The Company has also filed a motion for partial summary judgment that is currently pending before the Superior Court. The Company is unable to predict the outcome of these matters. 28 7. OTHER INFORMATION: The following represents the financial data which includes supplemental unaudited prior years' information as compared to consolidated financial statements and notes previously reported in 2001 and 2000. (A) CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2002 ---- ---- ---- ---- Other Cash Flows from Operating Activities: Accrued taxes............................. $(21,939) $ 2,675 | $24,272 $ 4,242 Accrued interest.......................... 1,625 9,501 | (7,590) 898 Retail rate refunds obligation payments... (43,016) -- | -- -- Prepayments and other..................... (21,149) 16,436 | 63,909 (73,916) All other................................. 66,837 (8,049) | (14,263) (161,324) -------- -------- | ------- --------- Other cash used for operating activities $(17,642) $20,563 | $66,328 $(230,100) ======== ======= | ======= =========
(B) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS The Company records purchase and sales transactions with PJM Interconnection ISO, an independent system operator, on a gross basis in accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The aggregate purchase and sales transactions for the three years ended December 31, 2002, are summarized as follows: Nov. 7-Dec. 31, Jan. 1-Nov. 6, 2002 2001 2001 2000 ------------------------------------------------------- (In millions) Sales..... $136 $ 2 | $ 28 $87 Purchases. 101 16 | 188 66 -------------------------------|----------------------- The Company's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from the PJM ISO from power sales (as reflected in the table above) during periods when the Company had additional available power capacity. Revenues also include sales by the Company of power sourced from the PJM ISO (reflected as purchases in the table above) during periods when the Company required additional power to meet its retail load requirements. (C) TRANSACTIONS WITH AFFILIATED COMPANIES- The primary affiliated companies transactions are as follows: Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 ------------------------------------------------------------------------------ (In millions) Operating Revenues: Wholesale sales-affiliated companies... $ 17.6 $ 2.4 | $17.3 $ 3.0 | Operating Expenses: | GPU Service, Inc. support services..... 140.4 21.0 | 120.0 259.0 Power purchased from other affiliates.. 26.1 3.4 | 16.1 48.1 Power purchased from FES............... 17.9 7.5 | -- -- ----------------------------------------------------------------------------- (D) RETIREMENTS BENEFITS (1) Net pension and other postretirement benefit costs (income) for the three years ended December 31, 2002 are approximately as follows: Nov. 7- Jan. 1- Dec. 31, Nov. 6, 2002 2001 2001 2000 ------------------------------------------------------------------------------ (In millions) Pension Benefits....................... $(19.6) $(6.7) | $(33.4) $(10.6) Other Postretirement Benefits.......... 5.3 1.7 | 8.3 14.9 ------------------------------------------------------------------------------ (1) Includes estimated portion of benefit costs included in billings from GPUS. 29 8 . RECENTLY ISSUED ACCOUNTING STANDARDS: FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34" The FASB issued FIN 45 in January 2003. This interpretation identifies minimum guarantee disclosures required for annual periods ending after December 15, 2002. It also clarifies that providers of guarantees must record the fair value of those guarantees at their inception. This accounting guidance is applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Company does not believe that implementation of FIN 45 will be material but it will continue to evaluate anticipated guarantees. FIN 46, "Consolidation of Variable Interest Entities - an interpretation of ARB 51" In January 2003, the FASB issued this interpretation of ARB No. 51, "Consolidated Financial Statements". The new interpretation provides guidance on consolidation of variable interest entities (VIEs), generally defined as certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. This interpretation requires an enterprise to disclose the nature of its involvement with a VIE if the enterprise has a significant variable interest in the VIE and to consolidate a VIE if the enterprise is the primary beneficiary. VIEs created after January 31, 2003 are immediately subject to the provisions of FIN 46. VIEs created before February 1, 2003 are subject to this interpretation's provisions in the first interim or annual reporting period beginning after June 15, 2003 (our third quarter of 2003). The FASB also identified transitional disclosure provisions for all financial statements issued after January 31, 2003. The Company currently has transactions with entities in connection with the sale of preferred securities, which may fall within the scope of this interpretation, and which are reasonably possible of meeting the definition of a VIE in accordance with FIN 46. The Company currently consolidates these entities and believes it will continue to consolidate following the adoption of FIN 46. 9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED): The following summarizes certain consolidated operating results by quarter for 2002 and 2001.
March 31, June 30, September 30, December 31, Three Months Ended 2002 2002 2002 2002 ------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.......................... $450.7 $501.3 $779.9 $596.5 Operating Expenses and Taxes................ 389.4 423.1 658.6 522.1 ------------------------------------------------------------------------------------------------------------- Operating Income............................ 61.3 78.2 121.3 74.4 Other Income ............................... 2.8 2.2 1.2 1.5 Net Interest Charges........................ 24.1 23.0 21.8 22.1 ------------------------------------------------------------------------------------------------------------- Net Income.................................. $ 40.0 $ 57.4 $100.7 $ 53.8 ============================================================================================================= Earnings on Common Stock.................... $ 39.2 $ 57.0 $103.5 $ 53.7 ============================================================================================================= Three Months Ended ------------------------------------ March 31, June 30, Sept. 30, Oct. 1-Nov. 6, Nov. 7-Dec. 31, 2001 2001 2001 2001 2001 ---------------------------------------------------------------------------------------------------------------------- (In millions) Operating Revenues.......................... $461.7 $521.0 $672.2 $ 183.7 | $282.9 Operating Expenses and Taxes................ 388.2 451.7 554.0 151.9 | 239.2 -------------------------------------------------------------------------------------------------------|-------------- Operating Income............................ 73.5 69.3 118.2 31.8 | 43.7 Other Income (Expense)...................... 1.2 2.3 (2.7) (177.7) | 1.2 Net Interest Charges........................ 23.3 25.6 24.3 8.3 | 14.8 -------------------------------------------------------------------------------------------------------|-------------- Net Income (Loss)........................... $ 51.4 $ 46.0 $ 91.2 $(154.2) | $ 30.1 =======================================================================================================|============== Earnings (Loss) on Common Stock............. $ 50.0 $ 44.7 $ 89.8 $(154.5) | $ 29.3 ====================================================================================================================== 30
Report of Independent Accountants To the Stockholders and Board of Directors of Jersey Central Power & Light Company: In our opinion, the accompanying consolidated balance sheet and consolidated statement of capitalization and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes present fairly, in all material respects, the financial position of Jersey Central Power & Light Company (a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended and the year ended December 31, 2000 (pre-merger) 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 audit. 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 consolidated financial statements of Jersey Central Power & Light Company and subsidiaries as of December 31, 2001 and for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger) were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financials statements in their report dated March 18, 2002. PricewaterhouseCoopers LLP Cleveland, Ohio February 28, 2003 31 The following report is a copy of a report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP. Report of Previous Independent Public Accountants To the Stockholders and Board of Directors of Jersey Central Power & Light Company: We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Jersey Central Power & Light Company (a New Jersey corporation and wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December 31, 2001 (post-merger), and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger). 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 audit. The financial statements of Jersey Central Power & Light Company and subsidiary as of December 31, 2000 and for each of the two years in the period ended December 31, 2000 (pre-merger), were audited by other auditors whose report dated January 31, 2001, expressed an unqualified opinion on those statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the 2001 financial statements referred to above present fairly, in all material respects, the financial position of Jersey Central Power & Light Company and subsidiaries as of December 31, 2001 (post-merger), and the results of their operations and their cash flows for the period from January 1, 2001 to November 6, 2001 (pre-merger) and the period from November 7, 2001 to December 31, 2001 (post-merger), in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 2002. 32